MONDAY AGGREGATE: Diablo Canyon; Distribution Planning; SDG&E's 2026 Natural Gas Rates and PPP Surcharge

Here is what's on our Monday radar. For a full review of last week's CPUC voting meeting, go here.

Today's items are a microcosm of California’s reliability strategy and how it's running on multiple tracks simultaneously: extending nuclear baseload at Diablo Canyon, mapping new load before it arrives (distribution planning), and cautiously testing new financing mechanisms for electrification.

DIABLO CANYON COST RECOVERY

Administrative Law Judge Chang issued a proposed decision approving PG&E's request to recover $382.233 million in 2026 customer rates to support the continued operation of the Diablo Canyon Power Plant under the extension authorized by Senate Bill 846 and prior CPUC decisions.

The authorized revenue requirement reflects forecasted operations and maintenance costs, statutory fees, nuclear fuel, and required substitution capacity for planned outages, offset by market revenues from power sales. Costs are allocated across the service territories of PG&E, SCE, and SDG&E.

The PD continues the regulatory framework established in a 2023 decision (D.23-12-036), which authorized Diablo Canyon Power Plant operations until 2029/2030 pending federal license approvals. The PD also incorporates directives from later decisions requiring PG&E to justify costs and differentiate clearly between:

• "Transition" or preparatory costs paid by government funding (e.g., the SB 846-authorized $1.4 billion state loan); and
• Extended operation costs recoverable from ratepayers.

The PD finds PG&E's 2026 O&M forecast (totaling $563.9 million) to be reasonable but directs PG&E to provide more detailed justification for any projects over $1 million in future filings.

• The PD also approves statutory payments required under SB 846, including $113.97 million in Fixed Management Fees; $266.566 million in Volumetric Performance Fees; and $75 million for a liquidated damages fund, which protects ratepayers against unreasonable outage replacement power costs.
• The PD also adopts PG&E's proposed methodology to escalate the Fixed Management Fee using the Consumer Price Index (CPI-U) rather than the electricity capital cost index previously used, finding the CPI-U more stable and appropriate for a non-capital payment.

Last, the PD approves PG&E's calculated non-bypassable charge to recover net Diablo Canyon Power Plant costs from all customers, including those served by Community Choice Aggregators and Direct Access providers.

PG&E forecasts a slight reduction in average system rates in 2026 (but only net of high expected market revenues and full facility availability). Comments on this item are due November 20. The earliest the CPUC will consider the PD is December 4.

INSTANT ANALYSIS: The CPUC is institutionalizing Diablo Canyon's extended life as a cost-managed reliability asset. Rate impacts appear to be minimal (under PG&E's assumptions of high market revenues and full facility availability) and the non-bypassable charge remains intact. For CCAs, DA providers, and large customers, Diablo Canyon costs are becoming an embedded part of the rate landscape.

DISTRIBUTION PLANNING

The CPUC issued Draft Resolution E-5413, which approves with modifications a joint proposal submitted by PG&E, SCE, and SDG&E to create a "pending loads" category in the utilities' distribution planning process. This new process would capture anticipated but not-yet-certain electrical demands (more specific than statewide forecast trends, but less certain than formal service requests).

The draft resolution aims to improve medium-term distribution grid planning (years two through five), allowing utilities to proactively identify where load growth is likely to occur so upgrades can be planned in advance without unnecessary overbuilding.

The draft resolution implements a uniform, four-hour tier framework statewide (based largely on Edison's proposal but using PG&E's detailed criteria), which classifies pending loads based on data quality and confidence:

• Category A: High-confidence, customer-driven projects with specific load, location, timeline, and permit data (these may exceed the Integrated Energy Policy Report, or "IEPR," forecast);
• Category B1: Medium-confidence customer projects (also allowed to exceed the IEPR forecast);
• Category B2: Study-based or regulatory-driven load projections using customer-related data (cannot exceed the IEPR unless located in a "hot spot"); and
• Category C: Low-confidence early-stage projects or general studies (may only assist in disaggregating IEPR forecasts, never exceed them).

Draft Resolution E-5413 also formally defines hot spots (geographic areas with multiple pending or known loads and infrastructure constraints) and allows certain Category B2 load forecasts in these areas to exceed the IEPR cap to support proactive grid investments. Utilities must identify and justify these hot spots annually in their Grid Needs Assessment and Distribution Upgrade Project Report filings and report all pending loads by category, location, projected in-service year, and data source.

While Draft Resolution E-5413 allows utility-specific data sources, it requires PG&E, SCE, and SDG&E to adopt the same structure, criteria, and reporting standards beginning in the 2025-2026 planning cycle. SDG&E, which initially proposed only using medium-/heavy-duty vehicle electrification forecasts, must incorporate customer-based pending load data similar to PG&E and SCE.

Last, the draft resolution strengthens oversight and reporting, requiring annual updates, standardized data tracking, and a formal evaluation in 2027 on how many pending loads became actual service requests plus timing accuracy and risk mitigation where loads do not materialize.

The earliest the Commission will consider this item is December 4.

