MONDAY AGGREGATE: Diablo Canyon; DER Flexible Connections; Edison PSPS Events

Updates today reflect the CPUC's continuing focus on long-term infrastructure planning and cost-recovery frameworks.

• PG&E forecasts a return to normalized capital-structure oversight following its bankruptcy-era deleveraging, while simultaneously highlighting the persistent tension between wildfire-driven spending and gas-system underspend that will likely feature prominently in its 2027 General Rate Case.
• Utilities' comments on DER-enabled flexible connections suggest that that any near-term flexible-interconnection policies must be calibrated to infrastructure limitations rather than conceptual frameworks.
• SCE's early-November Public Safety Power Shutoff reports demonstrate how deeply embedded precautionary de-energization has become across diverse wind patterns.
• The Long Beach/THUMS artificial oil islands matter continues to develop as a potential bellwether for how the Commission will handle legacy Added Facilities Agreements in California's offshore drilling phase-down.

DIABLO CANYON

PG&E filed a response to the Alliance for Nuclear Responsibility (A4NR)’s October 2025 petition for modification of the 2024 CPUC decision (D.24-12-033), which governs the costs and reasonableness review structure for Diablo Canyon’s extended-operations revenue requirement for 2025.

• In its petition, A4NR requested that the CPUC replace the forecast 2025 Resource Adequacy Market Price Benchmark (RA MPB) with the final RA MPB value when evaluating whether PG&E’s actual costs exceed the 115% threshold that triggers a reasonableness review, and also sought revisions to update the 2025 revenue requirement.
• PG&E agrees that the final RA Market Price Benchmark should be used for the statutory 115% evaluation but argues this should apply not only to 2025 but to all Diablo Canyon Extended Operations Forecast proceedings through 2030, since the Market Price Benchmark is outside PG&E’s control and variances will continue in future years.
• However, PG&E opposes modifying the 2025 revenue requirement or revising the findings and ordering paragraphs, noting that the Energy Resource Recovery Account-style forecasting and true-up framework already incorporates final Market Price Benchmark values into rates the following year, making A4NR’s proposed revisions redundant and inconsistent with established ratemaking practice.

PG&E recommends partially granting the petition (limited to adopting the final RA MPB for all 115% evaluations going forward) while rejecting A4NR’s other proposed modifications.

Instant Analysis: The main takeaway here is that a 2025 rate adjustment remains unlikely, but the Commission may refine how RA MPB values factor into future cost reviews, thereby potentially improving clarity around the multi-year Diablo Canyon cost-reasonableness structure.

COST of CAPITAL

PG&E submitted its 2025 Annual Capital Structure Update to comply with a 2020 CPUC decision (D.20-05-053), reporting that it is now fully back in compliance with its authorized ratemaking capital structure following the June 2025 expiration of the five-year temporary waiver granted at its exit from bankruptcy.

PG&E says it has deleveraged over the waiver period through equity issuances and other measures, and now maintains (and forecasts through year-end 2025) a common-equity ratio at or above the authorized 52% level.

PG&E provides updated capital-structure ratios as of September 30 and projected ratios for December 31, 2025, reflecting statutory and Commission-directed adjustments for Wildfire Fund contributions, Assembly Bill 1054 wildfire-mitigation securitizations, a rate-neutral $7.5 billion securitization authorized in 2021, and the retroactive grantor-trust election for the Fire Victim Trust.

The advice letter also lists PG&E’s current credit ratings from S&P, Moody’s, and Fitch, and notes that, because the waiver has expired and no deviation exists, PG&E no longer provides a multi-year deleveraging forecast in this update. Protests are due December 15.

Instant Analysis: PG&E’s latest capital-structure update is largely perfunctory but still noteworthy as the first post-waiver confirmation that the utility has restored its equity ratio above the authorized 52% (a key milestone after years of bankruptcy-era leverage).

With the temporary waiver now expired and no deviation to report, this filing signals a return to “normal” capital-structure oversight, albeit still shaped by major statutory adjustments. Credit ratings remain mixed. In short, this is a clean compliance update, but it confirms that the Commission is unlikely to revisit capital-structure relief absent new wildfire-liability shocks or adverse credit movement.

