MONDAY AGGREGATE: CPUC Begins Setting Cost-Recovery Parameters as Undergrounding and Securitization Frameworks Take Shape

Today's briefing covers:

• Benefit-Cost Ratio calculations for electrical undergrounding;
• A PD authorizing SCE to issue almost $2 billion in recovery bonds to finance Woolsey Fire costs;
• Energy Division's updated SERVM inputs for the RA docket;
• A distortion in the Diablo Canyon cost-recovery framework;
• The BioMAT's future (or lack thereof); and
• Interstate natural gas capacity.

UNDERGROUNDING

CPUC President John Reynolds issued a scoping memo that establishes the framework for A.26-02-005, in which the CPUC will evaluate joint proposals from PG&E, SCE, and SDG&E to implement key outstanding elements of the Senate Bill 884 undergrounding program.

This is the first proceeding to define the cost-effectiveness framework for SB 884 undergrounding at scale, and it will drive billions in ratepayer exposure. The proceeding addresses three main issues:

• How to standardize Benefit-Cost ratio (BCR) calculations for undergrounding projects;
• What audit framework should govern utility cost tracking; and
• What conditions should apply to cost recovery through the program's one-way balancing account.

These questions trace back to prior CPUC guidance in Resolutions SPD-15 and SPD-37 and from the foundational BCR work developed in the Commission's Risk-Based Decision-Making Framework.

Attached to the scoping memo is a white paper on BCR Methodology, the first substantive Staff position on the BCR question, and the document that will anchor intervenor counter-proposals, which are due June 9. Staff recommends adopting "Method 3," the Disaggregated Formulation, which places O&M Costs in the denominator and O&M Savings in the numerator separately, and pairs that formula with the "No-Build Baseline," measuring incremental benefits only against existing funded programs. Both choices constrain utility flexibility at scale.

The ruling adopts an accelerated track, with a proposed decision expected in October, and an official vote targeted for November 19. The schedule aligns with utility timelines, particularly PG&E's expected Q3 2026 undergrounding plan filing and its planned shift of cost recovery from General Rate Cases to the SB 884 framework, beginning in 2028.

INSTANT ANALYSIS: The CPUC is not deciding whether to underground. It is deciding how the economics get constructed and policed, and that will determine the scale, pace, and recoverability of billions in future spending.

• The BCR methodology is the center of gravity, and the Staff white paper is the terrain. Staff has made the first move, recommending a specific formula and baseline that constrain how utilities can present cost-effectiveness. The recommendation to adopt the “Disaggregated Formulation” (Method 3) separates O&M costs and savings rather than netting them, avoiding the mathematical distortions that can arise when large O&M savings collapse the denominator in alternative formulations.
• The No-Build Baseline is just as important. It forces projects to measure incremental benefits against existing funded programs, preventing utilities from claiming credit for risk reductions already being paid for by ratepayers. That is a direct check on double counting and materially lowers headline BCRs in high-mitigation areas.
• Staff also has a broader concern with baseline manipulation. The white paper points to inconsistent baseline application in utility filings as a source of skewed results that can favor capital-intensive solutions like undergrounding over lower-cost alternatives.

The audit and cost-recovery tracks carry equal importance. The one-way balancing account is already a powerful instrument; the question now is how much friction the CPUC adds around it. Strong audit rules and conditionality favor ratepayer advocates. Flexible treatment favors the utilities and accelerates deployment. This is a direct negotiation over who bears risk when costs overrun or benefits fail to materialize.

The accelerated pace tells you that the CPUC wants to keep this at a policy level rather than build a litigated evidentiary record. That favors parties who can shape the written narrative early (and disadvantages intervenors who need time to develop quantitative counter-proposals to utility-drafted BCR frameworks). The June 9 counter-proposal deadline is the first true test of whether intervenors can meaningfully challenge Staff’s opening position.

On the intervenor side, EPUC filed a protest. EPUC's presence shows where the pressure will concentrate: not on whether undergrounding is good policy, but on whether the BCR inputs, audit rigor, and balancing account conditions adequately protect against cost pass-through that ratepayers can't absorb.

TL;DR: This proceeding will define the rules for undergrounding as an asset class in California. Staff has presented a framework that diminishes utility flexibility and reduces some of the methodological advantages that have historically supported large capital builds. If that framework holds, undergrounding can scale on more defensible terms. If it weakens, the conflict shifts back to whose assumptions control the math.

