WEDNESDAY AGGREGATE: Transmission Planning; SCE Rates; Biomethane Costs

Below are several items on our radar:

• The CPUC is mapping hypothetical resource portfolios to physical transmission busbars;
• SCE is absorbing a $932 million accounting swing from collapsing Resource Adequacy values;
• Utilities are reframing electrification as rate stabilization rather than grid stress;
• A new distribution framework is about to formalize “least-regrets” early grid buildouts; and
• Biomethane policy is forcing a core question: will California socialize gas infrastructure like it did renewables, or are affordability concerns too dire?

INTEGRATED RESOURCE PLANNING

Administrative Law Judge Colin Rizzo issued a ruling in the Integrated Resource Planning docket inviting parties to submit comments on the preliminary busbar mapping of electricity resource portfolios for use in the CAISO's 2026-2027 Transmission Planning Process.

ALJ Rizzo's ruling follows a September 30 ruling that asked for input on proposed portfolios (a massive number of parties filed October 31 reply comments on that ruling, which are available here). The current ruling seeks feedback specifically on how resources are being assigned to transmission busbars, a key step in aligning resource planning with transmission needs

CPUC staff will host a webinar on November 12 to explain the preliminary mapping results. Comments on the latest ruling are due November 21.

INSTANT ANALYSIS: The CPUC is moving from abstract resource portfolios into the physical realities of the transmission system, asking parties to weigh in on how planned resources are mapped to specific busbars for the CAISO’s 2026–2027 Transmission Planning Process. That placement determines whether projects are considered deliverable, where grid upgrades are triggered, and who pays for them. With no reply comments allowed and a short fuse (November 21), stakeholders will need to highlight misalignments, push for preferred interconnection assumptions, or defend against siting that might disadvantage their portfolios. In short, this comment opportunity could be a low-profile (but high-leverage) moment where modeling choices start to harden into infrastructure decisions.

SCE RATES

SCE filed Advice Letter 5664-E (available here) to notify the CPUC that its Energy Resource Recovery Account balance exceeded the 4% "Trigger Point" in September 2025 and was expected to exceed the statutory 5% Assembly Bill 57 threshold by October 31 (SCE filed the advice letter on October 30, FYI).

The trigger was reached because the ERRA and Portfolio Allocation Balancing Account (PABA) balances reflect updated Market Price Benchmarks for retained Resource Adequacy and Renewable Portfolio Standard resources, which were significantly lower than the forecast values that were used to set 2025 rates.

As of September 30, SCE's ERRA trigger balance showed an undercollection of $280 million (or 4.8% of its 2024 generation revenues), above the trigger level. The primary causes were true-ups tied to final 2025 Market Price Benchmarks: Resource Adequacy benchmark values dropped by 34-72% compared to forecasts, and RPS values fell about 10%, creating large accounting adjustments between the ERRA and the PABA.

Notably, SCE does not seek a rate change at this time. It states that the balance will resolve when new 2026 ERRA Forecast rates take effect on January 1, 2026, pending a final decision in A.25-05-008 (which is expected on December 18). Those rates will incorporate the year-end ERRA and PABA balances, eliminating the undercollection.

INSTANT ANALYSIS: The trigger was caused not by out-of-control spending but by an October 1 true-up to 2025 Market Price Benchmarks (via a steep collapse in Resource Adequacy values, down 34–72% from forecasts), which shifted nearly $932 million between ERRA and PABA. This is not rate shock but rather a signal of procurement volatility and accounting whiplash inside SCE’s portfolio. The bet is that once 2026 ERRA rates are implemented, the undercollection will disappear. But if the CPUC misses its December deadline on SCE’s ERRA forecast application, (or balances worsen in during the next several weeks), the situation could result in a trigger application with legitimate rate impacts.

DISTRIBUTED ENERGY RESOURCES

PG&E and SCE each filed draft "Electrification Impacts Study: Part 2" reports in the CPUC's High DER Future proceeding (R.21-06-017). The reports show that electrification will require massive-but-manageable upgrades to the state's distribution grid, with costs that can be partially offset by load growth and demand flexibility.

• Both utilities model scenarios through 2040 and find total distribution investments of about $12 to $13 billion for SCE and $23 to $31 billion for PG&E.
• Secondary system costs (service transformers and new customer connections) make up the majority of future spending, and both utilities note that project volumes must scale five to 10 times above historical levels. The utilities claim that equity scenarios modestly increase costs but do not significantly strain grid infrastructure.
• The utilities also claim that demand flexibility (especially when orchestrated at the circuit level) can defer $1 to $1.8 billion in upgrades and cut local peaks by up to 1.4 gigawatts (SCE) or approximately 2.8 GW systemwide (PG&E), while helping keep future rates flat (or even reduce distribution rates by up to 25% by 2040), as electrification spreads fixed costs over more load.

Both studies frame electrification not as a grid crisis, but as a logistical and planning challenge requiring faster execution, workforce and supply-chain scaling, and better tools to manage flexible loads.

INSTANT ANALYSIS: Demand flexibility (electric-vehicle load shifting, storage dispatch, HVAC modulation) is now a genuine capital deferral tool. When applied at the circuit level (not just system peaks), the utilities claim that demand flexibility can shave 1–3 gigawatts off local peaks and defer $1–2 billion in upgrades, but only if it’s “orchestrated,” meaning utilities control it like firm capacity, not voluntary “demand response.” Additionally, utilities are framing electrification not as a threat, but as a rate stabilizer.

DISTRIBUTION PLANNING

The CPUC issued Draft Resolution E-5414, which approves with modifications a joint proposal from PG&E, SCE, and SDG&E to implement a uniform scenario planning framework within the annual "Distribution Planning and Execution Process," starting in the 2025–2026 cycle.

