CalReg CPUC Docket Monitor

The CEC plan runs nine initiatives led by $143.9 million for DER and load flexibility, $126.1 million for building and community-scale decarbonization, $109.155 million for transportation electrification, $105.4 million for industrial decarbonization and $89.2 million for connecting clean resources and new loads, plus $131.85 million for administration. PG&E proposes six initiatives and 14 research topics, weighted toward advanced planning and operating capabilities and community resilience; its $8.342 million inflation request is about half what its CPI-W calculation would permit. SCE proposes 17 topics around grid efficiency and flexibility, digital grid planning, field sensing and advanced field operations — grid-enhancing technologies, DC networks, next-generation conductors, digital substations, drones, robotics and asset sensors. SDG&E proposes seven topics across four initiatives, including evaluation of sodium-ion batteries as a lithium-ion alternative.

The filings push EPIC toward near-term operating problems: interconnection, load growth, DER orchestration, flexible demand, wildfire resilience and advanced sensing. They differ mainly on funding posture. SCE also seeks Tier 3 advice-letter authority to add future research topics; SDG&E asks that all IOUs receive that flexibility.

In 2017 Pacific asked the CPUC to idle the Line 63 trunkline across the Tehachapis and route those shipments over a shared Line 2000 segment. The Commission approved the change after Pacific said Line 63 shippers would not be adversely affected. CRC now argues that the resulting configuration leaves Line 63 shippers bearing the capacity risk whenever the shared route is constrained, violating the Line 63 tariff and the Public Utilities Code by giving Line 2000 shippers preferential treatment. Pacific rejected the claim in June as without merit.

The dispute places the CPUC in the middle of a significant constraint between Kern County production and Los Angeles refineries. It also arrives as CRC expands its own midstream footprint: CRC closed a $63 million acquisition of Crimson Midstream on September 1, adding approximately 2,000 miles of pipeline. The proceedings are separate, but the Line 63 dispute illustrates the transportation exposure CRC is seeking to reduce as it gains control over infrastructure connecting California crude production to downstream markets.

On the O&M side, high-pressure-system spending ran $38.4 million above the imputed level while medium-pressure was $45.8 million below; cybersecurity and physical security were 60% and 128% above imputed levels respectively, though both are small in absolute dollars. The largest capital overruns were storage-system work ($65 million) and medium-pressure-system work ($46.6 million); employee-safety capital ran 139% above imputed.

The report also carries SoCalGas’s 20 applicable CPUC safety metrics for 2025: 2.01 third-party dig-ins per 1,000 USA tickets, average emergency response of 23.38 minutes (19-minute median), 100% of scheduled storage baseline inspections completed, and 2,344 miles (about 70%) of transmission pipeline capable of internal inspection. SoCalGas reported nine serious public injuries and no fatalities, no missed in-line inspections, no overdue gas-operation corrective-action work orders, and one distribution and one transmission overpressure event.

The comparison has an important limitation: the 2024 GRC did not separately identify RAMP funding, so SoCalGas had to impute authorized amounts for some mitigation activities, and its accounting systems do not track costs by individual RAMP risk. The figures are a directional comparison, not a clean authorized-versus-recorded test.

The ECAC provides dollar-for-dollar recovery of net power costs and fuel-stock carrying charges, reconciled annually each August; last year’s counterpart was a $1.7 million (1.0%) increase. Class impacts: residential −$13.8 million (−15.5%), commercial/industrial −$10.1 million (−16.9%), irrigation −$3.2 million (−16.7%), lighting −$47,000 (−6.0%). Beyond the rate components, the application discontinues allocations to the SOMAH program after June 2026 and refunds unused 2025–2026 SOMAH set-asides through the 2027 Climate Credit, consistent with R.25-01-005, and begins State Transmission Accelerator Fund set-asides (deposits from July 1, 2026) in compliance with D.26-04-036. Summary of earnings for the 12 months ended December 31, 2025: California operating revenue $153.6 million, rate base $611.6 million, return on rate base 5.35%. Proposed schedule: prehearing conference September 24, scoping memo October 22, proposed decision November 24, final decision December 18, 2026, rates effective January 1, 2027; PacifiCorp states hearings should not be needed, and no protests were on file as of August 13.

The 2028 Summer Olympic and Paralympic Games are hosted in Los Angeles, within SoCalGas’s service territory. Establishing the memorandum account now lets the utility track incremental Games-related costs for potential future recovery, subject to a later reasonableness review. No dollar amount is requested in this application.

PG&E reports actual gas costs of $2.086 billion against a benchmark of $2.283 billion (91.4% of benchmark, or $196.8 million in savings). Of that, $177.1 million fell below the tolerance band and is subject to sharing. Customers keep $170.2 million. The shareholder award, capped at 1.5% of annual gas commodity costs, comes to $26.6 million; without the cap it would have been $35.4 million. PG&E used no physical hedges during the year and took no award for Year 29.

The rate impact is estimated at $0.01307 per therm.

Procedural context: The award year overlaps with the winter 2022-23 gas-price spike that produced the new application-format process. D.26-02-028 previously concluded that the gas utilities did not cause the spike. Under the CPIM formula, customers retain $170 million of the identified savings; the 1.5% cap reduced the uncapped $35.4 million award to $26.6 million. Two open procedural questions for the Commission: (1) whether Cal Advocates conducts the same scope of review under the application format as under the prior advice-letter process, and (2) how the benchmark methodology and its performance during a period of extreme market volatility should be evaluated.

Recovery would run through a new Gas Line Extension Allowance Balancing Account after each project's three-year true-up period. The lifetime revenue requirement across the seven projects is estimated at $11.9 million, with a peak-year 2032 requirement of $722,000. The residential bill impact at peak is approximately 0.04 cents per month. SoCalGas is also proposing an updated allowance multiplier of 3.6, up from 3.1 in the prior filing.

Procedural context: Rate impacts under this filing are limited (approximately 0.04 cents per month at peak). D.22-09-026 ended gas-line extension subsidies to advance building decarbonization but retained an exception process for projects demonstrating GHG benefits without a feasible electrification pathway. The seven July 1 projects are principally RNG. Party review of the “no feasible electrification path” demonstration - particularly for the beverage-manufacturer project - will inform how the exception standard is applied in subsequent filings.

PG&E estimates the project would reduce GHG emissions by 14,200 metric tons of CO₂e annually. The application includes an explicit disclaimer that PG&E does not independently verify SFPUC’s technical, engineering, or financial claims.

Procedural context: PG&E received 17 subsidy requests under the D.22-09-026 exception process and advanced one. The screening criteria PG&E applied to distinguish the SFPUC project from the 16 non-advanced projects have not been placed on the record. Party discovery could develop those criteria for future application of the “no feasible electrification path” standard.

The $1.15B debt authorization covers up to five years of financing needs: new debt for capital investment, refinancing of maturing short-term paper, and interest rate hedging instruments including swaps and caps. Southwest Gas has been active in Northern California and Nevada rate cases; the financing authority is the enabling instrument for its 2027-2030 rate-base growth. Commission approval is routine at this scale absent evidence of adverse financial condition or misuse of prior authorizations.

The Moraga-Oakland X 115 kV corridor connects the Orinda substation to Oakland X substation across ~5 miles. Load flow studies identified summer-peak thermal violations on the existing conductor as of 2026, driven by East Bay load growth (residential electrification + commercial data center anchor tenants). The rebuild replaces existing conductor and structures with higher-capacity conductor and, where feasible, retrofits existing rights-of-way to avoid new corridor acquisition. The $276.8 million cost is embedded in PG&E's Test Year 2027 GRC (A.25-05-009) transmission capital forecast. Adoption at July 2 clears the CEQA and PTC gate; construction 2027 and in-service 2029 align the project with East Bay Rule 30 large-load studies now in progress.

This is one of four SoCalGas applications pending outside its TY 2028 General Rate Case, alongside the SAP migration, the gas-line extension allowance request, and the Olympics memorandum account. Unlike the other three filings, the GCIM application returns money to customers rather than seeking new recovery. It is distinct from PG&E’s CPIM Year 30 shareholder-award filing, which uses a comparable incentive structure on the PG&E system.

The agreement makes two changes to the expiring arrangement. It doubles the power MID may sell Contra Costa Water District from 8 MW to 16 MW, covering existing intake and pumping sites, a new pumping plant, and fleet electrification. It also updates language to reflect Mountain House’s incorporation as a city. The Legislature established the underlying territory division in 2000 after years of litigation and Commission proceedings between the two utilities, so the filing’s principal effect is to forestall renewed disputes over service boundaries for another quarter century.

The $5.104 billion request is about 10.5% above SoCalGas’s expected 2027 collections, roughly 20.5% above the amount first authorized for 2027, and about 34% above the 2024 test year (a roughly $1.3 billion four-year increase). The July 20 protests focus on gas-transition risk and cost recovery: intervenors including SCGC, the Indicated Shippers, TURN, and Cal Advocates challenge O&M and attrition forecasts, sub-1.0 benefit-cost pipe programs such as the $1.25 billion DREAMS effort, the proposed earnings-sharing mechanism, and RAMP and AB 2666 forecast-versus-actual compliance. Cal Advocates asks to consolidate the utilities’ advanced-metering, Smart Meter 2.0, and $348.1 million SAP dockets into the case.

