March 19, 2026 CPUC Voting Meeting Results: Commissioner John Reynolds' First Meeting as President

CPUC commissioner John Reynolds presided over his first voting meeting today following his appointment to president. Additionally, Commissioner Christine Harada made her debut appearance, bringing prior experience from the California Government Operations Agency and the U.S. Office of Management and Budget.

As detailed in our update yesterday, the CPUC delayed action on several items. Two matters move to April 9:

• Draft Resolution E-5440 (Integration Capacity Analysis remediation plans for PG&E, SCE, and SDG&E); and
• SDG&E's 2023 ERRA compliance ($215 million cost recovery).

And Draft Resolution E-5436 (DG statistics website funding) is now set for April 30.

Items that carried today include actions on data-center and transmission infrastructure, a pause of the spring 2026 residential electric Climate Credit, and an extension of California's Flex Alert campaign. Meeting results also include issues related to Provider of Last Resort, SCE's finances and EV load management, PG&E's "RAMP" closure, the Self-Generation Incentive Program, petroleum pipelines, and crude oil transportation.

A recurring theme is the advancement of infrastructure ahead of full economic resolution. Increasingly cost recovery, valuation, and rate impacts are deferred to later consideration, while approvals move forward based on reliability, load growth, and system need.

For easy reference, the table below breaks down the day's major transmission and data-center moves, followed by a more comprehensive summary of all notable energy items.

TRANSMISSION INFRASTRUCTURE

The meeting's regular agenda included two decisions involving LS Power Grid California: the 'Power Santa Clara Valley Project' and the 'Power the South Bay Project,' with each carrying 5-0.

"These decisions," said Commissioner Harada, "are about what every Californian expects – that when we flip on a switch, the light turns on. When we plug in our EV – it actually charges. That we've got a family member who needs medical equipment to run through the night – that it does."

Commissioner Harada framed the approvals as foundational to reliability and economic growth, emphasizing that transmission should not constrain load growth in rapidly expanding regions.

Power Santa Clara Valley Project

A decision grants LS Power Grid California a certificate to construct the Power Santa Clara Valley Project, a $1.593 billion (cap) transmission upgrade initially approved to address reliability issues in the San José area's 115-kV system. The project was subsequently modified in November 2024 to respond to load forecast increases from 2,100 MW to potentially 4,200 MW through a new HVDC link between major substations.

The decision finds the project necessary despite significant environmental impacts, adopts an environmentally superior alternative configuration (AC-1) with mitigation measures, and authorizes cost recovery through CAISO transmission rates subject to FERC oversight.

While the decision declines to apply the statutory presumption of need due to inconsistencies in project cost estimates (including exclusion of PG&E interconnection costs), it nevertheless finds an independent reliability need based on substantial record evidence.

Power the South Bay Project

A separate decision grants LS Power a Certificate of Public Convenience and Necessity to construct the Power the South Bay Project, a roughly 12-mile 230-kV transmission line connecting PG&E's Newark substation to Silicon Valley Power's Northern Receiving Station to address reliability risks and rising demand in the San José area.

Identified by the CAISO in its 2021–2022 Transmission Plan, the project will largely be built underground to relieve system overloads and support future load growth. Construction is authorized beginning March 2026 with a CAISO-required in-service date of June 1, 2028. The maximum cost cap is $813.24 million ($677.7 million base plus 20% contingency), recovered through CAISO transmission rates subject to FERC oversight.

The decision applies the statutory presumption of need under the Public Utilities Code without dispute and finds the project necessary to resolve identified system overloads. While most environmental impacts are mitigated to less-than-significant levels, air-quality impacts remain significant and unavoidable in part because the Commission lacks jurisdiction over Silicon Valley Power’s mitigation measures.

Alberhill System Project

A decision grants SCE a CPCN to construct the Alberhill System Project, a new 1,120 MVA 500/115 kV substation and associated transmission infrastructure in western Riverside County, at a cost cap of $481.7 million in 2023 dollars, including 15% contingency.

• The project addresses the Valley South System, an islanded radial network serving roughly 560,000 people and the only one of SCE's 56 sub-transmission systems with no tie-lines to adjacent networks. The system is already operating beyond safe capacity thresholds. Peak demand hit 1,103 MW in Summer 2024 (99% of nameplate capacity assuming tie-lines that don't exist, and 23% above the 896 MW single-transformer emergency rating that actually governs operations).
• The Commission finds that capacity, reliability, and resilience needs constitute overriding considerations under CEQA, sufficient to justify unavoidable impacts on air quality, noise, and aesthetics.
• TURN's arguments were rejected across the board. Valley Substation has five 560 MVA transformers (two serving Valley South, two serving Valley North, and a fifth spare required by SCE's internal planning criteria for emergency backup).
• TURN argued the spare should be treated as a permanent load-serving asset, which would triple the system's apparent available capacity and undercut the case for Alberhill. The decision rejects this, finding that stripping the spare of its backup function leaves 560,000 customers with no fallback if a load-serving transformer fails.
• The decision also rejects TURN's lower resilience event frequencies and alternative metrics as bases for denying the project.

