WEDNESDAY AGGREGATE: Energy Storage PFM; Flex Alerts; New SoCalGas AMI Application

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Natural Gas Advanced Metering Infrastructure

SoCalGas filed an application seeking CPUC authorization to implement a new revenue requirement to support a systemwide Advanced Meter Infrastructure Replacement (AMIR) Project, arguing that its existing AMI system is approaching end-of-life and becoming technologically obsolete.

• SoCalGas proposes a coordinated replacement of more than six million gas meter communication modules and associated network, data-management, and cybersecurity systems to avoid a costly and operationally risky return to manual meter reading as battery failures and vendor support limitations emerge around 2030.
• SoCalGas estimates a total forecasted revenue requirement of $3.76 billion over the life of the project, driven by $2.1 billion in direct capital and O&M costs incurred between 2025 and 2034, with costs tracked through a new two-way balancing account.

The project would be executed in phased technology development and field deployment workstreams, peaking during mass deployment from 2030 to 2034. SoCalGas frames the project as necessary to preserve meter-to-cash functions, enhance operational visibility and cybersecurity, and maintain billing accuracy and safety.

Cost recovery would be allocated primarily to core customers on a meter-count basis, resulting in gradually increasing residential bill impacts through the early 2030s. These impacts would be followed by bill reductions later in the forecast period, subject to Commission approval.

INSTANT ANALYSIS: SoCalGas’ application is a preemptive, system-preservation filing that establishes a multi-billion-dollar cost trajectory years before AMI failures become operationally visible. By framing AMI replacement as unavoidable end-of-life remediation rather than discretionary modernization, SoCalGas is positioning the Commission to authorize a long-dated revenue stream with limited room for later prudence challenges, particularly once field deployment ramps in 2030.

SoCalGas's meter-count allocation assigns nearly all costs to core residential customers, reinforcing how non-commodity, systemwide infrastructure investments are increasingly treated as baseline service obligations rather than optional enhancements. If approved largely as filed, AMIR would add another durable fixed-cost layer that persists through electrification, load volatility, and customer attrition, illustrating how gas infrastructure costs are being stabilized in rates even as long-term gas demand remains uncertain.

Energy Storage

The California Energy Storage Alliance (CESA) filed a reply in R.15-03-011 defending its petition for modification of a 2017 decision (D.17-04-039) which governs how station power is treated for utility-scale energy storage facilities when batteries are idle.

• CESA argues that the current rules (developed when California had only a handful of storage projects) now impose unnecessary costs, billing complexity, and distorted operational incentives as the state has scaled to more than 13,000 megawatts of storage.
• Its reply responds to opposition from utilities and Cal Advocates, asserting that the petition fully complies with the CPUC's Rule 16.4 by presenting new, previously unknowable facts through a sworn expert declaration based on real-world operating experience that did not exist in 2017. (Rule 16.4 governs petitions for modification, allowing a party to request changes based on new or changed facts).
• CESA maintains that these new facts demonstrate that idle-period station power charges increase project risk and financing costs, which are ultimately embedded in capacity bids and passed through to ratepayers in a competitive procurement environment.
• While acknowledging that some near-term contract effects could benefit certain developers, CESA contends these impacts are overstated, unquantified, and outweighed by long-term reductions in storage procurement costs.

The filing also rebuts claims that CESA’s proposed framework is technically infeasible, arguing that utilities already use comparable metering and baseline methods. CESA concludes that modifying the idle station power rules would reduce deployment friction, better align incentives, and support California’s reliability and clean energy goals.

INSTANT ANALYSIS: This particular fight is about whether California’s tariff and rate-design framework can adapt once a resource moves from pilot scale to system-critical infrastructure. CESA is using Rule 16.4 to argue that storage has crossed that threshold, and that legacy station-power constructs are now embedding unnecessary financing risk into capacity bids that ultimately flow through to ratepayers. Pushback from the utilities and Cal Advocates implies institutional resistance to reopening settled cost-allocation logic, even as the underlying operating reality has changed. If the Commission accepts that lived operating experience can justify post-decision recalibration, this filing becomes a potential precedent for revisiting other legacy tariffs that were designed for a grid that may no longer exist.

Demand Response/Flex Alerts

The CPUC issued a ruling in its latest Demand Response docket (R.25-09-004) seeking party comments on a staff proposal to extend funding for California’s Flex Alert marketing campaign through 2026.

Flex Alerts are voluntary conservation appeals designed to reduce electricity demand during peak periods, particularly heat events, and have been funded by the Commission since 2021 as part of its broader grid reliability response following the outages of 2020.

• The staff proposal recommends maintaining the existing statewide paid media Flex Alert campaign for 2026 at the current annual budget of $22 million, funded by PG&E, SCE, and SDG&E, and administered by SCE under its existing contract with Doyle Dane Bernbach Communications Group.
• The proposal emphasizes rising electricity demand pressures from electrification and data center growth. Staff cites evaluation results that show near-universal public awareness of Flex Alerts and widespread voluntary load reductions during alert days, including significant reductions in air conditioning and appliance use.
• The proposal contains specific questions for parties on whether the program should continue in 2026, whether SCE should extend or renew the existing contract, what the appropriate 2026 budget should be, and whether additional conditions or program elements are needed for continued administration.

Comments are due January 20, with replies due January 30.

INSTANT ANALYSIS: The Commission is treating Flex Alert as a standing reliability tool funded through utility demand-side budgets. While Flex Alerts are activated based on CAISO operating conditions, those conditions are largely shaped by CPUC policy choices governing Resource Adequacy, procurement, electrification, and Demand Response design. In practice, the Commission has chosen to absorb this reliability function entirely on the retail side rather than distribute it across the wholesale-retail boundary it already regulates. As Flex Alert becomes a recurring tool, it normalizes voluntary conservation as part of California’s core reliability stack rather than a temporary emergency measure.