• The framework establishes three standardized load scenarios: low, base, and high, premised on consistent use of Integrated Energy Policy Report forecasts and pending load categories (A–C), to help utilities identify distribution grid needs under varying future conditions.
• Utilities would then use these scenarios to inform a single investment plan, guided by a transparent “decision-logic” structure (drawn from SCE’s model) that explains when to advance, defer, or resize projects depending on whether High or Base scenario needs emerge.
• The draft resolution rejects fully utility-specific frameworks and instead imposes a common structure across all three investor-owned utilities, while allowing utility-specific implementation details. The draft resolution also requires that all planned projects be tied to a scenario and justified in the "Distribution Upgrade Project Report," with utilities reporting grid needs for each scenario in the "Grid Needs Assessment" both before and after mitigations.
• Draft Resolution E-5414 declines to mandate additional scenarios like demand flexibility or policy compliance in this initial cycle but leaves room to add them later once methodologies mature.

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

INSTANT ANALYSIS: This draft resolution formalizes scenario planning in utility distribution planning. Starting in the 2025–2026 cycle, PG&E, SCE, and SDG&E must run Low, Base, and High load scenarios (tied to pending load categories and IEPR forecasts) and translate them into a single investment plan using transparent logic. That means utilities now have formal CPUC backing to plan proactively for electrification-driven load growth but must justify every project by pointing to which scenario (especially High) triggered it, and show how it differs from the Base case.

• If adopted, Draft Resolution E-5414 would effectively authorize a “least-regrets” early grid buildout while installing guardrails against overbuilding. Demand flexibility, DER policy compliance, and more aggressive scenarios are deferred to future cycles.
• For stakeholders, this is where distribution planning shifts from reactive upgrades to probabilistic infrastructure strategy. Pending load data becomes a capital driver, and early substation and circuit buildouts can now be justified under High Scenario logic, provided they are transparently disclosed.

This item pairs well with the pending load frameworks of Draft Resolution E-5413, which the CPUC is also scheduled to consider on December 4 (see our summary here).

BIOMETHANE

In November 3 reply comments, parties in the CPUC's Biomethane Standards proceeding (R.13-02-008) continued to provide input on how to reduce interconnection costs for biomethane projects. Parties largely agree on the need for efficiency and process improvements but diverge over whether ratepayers should bear more of the costs.

• PG&E: PG&E acknowledges that rate-basing interconnections could reduce developer costs by avoiding the federal tax treatment, but warns that shifting these costs to ratepayers requires further analysis to ensure actual customer benefit. PG&E instead emphasizes process improvements e.g., standardized interconnection skid designs, modularization, third-party construction options, and selective deployment of reverse compression. PG&E also notes that many developers face delays unrelated to utility activity, which increase standby costs.
• SoCalGas/SDG&E (Sempra Utilities): The Sempra Utilities support allowing utilities to rate-base interconnection facilities, claiming it would eliminate the 24% tax gross-up under federal income tax rules that developers currently pass through in biomethane pricing. SoCalGas/SDG&E argue that rate-basing could lower overall costs without compromising safety, and they also support rate-basing reverse-flow compression equipment to improve system flexibility. At the same time, the Sempra Utilities push back against developers’ criticisms of utility supervisory fees, arguing such oversight is essential for safe construction and compliance with federal and CPUC standards.
• Dairy Cares: Dairy Cares opposes broad rate-basing of interconnection costs but supports expanding the Biomethane Monetary Incentive Program instead. Dairy Cares argues that utilities should only recover interconnection-related costs from ratepayers when a direct, systemwide benefit can be demonstrated under the Public Utilities Code. If rate-basing is expanded, Dairy Cares recommends applying strict cost controls and clear benefit thresholds in a dedicated proceeding.
• Sierra Club: The Sierra Club urges the Commission to reject rate-basing and any expansion of subsidies for interconnection or the incentive program. It argues that biomethane is costly, delivers uncertain climate benefits compared to electrification, and relies on finite organic waste resources. Sierra Club stresses that ratepayers could face more than $1.5 billion annually in biomethane costs under existing procurement mandates and objects to increasing that burden through interconnection subsidies. Sierra Club also opposes proposals for “backflow” compression investments without rigorous cost-benefit and climate analysis.
• Leadership Counsel for Justice and Accountability (LCJA): LCJA argues strongly against shifting interconnection or related infrastructure costs to ratepayers. LCJA contends that developers (not customers) should continue to pay these expenses, particularly given rising affordability concerns for low-income households. LCJA also opposes expanding non-ratepayer-funded incentives such as the Biomethane Monetary Incentive Program, arguing that limited public funds should instead support decarbonization and affordability programs for low-income customers.

INSTANT ANALYSIS: The tensions in this proceeding place the CPUC at a pivotal decision point: whether to socialize biomethane infrastructure costs like it did for renewables or to act with abundant caution as serious affordability concerns continue to mount.

CODA

Don't miss our recent standalone posts on:

• PG&E's advice letter filings for natural gas transportation rates effective January 1, 2026;
• The latest twists and turns with the Ivanpah solar facility;
• Stakeholders' comments in the CPUC's Natural Gas Price Spike investigation regarding PG&E's Core Procurement Incentive Mechanism and SoCalGas's Gas Cost Incentive Mechanism; and
• A motion from Californians for Green Nuclear Energy to disqualify the judge in PG&E's latest Diablo Canyon cost-recovery proceeding.

Additionally our Monday Aggregate from November 3 covers a new proposed decision in the above-mentioned Diablo Canyon proceeding, SDG&E's proposed natural gas rates for January 1, and more.