Instant Analysis of Transmission Infrastructure Decisions

The CPUC is moving into a preemptive transmission build cycle across multiple regions, approving large projects based on forecasted load, system vulnerability, and resilience to low-probability events. Cost scrutiny can disrupt formal presumptions but is not blocking approvals. Environmental impacts continue to be outweighed by reliability needs. The Alberhill project demonstrates the evolution: resilience and contingency risk are now sufficient on their own to justify major infrastructure.

DATA CENTERS

Ringwood Switching Station in San Jose

Resolution E-5447 approves PG&E Advice Letter 7653-E, a non-standard Engineering, Procurement, and Construction (EPC) agreement with STACK Infrastructure under the exceptional case provisions of Electric Rules 15 and 16.

STACK will design, procure, and construct the 115 kV Ringwood Switching Station in San Jose to serve a 90 MW data center load, then transfer ownership to PG&E. The switching station is expected to be operational by April 2026.

• This resolution is scoped to construction and transfer terms only. Cost responsibility, refunds, and the broader energization framework were addressed in the prior Resolution E-5420 (see CRI's coverage here), which approved an Agreement to Perform Work and Special Facilities Agreement and capped refunds at 75% of PG&E's annual net revenues from STACK.
• Cal Advocates protested, arguing PG&E should not earn a return on a customer-financed asset and that the refund framework could expose ratepayers to cost overruns. The resolution declines to address either issue here, finding them outside the scope of an EPC agreement approval and properly reserved for FERC transmission owner rate proceedings and other ratemaking venues. The resolution notes that the refund cap and PG&E's stated post-construction cost review provide adequate safeguards.

INSTANT ANALYSIS: The Commission is reinforcing a clear pattern: once a load-serving framework is approved, follow-on execution agreements move through approval with little resistance. The two-year gap between EPC execution and regulatory filing underscores the sequencing: developers can build first and regularize later. Rate-base treatment, returns, and cost recovery remain unresolved and will surface at FERC, but for large-load customers, a pathway is now well-established:

• Fund;
• Build;
• Transfer; and
• Sort out the economics.

Sunnyvale Data Center for Menlo Equities

Resolution E-5433 approves PG&E’s agreement to energize a 49 MW data center in Sunnyvale for Menlo Equities, but rewrites the refund mechanics to address risk. The standard "Base Annual Revenue Calculation" method would allow near-immediate recovery by treating one year of revenue as evidence of a long-term stream, meaning refunds could exceed actual first-year net revenues by a wide margin.

Resolution E-5433 rejects that structure and instead ties recovery to realized revenues. Menlo pays upfront for transmission upgrades, including a 0.6-mile 115 kV underground line deemed the optimal design due to siting constraints (and fully eligible for refund), while a separate redundant line is treated as a non-refundable Special Facility. PG&E will design and build the facilities, and all work is performed on an actual cost basis.

Refunds are capped at 75% of annual net transmission revenues, with an added Income Tax Component of Contribution gross-up (24%) that increases the allowable refund but does not reflect infrastructure cost. The refund window is extended to 15 years.

PG&E opposed the cap (citing precedent, existing protections, and development risk) and proposed a 100% alternative. The resolution rejects all arguments and holds the modified structure, while removing additional ownership charges on any unrefunded balance to preserve a path to full recovery if load materializes

INSTANT ANALYSIS: This resolution resets the recovery model for large loads. The Commission is discarding forward-looking revenue assumptions and replacing them with a backward-looking annual true-up. Refunds now follow cash actually collected, not projected demand trajectories. That closes the gap where one year of revenue could justify full repayment.

The 75% cap splits the economics. Customers carry performance risk if load falls short. At the same time, a portion of revenue is retained to cover broader system costs tied to transmission service. The Income Tax Component of Contribution gross-up softens the cap, and the 15-year window plus removal of ownership charges keeps the project financeable. Large load developers now face a slower, revenue-dependent recovery path in California.