Utility Finances

PG&E filed a response to an ALJ ruling seeking clarification and additional information with regard to the utility's application for a limited capital structure adjustment (A.24-08-004).

In the filing, PG&E argues that its request is not a waiver under Rule IX.B of the Affiliate Transaction Rules triggered by an adverse financial event, but rather a narrow, accounting-based adjustment to how compliance with its authorized capital structure is calculated. (Recall that Rule IX.B is a provision of the CPUC’s Affiliate Transaction Rules that governs how a utility must maintain and demonstrate compliance with its authorized capital structure.)

• PG&E explains that it is seeking approval to exclude specific categories of non-rate-base financing (including long-term debt and equity charges associated with the Kincade and Dixie wildfires and a Department of Water Resources forgivable loan) from the equity-to-debt ratio used to determine return on rate base. (The DWR loan is an interest-free loan of up to $1.4 billion provided under Senate Bill 846 to support the license extension and continued operation of the Diablo Canyon Nuclear Power Plant. Repayment is expected from federal DOE nuclear credit funding and not from ratepayers.)
• According to PG&E, these items are excluded from rate base, subject to future recovery or forgiveness, and therefore should not distort capital structure compliance calculations. PG&E cites multiple Commission precedents where similar capital structure adjustments were approved outside the context of adverse financial event waivers, grounding the Commission’s authority in Public Utilities Code Section 701 and prior decisions.

PG&E further clarifies that it is not claiming the DWR loan or wildfire-related items constitute an adverse financial event, though it notes that, illustratively, the requested adjustments would amount to roughly a 1.2% change in equity and debt ratios if applied to mid-2024 figures.

INSTANT ANALYSIS: PG&E is pressuring the Commission to treat extraordinary wildfire-era financing and the DWR forgivable loan as structural exclusions (not emergency deviations) from capital-structure compliance under Rule IX.B. The practical effect is to keep PG&E “in compliance” with its authorized equity ratio while carrying large, non-rate-base obligations that neither earn a return nor reflect ongoing utility investment.

If the Commission affirms this framing, it will reinforce a now-consistent pattern: wildfire liabilities are being absorbed through accounting architecture rather than through formal adverse-event waivers, which reduces financing costs and scrutiny while normalizing long-duration carve-outs from capital discipline. In essence, the CPUC is allowing wildfire costs to be absorbed through capital-structure exclusions, rather than handled as episodic emergencies. This seems to portend a long-term shift in how California is governing utility finance under chronic, system-level risk.

Utility Back-Office Modernization

SoCalGas filed a response in A.25-05-004 to an ALJ ruling seeking additional detail on its request for incremental funding for the Customer Information System Replacement Program.

The filing explains how SoCalGas estimated labor and contractor costs for organizational readiness, training delivery, and surge staffing, and clarifies that these costs are expected to exceed the $46 million in Customer Information System O&M funding already authorized in the company's 2024 General Rate Case.

Consistent with D.24-12-074, which the CPUC adopted in 2024, SoCalGas is now seeking an additional $24.9 million through this separate application and proposes allocating the incremental costs using the Equal Percentage of Authorized Margin methodology rather than usage-based allocation. As such, SoCalGas is characterizing Customer Information System costs as a vital utility operation.

INSTANT ANALYSIS: SoCalGas’s Customer Information System filing shows how enterprise IT overruns migrate from forecast risk to rate recovery once the Commission authorizes a “come back later” pathway in a General Rate Case. By framing the additional $24.9 million as a continuation of already-approved O&M and allocating it via the EPAM methodology, SoCalGas positions CIS costs as non-usage, base-business infrastructure rather than a project with discrete beneficiaries. The result is that modernization risk is absorbed across customer classes through margin allocation, reinforcing a broader Commission pattern: large back-office systems increasingly behave like permanent utility infrastructure, not temporary projects subject to rigid cost discipline.

Energy Efficiency

SCE filed its semi-annual Independent Evaluator report in the CPUC’s new Energy Efficiency oversight rulemaking (R.25-04-010), covering third-party EE solicitations conducted between April and September 2025.

The report assesses SCE’s compliance with Commission directives governing solicitation transparency, Procurement Review Group oversight, and third-party portfolio minimums. The report reviews progress across local commercial, large industrial, and statewide midstream programs.

Independent Evaluators generally find that SCE’s solicitation processes align with CPUC policy, while noting some persistent frictions (long contracting timelines, implementer risk exposure, and ongoing tension between Total Resource Cost thresholds and Total System Benefit objectives).

The filing offers insight into how California’s EE procurement framework is functioning in practice, rather than announcing new policy or rate impacts. Those insights include acknowledgments that:

• Risk is being pushed downstream, timelines remain long, and policy signals remain ambiguous (page 11).
• Cost-effectiveness is negotiated, not assumed. The report arguably admits that Total Resource Cost is no longer a neutral metric, it's a constraint that must be managed, cured, or worked around (page 12).
• Performance-based structures are shifting risk allocation, i.e., protecting customers and placing the onus on implementers (page 30).
• Budget authority ≠ market clearing – process complexity, risk allocation, and cost-effectiveness screens can strand capital (page 30).

INSTANT ANALYSIS: SCE’s report depicts California’s energy-efficiency regime as a managed procurement system in which outcomes are shaped by process design, cost-effectiveness constraints, and risk allocation rather than budget authority alone. Although solicitations align with CPUC directives, the record highlights persistent friction. The result is a portfolio that is procedurally dense, slow to convert authorized funding into executed programs, and governed primarily by negotiation and screening mechanics rather than straightforward deployment.