MONDAY AGGREGATE: Edison's AMI 2.0 Program; an SPD-37 Fight; and PG&E's Diablo Canyon Year 3 Filing
Today's briefing covers:
- SCE's application to deploy its AMI 2.0 program;
- More conflict under Resolution SPD-37's requirements;
- PG&E's third annual Diablo Canyon extended operations application;
- A CPUC ruling on 2026 RPS Procurement Plans; and
- Valuation methodologies for Pre-2019 Banked RECs.
ADVANCED METERING INFRASTRUCTURE
SCE filed an application to deploy its AMI 2.0 program, driven by the looming obsolescence of its existing smart meters, which will lose vendor support by 2035.
- Failure rates are rising across SCE's fleet of approximately 5.7 million meters. The sole replacement vendor isn't committed beyond 2029, the proprietary 1.0 network can't support a hybrid mix of old and new meters, and each year of delay past 2029 adds approximately $140 million in nominal costs deploying meters that will be stranded anyway.
- SCE evaluated four replacement approaches and selected a "value upgrade" — next-generation meters with edge computing, an IP-based mesh/cellular/satellite network on open standards, and software for demand flexibility, fault detection, and granular usage analytics, claiming an incremental benefit-cost ratio of 7.56 versus baseline replacement.
- A mass installation would run from 2029–2033, preceded by deployment readiness and small-scale field validation in late 2028. SCE's total requested revenue requirement is $1,865 million over 2026–2033, with an average bundled rate impact of about 2.5%. SCE proposes a 110% reasonableness threshold on $444.6 million in capitalized software costs, with tiered recovery mechanisms for overruns.
The day after filing, SCE moved to establish a memorandum account to track O&M and capital costs for deployment readiness that are incurred before a final decision (proposed for September 2027). Recovery is not automatic; recorded amounts transfer to a balancing account only upon final decision and are subject to reasonableness review. Critical context: the CPUC denied SCE a similar memorandum account in a 2025 General Rate Case decision (D.25-09-030). SCE is reframing its request around deployment costs rather than planning costs.
INSTANT ANALYSIS: SCE is moving ahead of a 2027 decision and wants cost protection now. The memorandum account is the key: approximately 18 months of pre-decision spend after a prior GRC denial on essentially the same mechanism. The real conflict is scope. SCE is turning a meter replacement into a grid-edge platform with demand control, fault detection, and DER integration. The 110% software cost threshold and the 7.56 BCR will draw heavy intervenor scrutiny.
UNDERGROUNDING PROJECTS
The Joint IOUs (PG&E, SCE, and SDG&E) responded to protests of their application to establish a standardized Benefit-Cost Ratio methodology, audit process, and cost-recovery framework for undergrounding projects under Resolution SPD-37. (See CRI's coverage of the application here.)
MC
The IOUs defend their methodology as compliant with the CPUC's Risk-Based Decision-Making Framework due to its use of risk-averse scaling, a preferred discount rate alongside the three required rates, and an uncertainty factor to address modeling limitations.
The utilities propose moving O&M savings into the Benefit-Cost Ratio denominator as a cost offset and including broad enterprise risk-reduction benefits in the numerator, arguing the Risk-Based Decision-Making Framework requires reflecting the full set of benefits from incurred costs.
The utilities oppose intervenor attempts to expand the scope beyond SPD-37 requirements, calling Cal Advocates' proposed evaluation criteria vague and EPUC's five proposed issues redundant. On auditing, the utilities argue that portfolio-level compliance is sufficient and oppose project-level auditing of risk-reduction benefits as infeasible (those values are counterfactual estimates, not observable outcomes).
The utilities also seek to grandfather previously-scoped in-flight projects into the Expedited Undergrounding Plan even where updated risk models no longer support them, and defend the 2% variance threshold by noting the Commission approved 15% variance for PG&E system hardening in the 2020 General Rate Case.
INSTANT ANALYSIS: The utilities are keeping this application in a policy lane, not a cost-adjudication lane, preserving flexibility and limiting near-term ratepayer scrutiny. On substance, they're anchoring to the Risk-Based Decision-Making Framework as cover while preserving discretion inside it. Risk scaling, uncertainty bands, portfolio-level judgment, and the previously-scoped projects carve-out all point to the same outcome: the IOUs maintain the ability to justify undergrounding even when Benefit-Cost Ratio signals are marginal.
Moving O&M savings into the denominator and loading broad enterprise risk benefits into the numerator expands the universe of "cost-effective" projects without changing the headline metric. Portfolio-level auditing with no project-level compliance requirement means the accountability regime is as flexible as the methodology itself. Intervenors are asking "are these projects actually worth it?" but utilities are saying "does the methodology follow the rules we were given?"