The $3.8 billion combined electric and gas request is about 8.1% above the 2027 authorized baseline and roughly 41% above the 2024 test year. The July 20 protests concentrate on wildfire and capital spending: Protect Our Communities Foundation and Mussey Grade Road Alliance challenge the $1.19 billion grid-hardening program, the $232 million undergrounding exception, and SDG&E’s wildfire risk-scaling; the CCAs (San Diego Community Power and Clean Energy Alliance) contest generation-versus-distribution cost allocation; and CEJA and the Climate Action Campaign question long-lived gas investment as demand falls. Cal Advocates seeks to consolidate the metering and SAP dockets into the case.

D.25-08-032 closed Phases IV and V of the post-2018 Safety Policy Division OIR, replaced the RMAR with a consolidated set of adopted requirements, and made the required test for RAMP Four Optimized Enterprise Portfolios at 85, 90, 95, and 100 percent of the Baseline Cost Forecast, constructed using a prescribed binary or mixed-integer optimization (objective = risk reduction; constraint = budget in dollars; decision variable = include mitigation y/n).

Threshold compliance concerns under review include: (1) whether the optimization is a true constrained binary program or a greedy BCR-sort heuristic with cumulative-spend column; (2) whether the Baseline Cost Forecast is drawn from the current RAMP/GRC rather than the prior GRC (Conclusion of Law 12); (3) whether mutually exclusive mitigations (CC, VM, CC+VM) are bounded against additive alternatives (Row 25.2); (4) whether Overall Residual Risk shows a longitudinal trajectory across the 2018, 2021, and 2026 cycles (Modified Row 9); (5) whether RRU datasets ranked by BCR have cell-level formulas linked to a permanently accessible source sheet (Modified Row 26; D.24-05-064 auditability standard); (6) whether 2026-2028 tranche-level spending is disclosed at all chapters (not just 2029-2032); (7) whether the WIM-Climate disclosure documents GCM ensemble, SSP pathway, and downscaling method at the circuit-segment level. Reply window opens after the Jun 29 protests close.

Cal Advocates says the External Outage Report identifies no Emergency Flow Orders over the past decade and only one curtailment affecting noncore electric-generation customers; SoCalGas managed every listed external weather event without gas-customer impacts while Aliso operated at or below its current maximum allowable reservoir pressure. On the internal side, Cal Advocates says SoCalGas describes pipeline incidents, curtailments in the San Joaquin Valley, North Coastal System, and San Diego County, and other constraints, but never claims or shows that additional Aliso inventory was necessary to address them, or that the preferred 86.2 Bcf level would have prevented them. Sierra Club echoes the framing. The proceeding sits within the CPUC’s consideration of Aliso Canyon under the 2025 Biennial Assessment; the outcome will inform the Commission’s next capacity determination and prior inventory cap treatment.

Once the embedded-cost framework is agreed, the dispute shifts to allocators, where the intervenors fracture. Indicated Shippers' witness Brian Collins argues peak-day demand sizes the system; ratepayer-advocate intervenor witness Mike Florio argues that with load declining and spending now safety- and reliability-driven, annual throughput is the true cost driver - a package that shifts roughly $67 million onto retail noncore customers. Clean Energy opposes the throughput allocator, citing an approximate $17 million (30%) hit to the natural-gas-vehicle class tied to transit agencies facing about $1.3 billion in budget cuts. Two issues unite intervenors against the utilities: the backbone-to-local-transmission reallocation (~$116.4 million) and the FASRMA storage-account treatment, where the factual record has developed unevenly relative to the applicants’ positions. For a gas-only utility with a contracting customer base, cost-based allocation carries different implications than for a combined electric-gas utility.

Public Utilities Code §851 acquisitions are typically reviewed for (a) consistency with public interest, (b) absence of harm to ratepayers, and (c) reasonable terms. The scoping memo identifies what issues will be litigated and on what schedule. From a ratepayer protection perspective, two questions warrant scrutiny. First, the price paid for Chevron’s 1/7 stake and the 20-year stock purchase: if the purchase price reflects pre-2022 valuations or excludes the discounting that should apply to long-life gas-transmission assets during the gas-transition era, ratepayers will bear an inflated rate-base addition for decades. Second, the transportation agreements preserving Chevron’s system access: if Chevron receives below-cost transportation as part of the deal, the difference is a cross-subsidy from PG&E ratepayers to Chevron. A §851 challenge or conditioned approval is most effective at the scoping-memo stage, when the issues for hearing are set. Given the long-life nature of the asset and California’s 2045 gas-transition deadlines, an asset useful life shorter than the standard depreciation schedule should also be requested.

RAMP filings are required under D.18-12-014 and are the foundational input to a utility’s forward GRC capital plan. SCE’s 2026 RAMP frames the risk-spend efficiency and capital prioritization for SCE’s TY 2029 GRC. The proceeding sits in parallel with the new Risk-Based Decision-Making OIR (R.26-04-016) opened at the April 30 voting meeting.

The 10 RAMP risks: (1) Wildfire and Public Safety Power Shutoffs; (2) Overhead Equipment Failure; (3) Underground Equipment Failure; (4) Seismic; (5) Public Safety Risk Not Attributable to Asset Failure; (6) Major Physical Security Incident; (7) Cyber Attack; (8) Hydro Dam Safety; (9) Employee Safety; (10) Contractor Safety. The January 2025 Southern California fires dominate SCE’s case for planning around tail-risk events beyond historical experience. SCE developed an enhanced Wildfire Integrated Model and a climate-informed variant using data underlying the forthcoming California Fifth Climate Change Assessment, which has not yet been released.

BCR screen as the contested design choice. Grid hardening runs through a Benefit-Cost Ratio screen at the circuit level. SCE selects either covered conductor or targeted undergrounding based on whichever yields the higher BCR, provided at least one exceeds 1.0. Where neither clears that threshold, no proactive hardening is proposed; vegetation management, inspections, and PSPS continue, but no grid investment moves forward. SCE characterizes the BCR as one input among feasibility, operational, and execution constraints. Intervenors are likely to argue that communities on sub-1.0 circuits are being left without physical protection because of a cost screen, not because the risk is low - a challenge that could force SCE to revisit its 2029 hardening scope before GRC filing.

REFCLs. Rapid Earth Fault Current Limiters - substation-based protection devices that suppress ground-fault current when an energized conductor contacts the ground - are prioritized separately at circuits where covered conductor hardening is already prevalent. Covered conductor raises wind-speed thresholds but does not remove shutoff risk above those thresholds.

Forward-looking risk modeling. By incorporating climate projections rather than historical fire data into the risk calculations that drive mitigation prioritization, SCE creates a methodology that has not yet been evaluated by CPUC safety staff. A successful challenge to the underlying assumptions would not just affect the climate modeling - it would shift the risk scores, and with them the hardening investments SCE plans to ask ratepayers to fund in 2029.

ERRA is the annual reconciliation of forecast vs. actual energy procurement costs for bundled customers. PG&E’s 2027 forecast reflects exposure to wholesale energy markets, GHG allowance prices, and Resource Adequacy procurement obligations. The +5.7% bundled-rate projection follows multi-year affordability pressure on residential bills.

SDG&E’s parallel A.26-05-009 2027 ERRA Forecast seeks approval of an $893 million procurement-related revenue requirement, a 1.5% increase from currently effective levels, with new rates effective January 1, 2027. Inside the SDG&E filing: the ERRA revenue requirement falls 3.3% to $379.3M with a projected $45M overcollection, but the Portfolio Allocation Balancing Account rises 71% to $301.4M, partially offset by a prior-year balance reduction. Bundled customers see an approximate 1.2% rate decline aided by California Climate Credit returns; a typical 400 kWh residential customer sees no bill movement. Unbundled customers face a 1.4% increase in delivery-plus-PCIA charges. SDG&E forecasts $181.4M in GHG allowance revenues, with $137.8M returned via California Climate Credits and $2.8M to EITE customers. The filing also picks up the new Transmission Accelerator Revolving Fund obligation: 5% of qualifying GHG auction revenues remitted to the state beginning July 1, 2026. SCE’s A.26-05-006 shows procurement costs falling versus 2026, yet bundled customer bills are projected to edge higher due to fixed-cost amortization.

PTC applications under GO 131-D authorize construction of transmission facilities below the CPCN threshold (200 kV) but require Commission review of need, alternatives, and environmental impact. The Suncrest Loop-In supports east-San Diego County reliability and integration of large-scale solar and battery generation in the Boulevard and Jacumba corridors. Environmental review will run in parallel with the application; CEQA timing typically drives the schedule.