CLIMATE CREDIT

A decision pauses the spring 2026 residential electric Climate Credit for PG&E, SCE, and SDG&E customers. The credits (currently distributed in April and October) will be held so the CPUC can redirect them into high-billed summer months, with a follow-on decision expected shortly.

This move traces back to Assembly Bill 1207, which requires electric Climate Credits to be distributed in high-billed months to maximize affordability. Delivering the first post-enactment credit in April (an historically low-bill shoulder month) would conflict with the new statutory mandate.

The 2026 credits are also substantially smaller than 2025:

• PG&E dropped from $58.23 to $36.18;
• SCE from $56.00 to $36.00; and
• SDG&E from $81.38 to $49.36.

These constitute 40–60% reductions. Smaller credits make delivery timing more consequential; landing them during peak billing periods maximizes their visibility and impact.

CalCCA and the Environmental Defense Fund opposed the move, citing procedural concerns and potential harm to customers whose bills don't peak in summer. The decision acknowledges variation across customer groups but holds that average statewide billing patterns justify the pause.

INSTANT ANALYSIS: The Climate Credit is being converted from a conservation-signal instrument into an affordability tool. The legacy design intentionally placed credits in low-usage months to preserve price signals but AB 1207 inverts that approach entirely. Once timing resets into summer peaks, the credit becomes a more visible and politically salient rate offset as bills climb.

FLEX ALERTS

A decision extends California's Flex Alert paid media campaign through December 31, 2026, with a $15 million budget, down from $22 million in prior years, reflecting the end of the Power Saver Rewards program and an inflation adjustment to legacy funding levels that arose from a 2021 decision (D.21-03-056).

SCE must execute a contract extension with Doyle Dane Bernbach (or a successor) for services beginning no later than June 1, 2026. Cost allocation follows the existing CAISO peak load split:

• 45% SCE;
• 45% PG&E; and
• 10% SDG&E

These amounts are recovered from all distribution customers, including Community Choice Aggregator and Direct Access entities. The decision declines to modify program design for 2026 due to timing constraints, and does not adopt party recommendations on competitive bidding, alternative funding structures, or targeted marketing (though none of those doors are closed for 2027). Cal Advocates and SDG&E opposed the extension on affordability and Emergency Order N-5-24 grounds; the CPUC overrode on reliability.

INSTANT ANALYSIS: The Flex Alert apparatus survives for summer 2026 but at a budget reset closer to legacy levels now that emergency-era Demand Response programs have wound down. The Commission's willingness to override Emergency Order N-5-24 affordability arguments on reliability grounds tells a revealing story: behavioral DR retains institutional support when the grid is stressed, even as the cost justification diminishes.

PROVIDER OF LAST RESORT

Resolution E-5411 denies SDG&E's request to preemptively establish a memorandum account to track incremental costs from a potential mass return of customers to Provider of Last Resort service.

The resolution affirms staff's earlier rejection, finding that SDG&E's proposal conflicted with a 2024 decision (D.24-04-009), which contemplated such accounts during an involuntary return, not as a preemptive standing measure. The CPUC clarifies that SDG&E may file a Tier 1 Advice Letter when a Community Choice Aggregator Tier 2 financial trigger indicates material risk of involuntary return.

The resolution reinforces that memorandum accounts are optional tools for calculating reentry fees, not the primary cost recovery mechanism. It notes that utilities recover procurement costs through existing ERRA processes regardless of whether an account is opened (the memorandum account only affects reentry fees assessed directly to returned customers).

The resolution also points to existing safeguards, including financial monitoring of Community Choice Aggregators and a six-month notice period, as sufficient to prepare utilities for potential customer returns. Staff commits to notifying the Provider of Last Resort when it believes a CCA is at material risk of failure, subject to confidentiality obligations.

INSTANT ANALYSIS: This move addresses timing and discretion. The CPUC keeps the option to track actual costs but refuses to let utilities default into that path in advance. SDG&E has to wait for a real CCA distress signal before electing the memorandum account, which preserves the CPUC's ability to steer cost recovery back toward the Financial Security Requirement-based framework in most cases. That keeps re-entry fee mechanics predictable and avoids opening the door to broader, after-the-fact cost claims tied to volatile procurement conditions.

• The resolution also shows that the CPUC is comfortable relying on its monitoring regime rather than utility pre-positioning. Staff commits to notifying IOUs if a CCA shows distress, which puts the CPUC in the role of gatekeeper for when Provider of Last Resort cost-tracking tools activate.
• The naming of San Diego Community Power and Clean Energy Alliance as contrasting scenarios (catastrophic failure versus small planned return) provides a window into the CPUC's proportionality logic: the memorandum account is a heavy tool reserved for heavy situations.