INSTANT ANALYSIS: If adopted, this draft resolution would help modernize the CPUC's planning toolkit for the age of data centers and electrified infrastructure. While the draft resolution doesn't greenlight spending, it builds the process for a more transparent, anticipatory grid-planning regime. Future money will likely move first in Categories A and B1, because those are the early indicators of where utilities will break ground and where developers and large customers will be expected to co-invest or align.

SDG&E NATURAL GAS RATES for JANUARY 1, 2026

SDG&E filed Advice Letter 3463-G (available here) to update its natural gas transportation rates effective January 1, 2026.

• For core customers, SDG&E proposes a net $12.3 million decrease, driven mainly by a reduction in a Core Fixed Cost Account undercollection, partially offset by increases in SDG&E's Safety Enhancement Capital Cost Balancing Account and Residential Uncollectible Balancing Account.
• For noncore customers, SDG&E seeks a $7.5 million increase, primarily due to undercollections in the Residential Uncollectible, Safety Enhancement, and Greenhouse Gas Balancing accounts.

Overall, total gas transportation revenue requirements would rise by $4.1 million (0.5%), translating to a 0.4% increase for core customers and a 2.9% increase for noncore customers.

SDG&E will file a final version of its request prior to January 1 that consolidates all authorized revenue-requirement changes. Protests are due November 20.

Below are illustrative rates in $/therm.

SDG&E PUBLIC PURPOSE PROGRAM RATES

SDG&E also filed Advice Letter 3462-G (available here) to update its Public Purpose Program (PPP) gas surcharge rates, which fund state-mandated programs e.g., low-income assistance, energy efficiency, and research & development.

SDG&E's updated surcharge rates will take effect January 1, 2026. SDG&E proposes to increase PPP revenue recovery to $85.9 million (up about $10.2 million from 2025). Major cost drivers include:

• $23.6 million for the California Alternate Rates for Energy (CARE) low-income discount program;
• $15.1 million for the Energy Savings Assistance program;
• Approximately $30.8 million for energy efficiency;
• $14.4 million for a new San Diego Regional Energy Network;
• $1.2 million for RD&D;
• $0.7 million for a statewide Market Transformation program; and
• $0.1 million CPUC and California Department of Tax and Fee Administration costs.

Below are the anticipated changes. Protests to this filing are due November 20.

CLEAN-ENERGY FINANCING

Administrative Law Judge Toy issued a proposed decision that approves with modifications a Tariff On-Bill financing pilot advanced by SCE. The PD rejects similar proposals from SDG&E, SoCalGas, and Silicon Valley Clean Energy.

The Tariff On-Bill concept allows customers to install clean-energy upgrades (e.g., heat pumps and efficiency measures) with no upfront cost, paying instead through a fixed charge on their utility bill tied to the property, not the individual.

The PD finds Edison's proposal to be the only one sufficiently developed to test this model. The PD limits participation to approximately 200 residential sites and requires bill neutrality (meaning customers' total bills must not increase as a result of participating). The PD adds further customer protections, savings verification requirements, and reporting rules.

PG&E did not propose a pilot. The rejected proposals had design flaws or did not align with CPUD directives. Comments on this item are due November 20. The earliest the CPUC will consider this item is December 4.

INSTANT ANALYSIS: This PD is a cautious green light, not a broad endorsement. If SCE's pilot demonstrates real savings, low defaults, and manageable administrative costs, tariffed on-bill financing could become a new cost-recovery tool for electrification, especially for households that can't access credit or capital.

MID-TERM RELIABILITY

The CPUC issued Draft Resolution E-5428, which authorizes SCE's request to enter eight new Mid-Term Reliability resource contracts and one amendment to an existing battery storage contract. These agreements arose from Phases 2 and 3 of Edison's Mid-Term Reliability Request for Offers and include a mix of solar photovoltaic projects and co-located (or standalone) Battery Energy Storage Systems.

These projects were developed by EDF Renewable Energy, Intersect Power, and Leeward Renewable Energy and will provide renewable energy, Resource Adequacy capacity (or both), with contract terms ranging from 10 to 15 years, and expected online dates beginning in 2026 and 2027.

Draft Resolution E-5428 also approves an amendment to the Gateway battery storage contract to extend its delivery deadline following a 2024 thermal incident at the facility that the CPUC and EPA are currently investigating.

These contracts count toward Edison's procurement obligations under two the CPUC's original "mid-term reliability" decision (D.21-06-035) and a supplemental procurement decision (D.23-02-040) that arose when the state was experiencing a reliability gap in the middle of this decade due to:

• The retirement of gas plants and the (since-reversed) decommissioning of the Diablo Canyon Power Plant;
• Delays in new clean resources due to supply-chain problems and other issues; and
• The need to bridge the system from now through the realization of long-term decarbonization goals.

The earliest the Commission will consider this item is November 20. Contract costs are confidential.

INSTANT ANALYSIS: These contracts strengthen SCE's compliance posture but they also highlight how dependent California's reliability strategy has become on large-scale solar-plus-storage procurement. The Gateway extension is a reminder that battery safety and operational risk are now serious reliability variables, not edge cases.