The bill-flat framing reflects PG&E’s exposure to affordability pressure following multi-year rate increases driven by wildfire and capital programs. The 2027-2030 base revenue requirement embeds the Risk Assessment Mitigation Phase outcomes from A.24-05-008 and frames the capital trajectory that will be revisited under the new Risk-Based Decision-Making OIR (R.26-04-016). Consumer advocates, the Public Advocates Office, and other intervenors are active in evidentiary hearings.

The Energy Resource Recovery Account (ERRA) is a tracking mechanism that allows IOUs to recover the difference between actual energy procurement costs and the forecast amount built into rates. Each year, utilities file a compliance application documenting whether procurement was reasonable and consistent with the Commission-approved plan.
SCE's 2025 compliance filing covers electricity procurement for its 15 million customers across Southern and Central California. The $11.531 million net undercollection - relatively modest by ERRA standards - reflects the gap between 2025 actual costs and the forecast embedded in rates. If approved, the undercollection is recovered through a future rate adjustment. CPUC staff and intervenors may challenge the reasonableness of specific procurement decisions before a decision is issued.

California IOUs file coordinated Energy Efficiency Business Plans covering strategic direction and a Portfolio Plan specifying programs, budgets, and customer targets. The CPUC approves both through an application proceeding, then each utility implements programs funded by the Energy Efficiency Program Charge on customer bills. The 2028–2031 cycle is the next multi-year authorization following the current 2025–2027 plans.
SCE's application covers electric EE programs across its 15 million customer accounts in Southern and Central California. Typical annual EE budgets for SCE run approximately $400–$500 million per year, with programs targeting residential retrofits, commercial lighting, HVAC efficiency, and industrial process improvements. The Commission will hold workshops and formal hearings before issuing a decision, likely in 2027.

SDG&E's combined Business Plan and Portfolio Plan cover electric and natural gas efficiency programs for its San Diego and southern Orange County service territory - approximately 3.6 million customer accounts. The filing coordinates with SoCalGas which serves overlapping gas customers in the same region.
EE spending is funded through customer surcharges and is subject to CPUC oversight via annual compliance filings. SDG&E's annual EE budget has historically ranged from $80–$120 million. The Commission will evaluate cost-effectiveness using Total Resource Cost (TRC) and Program Administrator Cost (PAC) tests before approving program portfolios.

PG&E is the largest EE program administrator in California, serving approximately 5.5 million electric and 4.5 million gas accounts across Northern and Central California. Its application covers both electric efficiency (HVAC, lighting, data centers, agriculture) and natural gas efficiency (water heating, building envelope, industrial processes).
Annual EE budgets for PG&E have historically approached $700–$800 million combined electric and gas. The Commission evaluates portfolio cost-effectiveness through the TRC test and sets minimum savings targets before adoption. Decisions on these applications are typically issued 12–18 months after filing.

SoCalGas is California's primary natural gas EE program administrator, serving approximately 21 million people across Southern California. Its EE portfolio focuses on gas end-uses: space heating, water heating, appliances, and industrial thermal processes. The application must also address how programs fit within California's long-term gas transition strategy under the 2022 Climate Action Plan.
Annual gas EE budgets for SoCalGas typically range from $150–$200 million. The Commission scrutinizes cost-effectiveness of gas programs given California's broader decarbonization goals - some gas EE investments face questions about stranded cost risk as electrification accelerates.

SCE's AMI 2.0 application seeks authorization to replace approximately 5.4 million legacy SmartConnect (AMI 1.0) meters and add 300,000 new meters across its 15 million-customer service territory. The original SmartConnect system was authorized across three phases from 2005 to 2008; vendor support for the existing hardware expires in 2035, and each year of delay costs approximately $140 million in extended maintenance.
The proposed $1,865 million revenue requirement covers 2026 through 2033, with small-scale deployment beginning in late 2028 and mass deployment running 2029 through 2033. SCE projects a benefit-cost ratio of 7.56 relative to the incremental cost of simply extending AMI 1.0 life. New meters will support two-way communication, faster outage detection, time-of-use pricing, and vehicle-grid integration. Capitalized software costs are forecast at $444.6 million, with a 110% reasonableness threshold of $489 million. No ALJ has been assigned yet.

SB 846 (2022) reversed PG&E's planned retirement of Diablo Canyon and established a framework for up to five additional years of operation. The statute requires annual Commission review and approval of PG&E's recorded costs - covering fuel, operations and maintenance, capital investment, nuclear waste management, and accelerated decommissioning trust contributions. Year 1 (A.24-03-007) and Year 2 (A.25-03-012) applications preceded this filing.
This Year 3 application covers the period ending December 31, 2026. Commission review focuses on whether recorded costs are reasonable and consistent with the SB 846 operational authorization. Diablo Canyon Unit 1 and Unit 2 collectively produce approximately 2,250 MW - roughly 8–9% of California's total in-state generation capacity. Cost recovery is funded through PG&E electric rates via the Nuclear Decommissioning Cost Memorandum Account and related balancing accounts.

SDG&E seeks CPUC authorization under PUC §817 to issue $2,583,000,000 in new long-term debt securities (notes, debentures, other obligations) and refinance $1,348,000,000 in maturing obligations via roll-over securities over a multi-year period. Combined authorization of ~$3.93B funds capital investment driven by grid modernization (Smart Meter 2.0, $948.75M), wildfire mitigation, and general reliability. Commission reviews whether issuance is reasonably necessary for lawful corporate purposes and that terms don't impair utility service or ratepayer interests. Actual issuances within the cap require only an Advice Letter.

SCE provides water and gas utility service on Santa Catalina Island through its Catalina Island subsidiary - a Class C water utility and a small gas distribution system. This application seeks Commission approval for cost recovery covering infrastructure maintenance, capital investment, and operating expenses for these island utility services. Catalina Island is served exclusively by SCE across electric, water, and gas; the island's isolation makes utility operations structurally more expensive than mainland operations. Ratepayer impact and approved dollar amount to be determined through the Commission's rate case review.

PG&E's 2023 GRC was split into three phases: Phase I set the revenue requirement (adopted in D.23-12-037); Phase II addressed nuclear operations and wildfire-related capital; Phase III resolved remaining contested issues including vegetation management cost recovery and outstanding intervenor claims.
D.26-02-035 formally closes Phase III after resolving all remaining issues, allowing the proceeding record to be finalized. Closure of Phase III does not reset or alter currently effective rates - all rate changes from this GRC were set at Phase I adoption effective January 1, 2023. The next GRC cycle (2027 GRC, A.25-06-016) will set rates effective January 1, 2027.

PG&E seeks CPUC authorization under PUC §851 to sell the Hamilton Branch Hydroelectric Project - a 4.8 MW facility mothballed as uneconomical. The buyer is Hamilton Branch Hydro, LLC. The Commission must determine whether the sale is in the public interest and that ratepayers receive appropriate benefit from any gain on sale.
Purchase price not publicly disclosed in the application. Ratebase impact and disposition of proceeds addressed in financial exhibits. Transaction also requires FERC approval for jurisdictional assets. The Feather River Land Trust conservation easement remains in place regardless of outcome.

Annual §451/§454.5 compliance review of PG&E's utility-owned generation (UOG) fleet for 2025. The Commission must determine whether PG&E's generation operations, economic dispatch, fuel procurement, and contract administration were prudent and consistent with its approved procurement plan. PG&E argues Diablo Canyon Power Plant (DCPP) extended operations costs belong in a separate statutory proceeding and should not be reviewed here.
The Portfolio Allocation Balancing Account (PABA) tracks capital costs; the Energy Resource Recovery Account (ERRA) tracks fuel and variable O&M costs. Commission findings on prudency determine whether recorded costs are recoverable in rates or subject to disallowance.

Crimson California Pipeline, a crude oil common carrier regulated by the CPUC, seeks a 66.97% rate increase effective April 1, 2026. The company cites a steep decline in throughput as California refineries reduce crude intake, leaving fixed costs spread across lower volumes. The Commission must determine whether the proposed rate is just and reasonable under PUC §454. Shippers and downstream parties may intervene. No IOU ratepayer exposure - crude oil shipper costs not passed through to residential utility bills.

PacifiCorp (d/b/a Pacific Power) seeks CPUC authorization to recover wildfire-related costs recorded in its Wildfire Expense Memorandum Account (WEMA) for the 2020 Slater Fire and 2022 McKinney Fire. The ~$1.7B total is multistate; California's jurisdictional share is subject to CPUC review. The Commission must determine whether recorded costs were prudently incurred before authorizing rate recovery. Intervenor review of fire cause, cost allocation methodology, and insurance offsets is expected.

PG&E files its Low-Income Proceedings Application for the 2028–2033 program cycle, requesting Commission approval to continue administering the Energy Savings Assistance (ESA) program - which provides free weatherization and energy-efficiency upgrades to income-qualified households - and the California Alternate Rates for Energy (CARE) discount program. The application proposes six-year program budgets, outreach strategies, and customer enrollment targets. This proceeding was consolidated with SCE (A.26-01-005), SDG&E (A.26-01-010), and SoCalGas (A.26-01-011) per an ALJ ruling on February 10, 2026, reflecting the CPUC's preference for coordinated review of all IOU low-income programs.