WILDFIRES

The CPUC issued a proposed decision authorizing SCE to issue approximately $1.951 billion in recovery bonds to finance 2018 Woolsey Fire costs under Assembly Bill 1054. The total includes $1.639 billion in Wildfire Expense Memorandum Account costs, $299.2 million in pre-securitization financing, and $12.7 million in upfront costs.

Rather than recovering these costs through traditional ratemaking, SCE will monetize a dedicated revenue stream ("recovery property") backed by a non-bypassable Fixed Recovery Charge on most customers. The PD finds the structure meets the three-part statutory test:

• Costs are just and reasonable;
• Issuance is in the public interest; and
• Securitization lowers total customer costs on an NPV basis.

Compared to traditional rate-base financing at SCE's 7.59% authorized return, estimated ratepayer savings are approximately $811 million Net Present Value. The more conservative comparison (against five-year amortization at the same discount rate) yields approximately $304 million NPV.

The financing structure requires SCE to transfer recovery property to a bankruptcy-remote Special Purpose Entity, which issues the bonds and services debt from Fixed Recovery Charge revenues. The charge applies to all non-exempt existing and future customers, is irrevocable, and adjusts at least annually through a true-up mechanism. CARE and FERA customers are explicitly exempt. Departing load customers (Direct Access entities and Community Choice Aggregators) remain obligated under applicable tariffs. Expected transaction maturity is capped at 22 years; legal final maturity cannot exceed 33 years.

Comments are due April 30. The earliest the CPUC will consider this item is May 14.

INSTANT ANALYSIS: This is a textbook AB 1054 securitization, but at real scale. SCE converts its Woolsey liabilities into a bond-backed revenue stream outside rate base, trading equity returns for cheaper debt. The $811 million NPV savings claim holds directionally, but it's the favorable baseline. The $304 million figure, comparing against five-year amortization, is the more conservative read, and both numbers carry uncertainty.

The non-bypassable charge attaches to essentially all load, survives migration, and binds future customers. That calcifies wildfire costs as system-level obligations rather than utility-specific exposures, and keeps pressure on departing load cost responsibility arguments for years.

Duration is the number the savings narrative glosses over. Expected maturity runs to 22 years, with a 33-year legal cap. Near-term bill relief is real; so is the long-dated encumbrance. Each issuance layers another fixed charge onto the stack. Political visibility risk grows as procurement and infrastructure costs compound. SCE improves its balance sheet immediately. Customers will pay for decades.

RESOURCE ADEQUACY

The CPUC issued a ruling that formally incorporates Energy Division's updated SERVM inputs into the record.

• What Changed: The CPUC upgraded its core reliability model (SERVM) with the 2025 Integrated Energy Policy Report demand forecast, extended weather and hydro data through 2024, refreshed baseline resources from August 2025 CAISO interconnection and retirement data, improved storage optimization, updated outage rates, fuel costs, and emissions pricing. The Integrated Resource Planning proceeding holds the 2024 IEPR and prior baseline by agreement (the split is intentional, not incidental).
• Why It Matters: This is a major update year, and the scope reflects it. Higher and more complex load shapes from electrification drivers (EVs, building load, data centers) combined with two additional extreme weather years in the dataset means SERVM is being calibrated to surface more challenging reliability conditions. Storage ELCC implications from the revised optimization will directly affect RA counting rules. The baseline resource refresh closes the gap between modeled and actual system buildout.
• What to Watch: The study case structure changed significantly, from 2,645 cases (23×23×5) to 125 cases run with 25 outage draws each. Staff decoupled weather and hydro years, a methodological assumption parties should scrutinize. The 2028 Loss of Load Expectation study result, expected by August 2026, will set the table for local capacity obligations, flexible capacity requirements, and the next round of IRP portfolio constraints. Everything downstream of this proceeding runs through these inputs.

INSTANT ANALYSIS: Every number that comes out of the 2028 Loss of Load Expectation study (reliability need, ELCC values, procurement volumes) will trace back to what was just cemented into this record. Three areas stand out.

• The demand forecast shift to the 2025 IEPR with explicit electrification load almost certainly pushes peak demand higher and changes its shape. Later evening peaks driven by EV charging interact badly with solar falloff. If that dynamic is embedded in the new hourly profiles, the storage adequacy picture gets worse, not better.
• The storage optimization upgrade deserves scrutiny from load-side parties. Better modeled storage performs better in reliability simulations, which could reduce measured reliability need and soften procurement mandates. Parties representing load will want to examine whether the new storage dispatch logic is conservative enough to reflect real-world operator behavior. A 90% nameplate discharge constraint is one lever; how aggressively the model arbitrages versus reserves for scarcity hours is another.
• The case structure change is underappreciated. Decoupling weather and hydro years and reducing to 125 cases with 25 outage draws is a computational tradeoff. Staff defends it on convergence grounds. But it eliminates the correlated stress scenarios (wet hydro year with mild weather, dry year with heat dome) that historically drove California's worst reliability events. Parties should demand sensitivity runs.