The net effect: utilities retain the tool, but not the initiative. Expect this to matter in a real CCA stress event, where the timing of that Tier 1 filing and the choice between Financial Security Requirements vs. tracked costs could shape who ultimately bears procurement risk.

UTILITY FINANCES

A decision authorizes SCE to issue up to $9.85 billion in debt and $1.155 billion in preferred equity, $525 million less than originally requested after SCE voluntarily reconciled its forecast to its 2025 General Rate Case final decision.

Over 55% of the debt authority ($6.075 billion) is earmarked for refinancing previously issued securities; the remainder funds capital expenditures for Transmission & Distribution reliability, wildfire mitigation, grid modernization and DER integration, and covers outstanding wildfire liability payments from the 2017/2018 fires. The authorization spans a broad instrument menu (secured and unsecured debt, commercial paper, hybrid securities, preferred equity) with hedging, swaps, and credit enhancements.

INSTANT ANALYSIS: The CPUC is reaffirming settled doctrine: utilities get wide latitude to raise capital ahead of need while prudency and cost recovery are litigated later. Cal Advocates fought hard (arguing evidentiary deficiencies, double-recovery risk, and even requesting denial without prejudice) and lost on every point. Small Business Utility Advocates' concerns about overborrowing landed similarly. The decision treats both sets of objections as conflating financing authority with cost recovery.

By walling off financing from recovery, the CPUC preserves future leverage over billions that will flow into GRCs, Cost of Capital cases, and wildfire proceedings. Expect those venues to carry the substantive disputes:

• Equity thickness;
• Debt cost pass-through;
• Hybrid securities treatment; and
• Whether ratepayers absorb financing tied to wildfire exposure.

The Affiliate Transaction Rules and authorized capital structure compliance add another constraint layer that could become contested if SCE's equity ratio drifts. Near-term, SCE gets the flexibility it needs through 2028. Medium-term, the decision sets up heavier litigation over how much of that financing ultimately surfaces in bills.

ELECTRIC VEHICLE LOAD MANAGEMENT

Resolution E-5452 approves SCE's ORCHARD program, a utility-orchestrated EV charging scheme funded by $22.9 million in Low Carbon Fuel Standard holdback revenue. The program embeds a software layer into SCE's DERMS to directly coordinate residential EV charging times, targeting circuits with less than 1 MW of available capacity and at least 100 EVs.

The goal is to mitigate the secondary distribution peak created when drivers pile onto off-peak Time-of-Use windows starting at 9 p.m. SCE's enrollment target is 25,000 customers with annually declining participation incentives.

The resolution denies SCE's proposed bidirectional equipment rebates without prejudice, finding the Vehicle-to-Everything justification insufficient and that SCE:

• Failed to clarify whether participants would operate in Momentary Parallel or Isolated mode;
• Couldn't demonstrate Original Equipment Manufacturer willingness to enable grid-parallel software updates, and
• Proposed no export compensation mechanism.

INSTANT ANALYSIS: This resolution is the CPUC formally endorsing utility-controlled EV load orchestration as a distribution deferral tool, a significant step beyond passive TOU signals into active, localized grid management. The bidirectional denial keeps vehicle-grid integration squarely in the managed charging lane until interconnection costs and export compensation frameworks mature, likely through R.25-08-004 (the "Update Distribution Level Interconnection Rules and Regulations" docket). If ORCHARD performs, it gives SCE a scalable alternative to transformer upgrades with direct implications for distribution planning assumptions and future rate base.

RISK ASSESSMENT MITIGATION PHASE

A decision closes PG&E's 2024 RAMP (A.24-05-008), the front-end risk framework for its Test Year 2027 General Rate Case. The RAMP report covers PG&E's top 12 safety risks and mitigation cost-benefit analyses for 2027–2030 under the new Phase II Risk-Based Decision Making Framework. This methodology monetizes safety and reliability in dollar terms.

The CPUC's Safety Policy Division found the RAMP filing compliant but noted significant concerns:

• Expressing safety in dollars rather than unitless scores reduces its relative influence on risk rankings;
• PG&E's proposed and alternative mitigations are not modeled against the same risk areas (making cost-benefit ratios incomparable); and
• Previously approved mitigation programs appear to carry forward without rigorous re-justification even when their cost-benefit ratios fall below 1.0.

Intervenors reinforced these concerns and pressured on undergrounding-versus-covered-conductor, Public Safety Power Shutoff/Enhanced Powerline Safety Settings modeling, PG&E's hybrid Value of Statistical Life, ratepayer bill impacts, and circuit-segment granularity.