DISTRIBUTED ENERGY RESOURCES

On November 25, the three large electric investor-owned utilities (SDG&E, PG&E, and SCE) filed detailed responses to a CPUC ruling on DER-enabled near-term flexible connections.

The IOUs emphasize that, while they see value in variable and dynamic operating envelopes, their current Advanced Distribution Management System (ADMS)/Distributed Energy Resource Management System (DERMS) systems are not yet capable of delivering customer-level short-term or real-time capacity forecasts at scale.

SDG&E

SDG&E stresses foundational gaps:

• Missing programs;
• Undefined incentives;
• Insufficient telemetry;
• Incomplete customer-level models; and
• Major readiness work needed before any dynamic signaling could function reliably.

SDG&E warns that the ruling's questions "place the technological cart before the financial horse” and that producing operating envelopes for all customers would require expensive new data acquisition, modeling, and system architecture.

PG&E

PG&E outlines a more advanced DERMS posture, one that is already producing day-ahead feeder-level forecasts at SCADA points and deploying variable limits through its Flex Connect program. However, PG&E notes that full grid-wide modeling, hour-ahead forecasting, and customer-level dispatch depend on 2027 General Rate Case funding and load-flow/state-estimation expansion.

PG&E also highlights the need for customer-side equipment and a vendor ecosystem to make IEEE 2030.5 connectivity affordable.

SCE

SCE similarly reports that its ADMS/DERMS capabilities will not support full short-term or dynamic forecasting until 2027–2028, and that interim approaches rely on static limits through Rule 21 and its Load Control Management System pilot.

SCE also emphasizes the distinction between direct 2030.5 “gateway” connections and aggregator-based cloud pathways, noting that aggregator services will often be more cost-effective for customers while direct connection may suit only larger sites.

Instant Analysis: The apparent takeaway from these responses is that California is unprepared to operationalize dynamic or customer-level operating envelopes. All three utilities acknowledge that their ADMS/DERMS stacks lack the forecasting granularity, telemetry, modeling fidelity, and communications architecture needed to support day-ahead or hour-ahead import/export limits across the polyphase grid.

The filings portend a multi-year runway: foundational data cleansing, DER modeling, AMI upgrades, telemetry expansion, load-flow/state-estimation buildout, IEEE 2030.5 integration, and customer/aggregator ecosystems must all mature before flexible connections can be scaled. For now it seems, flexible interconnection remains a niche, pilot-stage tool, and any near-term policies must reflect the large gap between conceptual enthusiasm and operational reality.

RISK ASSESSMENT/SAFETY COSTS

PG&E submitted corrections to a previously filed 2024 Safety Performance Metrics Report, revising "Metric 2" (Transmission and Distribution Overhead Wires Down on Major Event Days) and "Section 4" (2024 imputed adopted values for safety-related risk-mitigation activities).

The updated report confirms PG&E’s 2024 performance across 32 safety metrics adopted in a 2021 decision (D.21-11-009), covering wires-down events, emergency response times, gas-system integrity, fire ignitions, inspections, workforce safety indicators, and corrective-action completion rates.

A key revision is the corrected count of wires-down events during major weather-driven outages (4,676 in 2024) an inherently volatile metric driven by the number of severe storm days, which PG&E says is not used for executive compensation or internal performance goals.

The updated Section 4 tables also restate imputed adopted versus actual spending on safety-related mitigation, showing areas of both underspend (e.g., gas distribution and transmission) and significant overspend (notably in electric distribution capital tied to wildfire and asset-failure mitigations).

PG&E explains that data-flow issues, system-integration challenges, and evolving IEEE reliability-calculation standards necessitated these corrections, and affirms that it is working toward improved alignment with industry best practices.

Key spending takeaways:

• Electric Distribution capital spending exceeded adopted levels by roughly $1.35 billion, driven by wildfire-hardening and overhead-asset programs;
• Electric Distribution O&M spending was also high, coming in more than $300 million above adopted levels;
• Gas Distribution and Gas Transmission both fell well below adopted O&M spending, with combined underspend exceeding $210 million;
• Gas Transmission capital spending came in about $81 million under plan, reinforcing the pattern of lower-than-adopted gas-side execution;
• Shared Services /IT nearly doubled its adopted O&M spending, adding over $170 million above plan; and
• Systemwide, PG&E spent about $1.66 billion more than adopted across safety-related O&M and capital, concentrated overwhelmingly in electric wildfire and asset-reliability categories.