The 2028 Loss of Load Expectation study result will set the table for local capacity obligations, flexible capacity requirements, and the next round of IRP portfolio constraints. These inputs are the opening position.

DIABLO CANYON

The CPUC issued a proposed decision granting in part a petition by the Alliance for Nuclear Responsibility to modify a 2024 Diablo Canyon cost-recovery approval (D.24-12-033).

Going forward, the CPUC will use the final Resource Adequacy Market Price Benchmark (rather than the forecast value) when determining whether Diablo Canyon's actual operating costs fall within the 115% threshold that triggers automatic reasonableness review under the Public Utilities Code.

The CPUC's rationale is straightforward: because the RA Market Price Benchmark is a Commission-issued, market-based benchmark, the final value is simply more consistent with the statute's intent to assess actual costs.

The Commission agrees with PG&E that this adjustment should apply to all Diablo Canyon extended operations proceedings through 2030, not just the 2025 revenue requirement (ensuring consistent treatment across years). The PD rejects broader requests to revise past findings or adjust already-approved revenue requirements, concluding that existing ERRA-style true-up mechanisms have already flowed updated benchmark values into rates.

The result is a forward-looking fix to the cost-evaluation methodology, without reopening prior rate decisions or altering previously authorized revenue levels. Comments are due April 30. The earliest the CPUC will consider this item is May 14.

INSTANT ANALYSIS: This approval is a surgical fix to a real distortion in the Diablo Canyon cost-recovery framework. By switching the 115% test to the final RA Market Price Benchmark, the PD narrows a gap where inflated forecast benchmarks could insulate hundreds of millions in costs from review.

The distinction matters because the safe harbor under the Public Utilities Code is binary: sit under 115% and scrutiny largely stops. A higher forecast Market Price Benchmark made that threshold easier to clear: the 2025 forecast Market Price Benchmark was $42.54/kW-month against a final value of $11.21.

The PD stops short of reopening past revenue requirements, keeping PG&E whole on already-booked costs. But going forward, the evaluation is grounded in actual market conditions rather than CPUC forecasts that proved dramatically wrong. If adopted, the PD would harden the back-end audit function of the Diablo Canyon Power Plant framework through 2030.

RENEWABLES PORTFOLIO STANDARD

The CPUC issued a proposed decision denying the Bioenergy Association of California's March 2025 petition to extend or modify the Bioenergy Market Adjusting Tariff (BioMAT) program, on procedural grounds. The BioMAT ended on December 31, 2025 and that sunset date remains intact.

The petition sought to remove or extend the sunset, adjust pricing for inflation, revise allocation rules, and expand project eligibility for microgrids and resource adequacy. The PD dismisses the petition before reaching the merits. The Bioenergy Association of California filed more than four years after the underlying decision, and its justifications (COVID disruption, subsequent legislation, 2021-2022 policy developments) were either stale or previously litigated in a prior petition that failed on the same timeliness grounds.

Comments are due April 30. The earliest the CPUC will consider this item is May 14.

INSTANT ANALYSIS: BioMAT is done as a dedicated program pathway. Any revival attempt has to compete inside the broader RPS docket, where bioenergy is one priority among many and carries none of the contractual certainty that a standalone Feed-in Tariff structure provided. The PD also reinforces that recycled policy arguments don't cure a late filing. Parties that missed the window need genuinely new facts.

INTERSTATE NG PIPELINE CAPACITY

PG&E filed an advice letter for pre-approval to enter a firm transportation service agreement with the El Paso Natural Gas Company for San Juan Basin gas delivery to California core customers.

The structure is a pre-arranged capacity release from a firm shipper to PG&E, not a direct contract. Contract terms are confidential (market-sensitive, proprietary) but cost recovery flows through existing channels: the Core Pipeline Demand Charge Account and Tariff G-CT for Core Transport Agents. Protests are due April 20.

INSTANT ANALYSIS: This is a routine compliance filing under the CPUC's 2015 interstate capacity planning range decision (D.15-10-050). The capacity release structure is the only detail worth tracking. A firm shipper is on the other side of this transaction, and Core Transport Agents can access the confidential terms under a non-disclosure agreement, meaning secondary capacity market activity on EPNG is in motion. Core customers remain fully exposed to upstream procurement costs through existing recovery mechanisms.