SCE files its Low-Income Proceedings Application for the 2028–2033 program cycle, covering the Energy Savings Assistance (ESA) program, the California Alternate Rates for Energy (CARE) discount, and the Family Electric Rate Assistance (FERA) program - which provides a smaller discount to households slightly above CARE income thresholds. SCE proposes program structure, budgets, and outreach targets for Commission approval. This proceeding was consolidated with PG&E (A.26-01-003), SDG&E (A.26-01-010), and SoCalGas (A.26-01-011) per an ALJ ruling on February 10, 2026.

SoCalGas files a compliance application as directed by Ordering Paragraph 6 of Decision 24-12-076. The application addresses specific compliance requirements imposed by the Commission in that prior decision. Assigned to Commissioner Karen Douglas and ALJ Jamie Ormond, the proceeding is categorized as ratesetting within the gas industry. Compliance filings of this type are required when a prior decision orders a utility to return to the Commission with a formal application implementing specific directed actions.

SCE requests Commission authorization under Public Utilities Code Section 851 to grant public road and limited utility easements to the City of Ontario. Section 851 requires CPUC approval before a utility can sell, lease, or transfer any property necessary for its operations. This is a routine infrastructure accommodation with no direct rate impact - the easement allows public road development over or alongside SCE-owned land while preserving utility access rights. Assigned to Commissioner Darcie Houck and ALJ Marcelo Poirier.

All five major California IOUs - PG&E, SCE, SDG&E, SoCalGas, and Southwest Gas - jointly seek a one-year bridge authorization to continue ESA and CARE low-income programs in Program Year 2027. The bridge is necessary because the long-term 2028–2033 cycle applications (filed separately) will not be resolved before PY2027 begins, creating a gap in program authority. Without Commission approval, IOUs would lack authorization to operate and fund the programs during 2027 - potentially interrupting service to hundreds of thousands of low-income customers.

SDG&E files its Low-Income Proceedings Application for the 2028–2033 cycle, covering both the Energy Savings Assistance (ESA) program - which provides free weatherization and appliance upgrades to income-qualified customers - and the California Alternate Rates for Energy (CARE) discount program. SDG&E proposes program budgets, customer targets, and delivery methods for Commission approval. Filed in coordination with the parallel SoCalGas (A.26-01-011) and joint IOU bridge (A.26-01-021) applications.

SoCalGas seeks CPUC approval to continue delivering the Energy Savings Assistance (ESA) and CARE low-income programs across its gas service territory for the 2028–2033 cycle. ESA provides weatherization measures and appliance replacements to reduce energy burden for low-income customers; CARE provides a rate discount. SoCalGas proposes program structure, budgets, and outreach targets. Filed concurrently with SDG&E's application (A.26-01-010) and the joint IOU bridge filing (A.26-01-021).

SCE seeks a CPUC financing order under AB 1054 authorizing $1.84 billion in rate reduction bonds to securitize its approved Woolsey Fire wildfire costs. Securitization replaces traditional rate base recovery with lower-cost bond financing - saving ratepayers an estimated hundreds of millions in carrying costs over the recovery period. Bondholders are repaid through a non-bypassable charge on customer bills. The CPUC must find the structure is in the public interest and issue a financing order before bonds can be sold.

Brookfield Infrastructure Partners seeks CPUC authorization under PUC §851 to acquire Wild Goose Energy Storage (~28 Bcf working capacity) and Lodi Gas Storage (~12 Bcf) - two major Northern California gas storage facilities currently owned by a PG&E affiliate. Together they represent critical seasonal storage capacity for the regional gas market. The Commission must find the transfer consistent with the public interest, including operational continuity, reliability, and ratepayer protection. FERC approval also required for FERC-jurisdictional assets.

The balance represents amounts collected from bundled customers above recorded power costs. PG&E’s forecast remains sensitive to market prices, customer demand and the final 2026 market price benchmarks — which Energy Division has not yet issued. That dependency is the main open question: PG&E expects the overcollection to unwind without an interim rate adjustment, but the projection rests partly on benchmarks that do not yet exist.

The utilities say changing those approaches could take approximately 12–18 months, with PG&E estimating about $500,000 in implementation costs. They frame the issue as a tradeoff between statewide consistency and utility-specific engineering practice, arguing that standardization could increase confidentiality redactions and reduce the usefulness of ICA and Limited Generation Profile data.

Use of LGP remains extremely limited: PG&E reports one active application statewide, with none at SCE or SDG&E. PG&E says no headline ICA-Static Grid values are currently redacted, although about 12.9% of line sections have at least one redacted hourly value.

For DER developers, the Commission’s eventual disposition could affect how much interconnection capacity shows up as usable on ICA maps and LGP profiles without upgrades.

At this stage the maps remain planning tools rather than project-selection documents. The parallel SDG&E filing (AL 3549-G) reports the same compliance step with no tribal requests received as of August 31.

The map updates feed the next phase of the SB 1221 neighborhood decarbonization program, where an Energy Division staff proposal would expand the priority zones from 151 to 304 full census tracts plus nine partial tribal tracts across 26 counties — see the SB 1221 Phase 2 ruling in Proposed Decisions & Rulings.

The maps remain planning tools at this stage rather than project-selection documents. SDG&E’s filing is the companion to SoCalGas AL 6687-G, which reported responses from two tribes.

The September 8 reduction coincided with maintenance at Shingletown PLS and at Gerber, Topock and Kettleman stations; Shingletown work was scheduled through September 30, while the other work was scheduled to end between September 10 and September 20. By September 15 work continued at Shingletown, Topock and Kettleman and began at Delevan Station and on the L300A and L300B pipelines. The entire 330 MMcf/d decline from September 8 occurred on the Redwood Path, where capacity fell from 1,860 to 1,530 MMcf/d; Baja remained at 600 MMcf/d and scheduled California production at 24 MMcf/d.

The filings document an increasingly large maintenance-related reduction in PG&E’s ability to receive gas, but they do not establish that customer demand exceeded available supply or that service was interrupted. The CPUC standard is a minimum system-design requirement based on an average day in a 1-in-10 cold and dry year, so crossing it requires notice even when actual September demand is considerably lower. The September 15 filing is the most significant of the three — available capacity roughly 15% below the standard, against less than 1% on September 1 and about 2% on September 8 — and concurrent maintenance on both paths leaves less flexibility if another facility becomes unavailable before the scheduled work ends.

The decrease reflects turnover in temporary balancing-account collections, not a decline in underlying service costs. Class impacts: noncore commercial-industrial −2.4%, electric generation −3.5%, wholesale −4.7%. The consolidated update reduces core revenue by $55.1 million and noncore by $19 million, partly offset by the $7.8 million backbone increase — backbone rates rise because SDG&E’s transmission-integrity costs are allocated entirely to that service. Both integrity-program figures include franchise fees and uncollectibles.

Projects using any form of co-digestion must separately attribute their component feedstocks. Landfill projects must now deploy advanced gas-capture and monitoring technology and demonstrate that an SB 1440 contract will not induce project activities that otherwise would not have occurred. The filing creates a conditional path for wastewater-treatment plants to use incremental existing combustion-generation capacity for biomethane production, subject to air-quality compliance, high-efficacy filtration, inclusion of the combustion in the lifecycle carbon-intensity analysis, and use of the power only for Renewable Gas Standard-related production. Part B adds credit for projects near population centers that demonstrate net local-emissions benefits; the revisions also define who may serve as the “officer” providing required attestations and update terminology to reflect the state’s renamed Cap-and-Invest program. The break-even calculation balances the all-in cost of renewable natural gas against conventional gas, including baseload supply, delivery, Cap-and-Invest compliance, and emissions.

A proposed decision in the 2027 GRC is scheduled for March 2027 with a final decision anticipated in May 2027. PG&E requests authorization by September 30 to gain certainty before the 2023 GRC cycle closes, but separately asks for an effective date on or before August 13. TURN and Cal Advocates, who negotiated the original self-insurance settlement, support the extension; the settling parties met February 27 to assess the program’s first three years as required by D.23-01-005 and all agreed it should continue unmodified, though the filing discloses the conclusion without the supporting analysis. For context, in its 2023 GRC PG&E sought $707 million annually to buy $900 million of commercial wildfire coverage; it began transitioning to self-insurance in March 2023, has been fully self-insured since August 2023, reduced the program’s CPUC-jurisdictional revenue requirement to zero beginning January 1, 2025, and requests no revenue requirement in the 2027 GRC.