Instant Analysis: This filing provides two practical takeaways.

• First, the corrected count of 4,676 Major Event Days wires-down events reinforces that this metric is almost entirely driven by storm frequency and offers little insight into day-to-day system performance, something PG&E openly acknowledges by excluding it from internal reporting, performance goals, and incentive structures.
• Second, the revised Section 4 spending tables highlight PG&E’s ongoing pattern: heavy electric-distribution spending tied to wildfire and overhead-asset programs, paired with consistent shortfalls in gas-system spending.

For rate observers, it's worth watching how these spending patterns will be examined in PG&E's 2027 General Rate Case, where parties may question whether PG&E’s mitigation portfolio is drifting out of balance between electric wildfire risk and long-term gas-system reliability.

PUBLIC SAFETY POWER SHUTOFFS

SCE issued two Public Safety Power Shutoff post-event reports covering early November 2025, each driven by fast-changing fire-weather conditions and elevated wind forecasts.

• A November 2–6 event in Inyo and Mono Counties involved strong onshore winds that produced High Wind Warnings, extremely low humidity, and gusts reaching 66 mph, leading SCE to de-energize 1,145 customers on the Birchim and McGee circuits.
• Days later, a weaker but still consequential Santa Ana pattern prompted a second event from November 7–10 affecting Los Angeles, Ventura, Riverside, and especially San Bernardino County, where 909 customers on the Firebird and Northpark circuits were de-energized after forecast and real-time winds neared PSPS thresholds.

Across both events, SCE activated its PSPS Incident Management Team, issued thousands of notifications, set up Community Resource Centers, and relied on its machine-learning-enhanced Fire Potential Index modeling, localized weather-station data, and Technosylva wildfire-risk simulations to confirm that avoiding potential wildfire consequences outweighed the temporary impacts of shutoffs.

In both cases, no damage or hazards were found during patrols, and power was restored once wind speeds and Fire Potential Index values fell below de-energization triggers.

Instant Analysis: Both reports reinforce how deeply embedded PSPS has become in SCE’s wildfire-season operations, even in shoulder-season months like early November. What stands out is not the scale of the shutoffs (which is modest by historical standards) but the sensitivity of SCE’s trigger framework:

• Localized, high-resolution Fire Potential Index modeling;
• Aggressive wind-trigger thresholds; and
• Rapid expansions of scope based on evolving forecasts.

The Eastern Sierra event demonstrates how non–Santa Ana wind regimes can now generate PSPS conditions, while the subsequent Santa Ana event shows that even weaker wind patterns can still push circuits over modeled thresholds. The absence of any damage findings highlights the precautionary nature of the activations.

ARTIFICIAL OIL ISLANDS

Last year, SCE filed an application to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the THUMS artificial oil islands must be replaced under a new, customer-financed Added Facilities Agreement, with THUMS or any successor customer providing all upfront capital and covering all removal-cost risk.

SCE argues that Rule 2 and the 1965 AFA require the customer (not general ratepayers) to fund these special, oil-field-specific facilities. With replacement estimated at $190 million + and likely to take a decade amid declining oil production, Senate Bill 1137 buffer-zone restrictions, and State/City plans to retire offshore drilling, SCE warns that utility financing could strand nine-figure assets and violate longstanding policy that added-facility costs cannot shift to the broader rate base.

On November 25 – in response to an ALJ request – the City of Long Beach and THUMS submitted a joint filing clarifying that the Long Beach Unit (the eastern Wilmington Oil Field, including the four THUMS islands), is owned by the State, held in trust by the City, and operated with THUMS as the field-contractor’s agent. They report that the State Lands Commission provides oversight but has declined to participate directly in this proceeding, instead deferring to the City in its trustee role.

Instant Analysis: This proceeding may create precedent for how the CPUC handles aging, oil-specific infrastructure in a phase-down environment, with potential ripple effects for other legacy Added Facilities Agreement.