DIABLO CANYON
PG&E's third annual Diablo Canyon extended operations application seeks $595 million in net revenue requirement for 2027. Total forecast costs are $1.34 billion, offset by $751 million in CAISO market revenues (down from prior years while operational costs held flat).
The statewide non-bypassable charge allocates $340 million to PG&E, $208 million to SCE, and $47 million to SDG&E. The system average bundled rate impact is 0.4%. Monthly residential bill increases are: $1.08 (PG&E); $0.65 (SCE); and $0.26 (SDG&E).
The plant ran well in 2025, with an 89.7% capacity factor across a double refueling outage year. PG&E values the statewide Resource Adequacy contribution at about $276 million and projects 34.5 million metric tons of avoided emissions through 2030.
On the Volumetric Performance Fee side, PG&E collected $178.4 million in 2025 and spent $144 million. Two VPF-funded programs blew their forecasts:
- A major back-office technology overhaul (migrating PG&E's work management systems to a new platform) landed at $32.3 million against a $10 to $15 million range; and
- Incremental grid safety spending (aerial inspections and emergency outage response above what the GRC funds) hit $64.5 million against $40 to $60 million.
Neither variance triggered any consequence under the current framework.
INSTANT ANALYSIS: The declining CAISO revenue trend is the number to watch. Operational costs aren't rising meaningfully: revenues are falling, and the difference lands directly on the non-bypassable charge. Bill impacts look modest in isolation but the charge is fully non-bypassable across all load, cumulative through 2030, and indexed to a market revenue forecast that keeps missing.
RENEWABLE PORTFOLIO STANDARD
The CPUC issued a ruling directing all retail sellers to file standardized 2026 RPS Procurement Plans by June 12. Cornerstone RPS requirements remain:
- Sellers must demonstrate progress toward 60% RPS by 2030 and 100% zero-carbon by 2045, with at least 65% of RPS procurement from contracts of 10+ years; and
- Planning horizons extend through 2036.
Every retail seller must provide renewable net short calculations, risk assessments with severity ratings and mitigation timelines, Minimum Margin of Procurement methodology, bid solicitation protocols including Least-Cost Best Fit criteria, cost quantification using standardized templates, and transportation electrification forecasts.
Community Choice Aggregators and Electric Service Providers face the same reporting depth as investor-owned utilities, including cost data the CPUC uses for its annual Padilla Report to the Legislature. The ruling explicitly states that incomplete plans will be rejected, and non-compliant sellers may face fines.
A notable new element is a table that requires retail sellers to cross-reference their RPS Plans against their individual Integrated Resource Plans due August 10. This creates a direct accountability link between the two proceedings.
For large IOUs only, the ruling requires their plans to include detailed Senate Bill 1174 transmission and interconnection delay reporting e.g., project-level delay reasons, median delay times, dependent renewable/storage capacity at risk, permitting reform analysis, and mitigation efforts.
Drafts are due June 12, with comments due July 13.
INSTANT ANALYSIS: The CPUC is building a comparison engine. Standardized inputs, uniform templates, and the new IRP cross-referencing table mean every retail seller's procurement position, risk exposure, and cost structure will sit side by side. The 65% long-term contracting rule is key: sellers with short-term-heavy portfolios will have their gaps quantified and visible. The SB 1174 transmission reporting will expose exactly where and why utility interconnection delays are holding up renewable and storage capacity. D.26-02-057's directives (supplemental procurement) also show up in the IRP alignment table.
ERRA/PCIA REFORM
The CPUC issued a ruling to introduce an Energy Division staff report. The report proposes four valuation methodologies for Pre-2019 Banked Renewable Energy Credits for use in calculating the Power Charge Indifference Adjustment.
Parties must comment on the report alongside opening briefs by May 22, with reply briefs due June 5. The Commission is asking:
- Whether staff accurately characterized positions and precedent;
- Which methodology best captures REC value;
- What modifications are warranted, and;
- Whether a non-zero valuation creates problems for RPS compliance and LSE procurement (including whether compliance deferrals could mitigate those concerns).
INSTANT ANALYSIS: This is a high-impact PCIA decision. How the Commission values these banked RECs directly affects the indifference calculation and, by extension, exit fees for departing load. Investor-owned utilities will likely argue that legacy procurement carries real value that should be reflected. Community Choice Aggregators and Electric Service Providers will argue it's a sunk cost that inflates the PCIA. The Commission's explicit focus on RPS compliance and procurement knock-on effects indicates awareness that getting the valuation wrong could distort market behavior beyond just cost allocation.