The ratepayer-protection structure runs on actual costs with progress billing rather than estimates. Refunds on the regular-service facilities are tied to actual revenues after service begins, calculated through PG&E's BARC process over 10 years: if load underperforms, refunds shrink or disappear. The customer-funded redundant 115 kV line carries no refund rights - the customer eats every dollar of optional redundancy. PG&E's template across recent large-load advice letters: actual-cost payment; BARC-based refunds; minimum demand protections; no refund rights for customer-requested redundancy; and a CPUC/FERC jurisdictional split on cost recovery. PG&E is normalizing bespoke large-load agreements ahead of the Rule 30 outcome, using each filing to reinforce the same basic bargain: accelerated transmission service in exchange for upfront risk absorption.

Beneath the near-flat system average sits a major redistribution of cost drivers. The largest upward driver is a $380.7M distribution revenue increase tied to SCE’s wildfire self-insurance program. After SCE entered into 2025 wildfire settlement agreements expected to exceed $1 billion, it triggered an adjustment mechanism that raises its 2026 self-insurance revenue requirement from $274M to $650M - an increase of $376M before Franchise Fees and Uncollectibles. SCE will amortize the increase over 12 months to moderate rate impacts.

Offsets: $84.5M reduction in Transmission Access Charge Balancing Account recovery (overcollection); $73.4M credit from the 2023 ERRA review; $240.3M reduction in energy efficiency funding requirements; expiration of $34.7M in Thomas Fire Catastrophic Event Memorandum Account recovery rolling off rates after May 31. Smaller items: $15.4M increase for the Electric Program Investment Charge RD&D and renewables program, $6.8M for the 2026 Flex Alert paid media campaign, and $3.6M annually for SCE’s tariff on-bill financing pilot for residential clean-energy upgrades.

Takeaway. For large customers tracking distribution cost growth and wildfire exposure, the filing is another reminder that California utility rates remain under steady upward pressure even when bill impacts appear benign. The TACBAA reduction shows how balancing-account timing can temporarily absorb rate pressure without altering the broader cost trajectory.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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 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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.”

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

SCE would tie a Flex Connect-style offering to the readiness of DERMS, AMI 2.0, and related systems, citing its Load Control Management System pilot where customers received service about 20 months sooner than by waiting for upgrades. SDG&E says there is no demonstrated demand in San Diego and prefers compensated DER orchestration over indefinite uncompensated limits. UCAN is the strongest supporter — wanting Limited Power as default mitigation, permanent non-bridging service, and removal of avoided projects from utility capital plans — though it would make real-time pricing opt-in; EDF is the clearest backer of default real-time pricing with compensation for permanent limits. Cal Advocates and IREC want stronger evidence before broad deployment, with Cal Advocates seeking a comparison of each flexible connection against the wires upgrade it replaces, and both questioning whether permanent limited service can be reconciled with the obligation to serve. CalCCA, CALSSA, and Advanced Energy United want third-party providers considered before utility platforms entrench.

SDG&E wants the Commission to complete the framework first, then allow optional, readiness-driven applications. Most non-utility parties support a time-limited working group followed by a Commission framework: Advanced Energy United, CalCCA, Clean Coalition, and CESA want common standards, open market access, and protections against utility self-preference, while the Center for Biological Diversity would consider utility incentive reform or an independent distribution system operator before applications proceed. UCAN’s three functions are a DER registry, a data hub, and a flexibility market. CALSSA supports a six-month working group but wants immediate programs letting large loads bring virtual power plant capacity to overcome energization constraints. Parties generally accept three use cases — system peak reduction, speed to power, and more efficient grid investment. On unsettled rules, EDF seeks common evaluation and cost-allocation rules, CESA wants storage to stack distinct distribution, wholesale, and reliability revenues, and several parties favor protocol-neutral interfaces without waiting for AMI 2.0.

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.

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.

BTM cost recovery (the central §663(b)(8) dispute): The PD treats BTM costs as expenses amortizable over up to 10 years, with carrying cost capped at the utility's authorized cost of debt - aligning with the the alternative framework advanced in December 17, 2025 Reply Comments and March 27, 2026 Opening Comments on the ALJ Ruling. PG&E and SoCalGas/SDG&E (Joint Utilities) oppose, seeking full WACC / rate of return via regulatory-asset treatment; Sierra Club + NRDC also prefer regulatory-asset at standard ROR but accept the PD's expense framing. Indicated Shippers and SBUA support the PD's no-ROR holding and ask for express language extending the bar to "regulatory assets, or another return-bearing mechanism."

Application vs. Advice Letter: The PD requires an Application; PG&E and Sierra Club/NRDC oppose (favoring 2- or 3-tier AL); Indicated Shippers and Cal Advocates support the PD; SCE asks for bifurcation (AL for <$7M, Application for larger).

67% pre-filing EOI threshold: Cal Advocates wants 80%; PG&E and Sierra Club/NRDC want elimination; most parties accept 67%. Cal Advocates also seeks a $3M cap on project-development costs for projects that never become applications, plus a lessons-learned report.

Cost-effectiveness level: PD adopts project-level; PG&E asks for program-level; Sierra Club/NRDC ask for portfolio-level (citing "legal error"); Indicated Shippers defends the PD.

Track 4 deferrals: Performance-based shareholder incentive deferred to Track 4. Ratepayer-advocate parties have signaled that any incentive tied to BTM-driven savings is at risk as a prohibited deferred return under §663(b)(8). Cal Advocates opposes any shareholder incentive on speculative-need grounds. Sierra Club + NRDC want an equity-focused incentive added.

Other party-specific asks: SCE wants single-fuel electric-IOU co-administration (electric IOU cost recovery); CMUA seeks reimbursement clarity for electric utilities (including POUs); CCSF proposes ZEA limited to non-combustion (exclude hydrogen/propane/biomethane); ECCHHC proposes tenant protections; CforAT proposes outreach materials in large print/Braille; CCR REN proposes RENs added to "coordinating entities" definition.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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 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 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.

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.

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Outcome: see the September 17 results card in this section for what the Commission actually adopted and what it held to October 8.

Correction carried from the September 3 meeting: the CPUC did not approve changes to SCE’s Fire-Threat Map on September 3. Commissioner Darcie Houck held that item until September 17 to allow further review. See the Fire-Map PD card in Proposed Decisions & Rulings for the substance of the item.

Also on the agenda: Draft Resolution E-5475 (Ava Community Energy’s Sonrisa project and the IRP baseline), Draft Resolution E-5480 (distribution-planning equity metrics), the GO 95 Load and Resistance Factor Design proposed decision, the tribal consultation and land-transfer policy proposed decision, and Draft Resolutions G-3622 and G-3623 on gas research, development and demonstration spending — including whether gas ratepayers should fund hydrogen research.

PG&E provided adequate data for circuit loads, system and circuit-level forecasts, known and pending loads, and extreme-weather adjustments; materials covering no-cost solutions, GNA tables, recommended investments and the continued need for earlier projects were expected in early September, with load-tracking, project-prioritization and execution information due later.

SCE completed most of its scheduled early forecasting demonstrations, including base, high and low scenarios, hot spots and extreme-weather adjustments. Additional GNA demonstrations were scheduled for September 25, followed by project-planning demonstrations October 9 and prioritization and execution information October 13.

SDG&E provided adequate data for most forecasting, pending-load, GNA and planned-investment steps, but the engineer requested additional information because data on 2025 circuit loading and extreme-weather adjustments were incomplete. Load-tracking data were due September 15, with other project information expected through early October.

These reports assess whether the independent engineer has enough information to conduct its review; they do not validate the utilities’ forecasts or investment plans, and because the verification approaches differ the statuses are not a direct ranking of data or planning practices. The engineer cautioned that it received more detailed information than parties received through the service list, so its adequacy findings do not establish that stakeholders can evaluate the same forecasts and projects. The November DPAG reports will provide the first substantive verification findings.

The forecasting workstream parallels the CPUC’s scrutiny of data-center load in PG&E’s 2027 ERRA forecast (see Proposed Decisions & Rulings) — both turn on distinguishing committed from speculative load before it enters planning and rate-setting. On EDAM, Energy Division staff comments questioned whether currently available public data allow stakeholders to reproduce the calculations behind some of CAISO’s key load-balancing results. Related Sacramento activity in the period: SB 886 (preventing data centers from raising costs for other customers) and SB 887 (clean-energy investment incentives) advanced from a key committee as the session nears its close.

Industry opposition was on the record: Goodyear told the Commission the rule would raise consumer costs and that technical and legal issues remained unresolved, disputing the CEC’s estimate of roughly $6.50 average per-tire price increases in phase 2 and warning increases could reach several hundred dollars. Rolling-resistance efficiency interacts with electric-vehicle range, making the standard relevant to transportation-electrification load forecasts as well as gasoline savings.

The agenda groups items by subject: utility finances and cost of capital, wildfires, large-load interconnection, low carbon fuel standard, arrearages, natural gas infrastructure, electric reliability and resiliency, gas system reliability, hydroelectric assets, and corporate restructuring. Several would set precedent beyond the individual utility involved — the LCFS resolution replaces an ad hoc advice-letter process with a fixed annual cycle for all three electric IOUs, and the reliability PD creates a unified annual report for PG&E, SCE, and SDG&E. Two marquee items, Res. E-5455 and the competing capital-structure PDs, were subsequently held to September 3. See the results card for what actually passed.