An April 2025 ruling required PG&E to address four deficiencies:

• Provide risk-neutral scaling analysis;
• Identify regulatory requirements for each mitigation;
• Supply disaggregated reliability cost calculations; and
• Remove risk tolerance as a mitigation justification.

PG&E complied, using the newly released "Interruption Cost Estimate" 2.0 calculator for disaggregated reliability (a change the decision cites as subject to GRC litigation). The decision declines Cal Advocates' push to impose new RAMP requirements through this closure, ruling those belong in a rulemaking applicable to all utilities.

INSTANT ANALYSIS: Monetizing safety collapsed PG&E's implied Value of Statistical Life from $100 million to $15.2 million, fundamentally reranking which mitigations clear the cost-benefit bar. The main GRC fights are now established:

• Undergrounding's $6.5 billion cost versus $1.7 billion in covered conductor;
• Whether risk-averse scaling inflates budgets beyond risk-neutral support;
• Interruption Cost Estimate 2.0 calculator effects; and
• Whether alternatives will ever be modeled on equal footing.

SELF-GENERATION INCENTIVE PROGRAM

A decision denies ENGIE North America’s petition to modify a 2021 CPUC decision (D.21-06-005), which sought an exemption for wastewater treatment plants from the SGIP requirement that biogas used in internal combustion engines meet a 96% methane standard. ENGIE argued that typical wastewater biogas (approximately 60% methane) makes compliance economically infeasible, even with SGIP incentives.

The decision does not reach the merits of that argument. Instead, it denies the petition on procedural grounds. Consequently, the 96% methane standard remains in place and the proceeding stays open.

INSTANT ANALYSIS: The 96% methane standard remains intact, continuing to screen out most raw wastewater biogas projects from SGIP eligibility. Any future effort to revisit SGIP fuel-quality thresholds will need a forward-looking policy track or new rulemaking phase, not a modification petition tied to a single project.

PETROLEUM PIPELINES

A decision approves Shell California Pipeline Company LLC's request to withdraw its Carson-to-LAX and Carson-to-Van Nuys petroleum pipelines from common carrier service and, upon satisfaction of specified conditions, terminate Shell California's status as a public utility entirely.

The factual record is unusually clean. Neither pipeline has ever served a non-affiliated customer since being offered for common carrier service (the Van Nuys line since 1992, the LAX line since 1996). Both lines serve only Shell affiliates and are not part of any larger interconnected pipeline system. No protests were filed. No physical or operational changes are planned, which means CEQA does not apply.

INSTANT ANALYSIS: This decision confirms that common-carrier status must be justified by actual public use: it is not a default regulatory condition. The decision relies explicitly on Richfield Oil Corp. v. Public Util. Com. (1960) for the principle that, where a pipeline no longer provides service to the public, continued regulation is unnecessary. As a result, Shell California will no longer be a CPUC-regulated entity once conditions are met.

The facts in this case (zero third-party customers across three decades, no interconnections, no protests) are about as frictionless as a withdrawal gets. For operators holding legacy common carrier classifications on affiliate-only systems, the decision opens a clear path to reclassification as private infrastructure. For assets with any history of third-party service or system interconnection, the path will be considerably more contested.

CRUDE OIL TRANSPORTATION

A decision approves Crimson California's request to withdraw the southern segment of the Seal Beach Pipeline (approximately 5.87 miles of crude oil line running from Seal Beach to Signal Hill) from public utility service. The pipeline's sole customer, DCOR, ceased using the line and withdrew its protest, leaving the application uncontested. The Commission finds the segment is not necessary or useful for public utility service, has no current or prospective customers, and is not part of a broader interconnected system.

Crimson will purge the pipeline of hydrocarbons, fill it with nitrogen, and isolate it in place under "out-of-service deferment" status overseen by the Office of the State Fire Marshal, while retaining ownership. Continued operation was uneconomic due to low throughput, saltwater-driven corrosion, and costly upcoming relocations and repairs. Crimson has indicated it will seek recovery of deferment costs in a future General Rate Case.

INSTANT ANALYSIS: The CPUC is letting a common carrier oil pipeline segment exit public utility status once it loses its sole shipper and serves no broader network function. The Commission is not forcing continued operation for optionality. If the asset is economically dead and commercially irrelevant, it can be idled.

• By approving withdrawal while the asset remains in place under OSFM oversight, the Commission is limiting its active involvement to assets with live public utility function. That approach will recur when other operators look to reclassify or sideline assets to reduce compliance burden.
• Cost recovery is unresolved. Ratepayers could still absorb shutdown and preservation costs.