The filing responds to Commissioner Harada’s July 20 scoping memo, which directed the utilities to file the survey conducted pursuant to D.25-08-032 no later than July 31, 2026. The utilities report that no public utilities commission dictates a risk-neutral approach to catastrophic events, and that aviation and nuclear regulators — the two closest analogues to electric utilities on public exposure — build rules to avoid tail-risk outcomes rather than price them. The Commission has said since 2016 that it should set a risk-tolerance standard but has never done so; utilities currently set their own tolerances internally, bounded by authorized funding and operating constraints, and explain them after the fact in RAMP filings and rate cases.

Within SoCalGas’s risk-mitigation programs, capital exceeded the imputed amount by $137.8 million (15%), led by gas storage, distribution, and transmission, while risk-related O&M came in 2% under as higher gas-integrity spending offset lower Pipeline Safety Enhancement Plan and field/meter operations spending. SDG&E’s risk-related O&M and capital ran 11% and 10% under benchmark, mainly because wildfire-mitigation spending came in below imputed amounts. The utilities caution the comparisons are not an accounting of authorized funding: because the 2024 GRC set a 3% annual revenue-requirement increase rather than approving post-test-year capital, both imputed 2025 authorizations by escalating direct costs by 3%, a method they say overstates the capital the adopted revenue requirement supports. Three projects — two compressor modernizations and SoCalGas’s customer-information-system replacement — are measured against zero authorized dollars because the Commission capped their costs and deferred recovery until in-service. SoCalGas has a pending petition to modify D.24-12-074 on the post-test-year mechanism.

The central marginal-cost and revenue-allocation subgroup has held 22 meetings, and PG&E has run nearly 100 scenarios to help parties weigh compromises. PG&E reported that every party has made at least one concession from its original testimony position, although “many details” remain unresolved. Those marginal-cost values are needed to complete negotiations over business electric-vehicle rate design and portions of commercial and industrial rate design. Phase II of a GRC sets rate design and revenue allocation rather than the total revenue requirement.

Each major item has its own card in Proposed Decisions & Rulings. Other energy items voted August 13: Res. E-5463 (joint IOU Low Carbon Fuel Standard process streamlining, approved with modifications); Res. G-3620 (SoCalGas Southern System reliability compliance, net cost $5.5M); A.25-04-004 (PG&E’s withdrawal of the S-238 Hinkley compressor CPCN granted); R.24-05-023 (unified IOU Customer Reliability Report template adopted; rulemaking closed); R.18-07-005 (Arrearage Management Payment Plan extended to February 1, 2027); A.25-05-020 (Sempra intermediate holding company authorized); and A.25-03-001 (SCE’s $19.66M Lower Tule hydro sale authorized). Liberty Utilities’ $61.4 million Mountain View Fire cost-recovery PD (A.25-06-017) was held to October 8. Upcoming meetings: September 3 (Sacramento), September 17 (San Marcos), October 8, October 29.

The investigation used National Wildfire Coordinating Group methodology supplemented by retained electrical and metallurgical experts. The determination is materially relevant to roughly 1,500 pending lawsuits — approximately 20,000 individual plaintiffs plus subrogation carriers and public-entity plaintiffs including the United States, Los Angeles County, Pasadena, and Sierra Madre. It lands days before the first courtroom test of the plaintiffs’ strict-liability theory (see the inverse-condemnation ruling card in this period) and ahead of the first bellwether jury trial, set for January 25, 2027.

SCE argues the tower, idle since 1971, no longer qualifies as public-use infrastructure that triggers strict liability — the question at the heart of applying inverse condemnation to a de-energized facility. If the tentative ruling holds, insurers may still pursue inverse condemnation at a bench trial, and negligence claims proceed to the first bellwether jury trial on January 25, 2027. The ruling is the first significant judicial screen of the liability theories that will determine how much of the Eaton Fire loss ultimately reaches SCE, its insurers, and the state wildfire fund.

EDAM launched May 1, 2026 with PacifiCorp East and West alongside CAISO, and Portland General Electric begins day-ahead participation in October 2026; the market delivered $11.38 million in cost savings in its first two months, and the first Western Energy Markets quarterly benefits report put combined EDAM/WEIM gross benefits above $470 million for the second quarter of 2026. ROWE was created under the 2025 Pathways / AB 825 framework, which envisions a regional-governance transition after January 1, 2028. The IPE 5.0 revisions unify shared payment and authorization schedules among certain interconnection customers; protesters including the Large-scale Solar Association had warned customer refunds could be lost under the change. CAISO also issued an errata to its board-approved 2025–2026 Transmission Plan clarifying geothermal deliverability reservations. No Flex Alerts or grid emergencies occurred in the period.

Battery capacity grew 80% over the comparison period. The CEC’s Opt-In Certification program has approved 1,850 MW of storage and 1,450 MW of solar in the past year, with more than 3,000 MW queued. The milestone is the backdrop for the storage-heavy resource-adequacy and procurement questions running through the CPUC’s IRP and RA dockets, where long-duration storage multipliers and battery flexible-capacity accreditation remain open issues.

The removal reverses amounts collected under the timing of the utility’s delayed 2024 GRC decision. Trade coverage in the same week noted SoCalGas’s capital spending is running roughly 25% above an imputed CPUC benchmark — a datapoint intervenors are expected to press in the consolidated 2028 GRC, where protests focus on year-to-year spending growth, sub-1.0 benefit-cost pipeline programs, and how much long-lived gas infrastructure customers should finance as gas demand declines.

Each held item has its own card in Proposed Decisions & Rulings. Decided July 16: D.26-07-042 (Northern San Joaquin 230 kV CPCN, signed); Res. G-3616 (SoCalGas recovery of ~$54.4M in storage-integrity undercollection); and Res. E-5470 (PG&E Atlas Solar XII/XIII PPA amendments, initial delivery moved to Sep 2028).

PG&E Cap Structure ($2.6B): A proposed decision would deny PG&E's request to exclude approximately $2.6 billion in wildfire liabilities and a state loan from its capital structure calculations. (Held by President Reynolds from July 2 for further review.)

PG&E $1B Short-Term Borrowing Reserve: A separate proposed decision grants PG&E half of the borrowing request in its 2025 application - authorizing a $1 billion increase in short-term debt authority (total $9.5 billion; PG&E asked $2 billion). The reserve is available only for: (1) gas/electricity price spikes (>50% jump in monthly cost vs. trailing 12-month avg), (2) major disaster response, or (3) memo/balancing-account undercollections >$2.5 billion. Funds cannot refinance existing debt. The figure ties directly to the Commission's new winter gas price cap (D.26-02-058). PG&E's own $600 million estimate of incremental need had the cap applied during the 2022-23 winter spike is the quantitative basis for the $1 billion.

SoCalGas Storage Integrity ($54.4M): Draft Resolution G-3616 grants SoCalGas authority to recover about $54.4 million for undercollected costs in its Storage Integrity Management Program Balancing Account (2019-2023 cycle, measured through Dec 2024). SoCalGas spent $437.1M against $332.4M authorized (31% overrun, entirely capital-driven). Because the amount falls under the 35% cap set in the 2019 GRC, SoCalGas can recover by advice letter. Staff found the overrun reasonably incurred.

PG&E Amended Atlas Solar PPAs: Draft Resolution E-5470 approves PG&E's amendments to two PPAs with Atlas Solar XII and XIII for the Atlas Solar North 1 and 2 projects in La Paz, Arizona (375 MW solar + 225 MW storage each). Initial delivery moves from Dec 1, 2027 to Sep 1, 2028 due to network-upgrade delays; capacity, term, RPS product and pricing unchanged. Project owner Lydian Energy supported the amendments.

Extreme-Heat Disconnection Protections (90°F Statewide): Draft Resolution E-5468 approves - with significant modifications - a joint SCE/PG&E/SDG&E/SoCalGas advice letter implementing D.25-06-012, which implemented Senate Bill 1142. The utilities proposed CalHeatScore Level 3 (activates at apparent temps ~98-101°F) plus a 100°F interim trigger. The draft resolution adopts CHS Level 2 plus a 90-degree statewide interim/fallback trigger, aligning with intervenor comments recommending a single lower threshold for coastal and mountain customer populations. Utilities may record incremental implementation costs to their Disconnections Memorandum Accounts and must report Level 2 trigger's arrearage effects annually for three years.

Northern San Joaquin 230-kV Transmission CPCN ($198.8M): A proposed decision grants PG&E a CPCN for the Northern San Joaquin 230-kV Transmission Project - a reliability upgrade looping the Brighton-Bellota line through Lockeford Substation and adding a new double-circuit 230-kV line to the new PG&E Thurman Switching Station at Lodi Electric Utility's Industrial Substation. Cost cap $198.8 million (14% contingency), March 2029 target. The project essentially doubles local load-serving capability for about 38,000 PG&E and Lodi Electric Utility customers. The PD grants some of PG&E's requested revisions to biological measures while keeping a 1,640-foot burrowing owl survey buffer, tiger salamander work stoppages, wetland O&M protections, and bat roost obligations.

Google 250 MW San Jose Data Center: Draft Resolution E-5455 approves PG&E's agreement to energize Google's 250 MW San Jose data center with stronger ratepayer protections: refunds capped at actual net revenues received (not projected future revenues), refund window extended from 10 to 15 years. The agreement must be updated within 60 days of a decision in the Rule 30 proceeding. Google's load depends directly on the Newark-NRS 230 kV line (a $1B+ project whose FERC-approved revenue requirement hits ratepayers at ~$100M/yr) plus more than 10 other South Bay transmission upgrades. The CPUC previously capped refunds at 75% of net revenues for STACK Infrastructure and Microsoft (Res. E-5420 and Res. E-5439); the Google agreement uses 100%.

PG&E Facility Relocation Contracts: Draft Resolution E-5465 (KB Home South Bay Phase 3, ~$782,109) and Draft Resolution E-5462 (Clark & Sullivan / Broward Builders JV building CHP office in Quincy, ~$1.3M) approve PG&E agreements allowing overhead T&D facilities to be relocated on an actual-cost basis rather than under the standard fixed-estimate WPA. Both under Electric Rule 15.I.3 Exceptional Cases.

For settlement purposes, PG&E admits four violations of General Order 95: (1) overdue corrective repairs; (2) failure to preserve the removed pole and attached equipment due to an internal coordination error; (3) six years of missed function tests on the two Oxbow Junction switches; and (4) inadequate clearance between a jumper and the interconnection switch rod - the condition SED alleges created the September 6 electrical fault. PG&E does not contest a vegetation-clearance allegation at the same pole. It disputes two others (loose tie wires and six cancelled transmission-maintenance notifications). The agreement states that most cited conditions were unrelated to ignition. SED dismissed an eighth allegation (late initial incident report). Any unused review funds go to the General Fund. The ACO resolves all claims SED brought or could have brought from the Mosquito Fire investigation, with no formal adjudicatory proceeding. SED retains authority to open separate enforcement against the inspection-review team based on the third-party report.

Procedural context: The $22 million figure sits below prior recent CPUC wildfire settlements (Zogg $150M; Dixie $45M from the CPUC plus $34.75M to five county district attorneys). The record identifies four factors relevant to the differential: no deaths, no injuries, an agreement that expressly detaches most cited conditions from ignition, and two disputed allegations. SED elected to resolve those disputes through settlement rather than adjudication.

The disputed allegations concern PG&E’s inspection-review team’s process for cancelling repair notifications. SED’s record shows the team cancelled 131,119 notifications created in 2023 alone. The $1 million examination covers the team’s general policies and procedures rather than the specific Oxbow cancellations. SED reserved the right to open separate enforcement based on the third-party report. The Administrative Consent Order pairs the settlement with an SED-approved independent contractor review of the inspection-review team’s policies and procedures on a one-year report deadline.

Item 15 (R.25-10-003, RA Reform Track 1 PD): Adopts 2027-2029 Local Capacity Requirements (23,618 / 24,545 / 25,480 MW), 2027 Flexible Capacity requirements, the Unforced Capacity (UCAP) framework effective 2028, storage penalty structures, and formally ends paper capacity. The first major RA structural overhaul since 2019.

Item 47 (R.24-09-012, SB 1221 Pilot PD): Establishes the application process for up to 30 statewide neighborhood decarbonization pilots across three deadlines (Dec 15, 2026; Dec 15, 2027; Jul 1, 2028). PD adopts the Application (not Advice Letter) approach, 67% pre-filing and post-approval consent thresholds, BTM expense-only treatment with cost-of-debt carrying charge, and project-level cost-effectiveness.

Item 9 (A.24-08-004, PG&E Cap Structure Denial): Draft denies PG&E's request to exclude approximately $2.6 billion in wildfire liabilities and a forgivable DWR loan from its capital-structure equity ratio.

Item 26 (A.24-11-005, PG&E Moraga-Oakland X 115 kV): Grants Permit to Construct for a ~5-mile 115 kV transmission rebuild from Orinda to Oakland at approximately $276.8 million, addressing 2026 summer-peak thermal violations. Construction 2027, completion 2029.

Item 19 (Res. E-5444): Draft declines to approve SDG&E's proposed residential Capacity Bidding Program and associated budget transfers, cutting off a planned residential DR expansion channel.

Item 7 (A.26-02-007, Southwest Gas Debt): Authorizes up to $1.15 billion in new debt, refinancing, and interest rate risk management contracts.

Item 25 (A.25-02-012, SDG&E TIMP): Grants recovery of $6,985,215 in Transmission Integrity Management Program costs incurred Jan 1, 2019 – Dec 31, 2023 pursuant to settlement.

The Tumbleweed 8-hour battery is the first project to come online under the CPUC's 1,000 MW LDES procurement mandate. Under the RA Reform PD framework (R.25-10-003) up for adoption Jul 2, LDES resources capable of discharging at maximum capacity for at least 8 continuous hours receive a Forward Charge Period multiplier ranging from 2x (8-hour resources) to 8x (72-hour-plus resources) starting 2027, enabling counting across the full 24-hour Slice-of-Day period. Tumbleweed's 8-hour duration sits at the floor of the LDES definition. Kern County siting places the project near the Tehachapi renewables hub; project follows the December 2024 completion of the Westside Canal Phase 2a 119 MW / 4-hour battery approved via SDG&E's Res. E-5467 acquisition.

An attached handout listed three other approaches for comparison only, not as Cal Advocates alternatives: a CAISO-tariff-modeled option tying advances to contracted capacity; the Resolution E-5420 method capping refunds at 75% of net revenue; and PG&E’s own “customer responsibility” proposal, which Cal Advocates says would produce no upfront financing because it excludes CAISO transmission planning process upgrades and upgrades not solely triggered by one customer. Cal Advocates argues refunds should track actual revenues rather than forecasts so customers are not refunded before load materializes, and that no other jurisdiction pursues interest for large-load interconnections — noting none of PG&E’s large-load advice letters in the proceeding have requested or received interest. It also backed a minimum demand charge on a fixed load ramp over PG&E’s customer-specific ramp, citing gamesmanship risk, and said minimum contract terms, early termination fees, and lowest-cost rules for applicant-built facilities have broader party agreement.

The express warning of a possible curtailment watch or actual curtailment makes the notice significant for noncore customers, including industrial users and potentially electric generators. Whether curtailments occur depends on whether supply and demand return to balance and how the utilities apply their tariff priorities. The notice landed the same week the Commission was weighing Draft Resolution G-3620, which would loosen SoCalGas’s gas-purchasing rules in response to declining supplier participation and thin market liquidity on the same Southern System — and the same month SoCalGas’s TY 2028 rate case proposed a 14.8% backbone transportation increase.

The Notice states three grounds for OCSLA challenge: the leases were competitively awarded under a federal statute that requires development; the cash buyout plus mandated out-of-state fossil reinvestment is itself a substantive policy reversal not authorized by the statute; and the cumulative effect across eight lease areas ($2.6 billion) reduces California's ability to meet the 25 GW by 2045 offshore wind target adopted under AB 525. Golden State Wind's 2 GW Morro Bay lease (OCS-P 0564) and Invenergy's adjacent 1.5 GW lease (OCS-P 0565) are the two largest single buyouts. If the suit succeeds, the federal Interior Department would be enjoined from finalizing the buyout structure pending judicial review; if it fails, the practical effect is that the California port and transmission investments already underway (Humboldt Bay, Long Beach, Port of San Luis) absorb the unrecovered investment risk while the offshore generation pipeline contracts. The case tests state standing to challenge federal lease modifications affecting state energy planning.

The "roughly commensurate benefits" doctrine was articulated in Illinois Commerce Commission v. FERC (7th Cir. 2009) and codified in Order 1000: transmission cost allocation must trace cost causation to beneficiaries with reasonable proportionality. The Maryland OPC argues that PJM's regional Order-1000 allocation lumps Maryland ratepayers into a generalized beneficiary pool for transmission upgrades whose actual cost driver is hyperscaler load growth in Virginia, Pennsylvania, and Ohio. The complaint, if granted, would either remand PJM's allocation methodology or direct PJM to develop a participant-funded sub-regional surcharge for data-center-driven upgrades. The decision may influence California policy in three ways: (1) it tests whether large-load cost causation can be statistically separated from generalized regional reliability needs at scale; (2) it informs CAISO's pending revisions to Rule 30 network-upgrade allocation; and (3) it establishes a record for CPUC arguments in future PG&E, SCE, and SDG&E exceptional-case AL filings that customer-specific cost-causation refunds (BARC) should be paired with non-detriment tests for non-participating bundled customers. Watch for whether FERC opens a Section 206 investigation, which would dramatically expand the proceeding's scope.

FERC's six-takeaway order signals that flexible-load tools (Grid-Enhancing Technologies, demand response) and Co-located Load Behind the Meter arrangements may have to satisfy federal cost-causation tests before being allowed to bypass RTO interconnection processes. Berkeley Lab's parallel analysis projects data centers could use up to 15% of all U.S. electricity by 2030, up from 5% in 2024. For California, the order matters in three ways: (1) it sets a federal floor for the kind of refund-cap and BARC-mechanism protections the CPUC is layering onto exceptional-case agreements like PG&E + Google; (2) it tightens the legal basis for arguments that hyperscale loads bear cost causation for upstream transmission; (3) it pressures CAISO's 2025-2026 Transmission Plan ($6.7B / 38 projects) toward more rigorous large-load attribution as the Tesla-Trimble-Metcalf 230 kV corridor and other South Bay reliability projects move forward. The Imperial County, CA 950,000-square-foot data center reversal reported by CalMatters (Jun 23) underscores that the federal backstop is colliding with local opposition at the same moment.

On GHG issues, staff propose to (a) collapse separate electric and gas values into a single electric-sector figure derived from Integrated Resource Planning modeling; (b) eliminate the GHG Rebalancing component; and (c) cap total GHG value at the high societal cost of carbon. The Integrated Calculation moves from a Python optimization criticized by stakeholders as a black box to an Excel-based framework using RESOLVE GHG shadow prices; marginal capacity value would be derived from a hybrid solar-plus-storage resource rather than solved through the optimization. Hourly allocation changes are also substantive: staff would swap expected unserved energy for loss-of-load hours as the basis for capacity value allocation, on the theory that each avoided LOLH carries equal marginal reliability value regardless of shortfall magnitude. Temperature would give way to SERVM energy prices as the trigger for identifying high-capacity-value days, reflecting IRP modeling showing California's reliability risk migrating from hot summer peaks toward winter periods driven by electrification load and low renewable output. Staff also propose weekday/weekend differentiation consistent with reliability modeling and with downstream uses such as Net Billing Tariff export rates. The proposal is a reweighting of the economic signals that flow through DER cost-effectiveness tests, electrification incentives, gas-substitution economics, and Net Billing Tariff export rates across CPUC programs.

E-5456 (SCE): closes a participation shortfall that was leaving Self-Generation Incentive Program customers without a qualifying DR option when third-party aggregators withdrew. E-5444 (SDG&E): the proposal weakened penalties too far from the existing model and lacked the Resource Adequacy compliance and load-impact filings required of supply-side resources. E-5450 (PG&E ART): 30-day performance evaluation timeline, Day-of Adjustment standardization, CAISO tariff alignment, and minor formatting updates approved; the 30% capacity-payment rate increase rejected. E-5453 (Joint PG&E + SCE AutoDR): expands eligible customer segments and measures and adds PG&E's ART program as a qualified residential AutoDR program. The Commission will fix program-access problems and approve narrow implementation changes; it will not approve residential DR expansion or DER-based supply-side programs without the documentation that real capacity products require. Earliest vote July 2.

CAISO is planning around load growth from electrification, data centers, manufacturing, and transportation. PG&E's Greater Bay Area dominates the reliability picture - Tesla-Trimble-Metcalf and related Bay Area upgrades indicate that South Bay load growth is now a system-planning driver, not a one-off interconnection issue. Path 15 congestion forecasts have moved from 244 hours on the most-limiting circuit in 2030 (per the 2021-2022 plan) to 3,256 hours forecast for 2035, supporting the Gates-Los Banos project now and pointing toward a larger backbone decision next cycle. The Serrano-Del Amo-Mesa cancellation shows the ISO will kill projects when costs outrun the original planning case; its reliability function is replaced with the Mesa-Laguna Bell 230 kV #2 Upgrade and the policy need dropped after updated resource portfolios. Transmission planning is becoming bigger, more iterative, and more politically exposed to large-load cost allocation.

PG&E’s position. Type 4 Transmission Network Upgrade costs should continue flowing through the Transmission Access Charge rather than being assigned upfront to individual customers. PG&E argues that the Resolution E-5420 75% revenue refund approach is proven, supported, and low-risk; that requiring upfront Type 4 financing would drive load to publicly owned utility territory or out of California entirely, leaving existing ratepayers holding upgrade costs with none of the rate-reduction benefit. PG&E illustrated the point with a Silicon Valley Power example: a CAISO-approved 230 kV line estimated at $593M–$858M, whose costs would flow through TAC regardless of whether the associated load lands in PG&E territory. PG&E also told commissioners that no customer has yet used interim Rule 30 implementation.

Ratepayer advocates including Cal Advocates, Sierra Club, and NRDC argue Rule 30 as proposed exposes existing ratepayers to unacceptable cost-shift risk from speculative hyperscale load. All call for upfront financing requirements, direct cost-assignment mechanisms, or refundable load-development fees grounded in cost causation. A refundable $667/kW interim load-development fee for loads ≥25 MW has been advanced by consumer advocacy parties; Cal Advocates proposes the same figure as one of several interim options alongside a flat $50M fee, with primary emphasis on a Revenue Cap methodology. Both treat Resolution E-5420 as a fallback. Sierra Club and NRDC reject PG&E’s FERC preemption argument, citing the CPUC’s own filing in FERC Docket RM26-4-000 that affirmatively argues large-load interconnection cost allocation remains a matter of state jurisdiction.

CLECA does not oppose Rule 30 but argues PG&E is misapplying data-center-driven risk provisions to decarbonizing and EITE customers that do not present comparable stranded-load risks. CLECA urges the CPUC to allow such customers Rule 30 access or continued exceptional-case procedures without the heightened minimum demand charges, extended contract terms, and early termination obligations built for speculative hyperscale load.

CalCCA’s reply takes no position on cost allocation, jurisdiction, or stranded-cost protection. Its one remaining dispute is PG&E’s proposed privacy and cybersecurity review requirements for CCAs receiving Rule 30 customer data.

Stakes. The identical ex parte deck delivered to all five commissioner offices two days before reply briefs shows where PG&E sees its exposure. PG&E is pushing Resolution E-5420 as the endpoint; ratepayer advocates and Cal Advocates treat that resolution as a floor; Sierra Club and NRDC want something more direct. The bigger question is whether the CPUC’s final decision separates hyperscale data-center load from policy-aligned industrial load growth.

Headline numbers. System-wide needs peak in March at 30,378 MW and bottom in December at 25,060 MW. CAISO retains its three-category framework: base flexibility at 27% of total need in non-summer months and 42% in summer; peak at 68% and 53% respectively; super-peak fixed at 5% year-round. For CPUC-jurisdictional LSEs, monthly obligations run from 23,824 MW (Dec) to 29,064 MW (Mar).

The sunset problem. Solar drives the maximum three-hour net-load ramp in every month of 2027. August solar contribution reaches 84.18%. CAISO states this plainly and anticipates continued solar dominance as utility-scale and behind-the-meter penetration grows.

Unresolved battery EFC methodology. The filing’s open question. CAISO states that battery charging in Effective Flexible Capacity accreditation "may be over-credited" in most months outside spring, because batteries transition from charging to discharging during the same ramp window flexible capacity is designed to address. CAISO identifies the problem and defers it, citing unresolved Local Regulatory Authority battery-mapping data.

Takeaway. CAISO’s acknowledgment of potential battery over-crediting creates a procedural record. Questions remain whether the CPUC addresses it in the RA docket, whether parties press for methodology revisions in the 2028 cycle, or whether CAISO’s ongoing Flex RA working group moves first. The mapping-data rationale buys one cycle. As solar dominance of the three-hour ramp deepens, procurement pressure continues shifting toward resources capable of responding during compressed evening windows.

The IEPR is the CEC’s biennial demand forecast and policy assessment that drives procurement orders at CPUC, capacity planning at CAISO, and infrastructure planning across the IOUs. Hydrogen and firm zero-carbon resource analyses respond to SB 1075 and SB 423 mandates respectively. Comments are the principal public-record vehicle for shaping the load-forecast inputs that feed every downstream proceeding.

The March 19 voting meeting was the first under new CPUC President Karen Douglas (appointed March 2026). Key outcomes: SCE's Alberhill Transmission CPCN adopted; LS Power's Santa Clara Valley Transmission CPCN ($1.593B) adopted; California Climate Credit pause (R.25-07-013, D.26-02-057) adopted 5-0 - pausing 2026 credits to fund the new 6,000 MW clean energy procurement order; PG&E RAMP closure approved.
ICA Remediation (Res. E-5440) was held to the April 9, 2026 voting meeting for additional review. DG Statistics Platform (Res. E-5436) remained deferred. The LS Power San José data center CPCN items may have been voted on separately as individual agenda items - see specific card entries for confirmed status.