WEDNESDAY AGGREGATE: Rule 21 Interconnection Review Opens; CPUC Expands PG&E 2027 GRC Scope

Today's roundup includes the following items.

• Interconnection: A scoping memo in the Rule 21 Update proceeding indicates that the OIR's initial phase will focus on whether the CPUC should:
  • Modify technical screening tools used to evaluate grid impacts;
  • Revise interconnection timelines and compliance benchmarks established in 2020; and
  • Reconsider the $800 flat interconnection application fee currently applied to non-Net Energy Metering and non-Net Billing Tariff resources.
• PG&E 2027 General Rate Case: An amended scoping memo expands this proceeding to address Assembly Bill 2666 and Assembly Bill 2847, which require the CPUC to examine utilities’ actual-versus-forecasted rates of return, and to evaluate the revenue-requirement impacts of proposed capital expenditures in future applications.
• Risk Assessment and Mitigation: A ruling in the Sempra IOUs' Risk Assessment Mitigation Phase docket directs SoCalGas and SDG&E to provide additional information regarding their 2025 RAMP filings, which will inform the utilities’ upcoming Test Year 2028 General Rate Case application. The ruling demands greater transparency from the IOUs.
• SCE 2022 ERRA Compliance: A new Edison advice letter implements the CPUC’s January decision in its 2022 Energy Resource Recovery Account compliance proceeding.
• PG&E ERRA Trigger: PG&E filed an advice letter to establish its 2026 ERRA trigger amount. Based on 2025 generation-related revenues, PG&E sets the 4% ERRA trigger amount at $166.5 million and the 5% threshold at $208 million. If its net ERRA balance reaches the trigger level and approaches the threshold, PG&E must file an application proposing rate changes to amortize the balance.
• PG&E Hinkley Compressor Station: An ALJ ruling in PG&E's application for a Certificate of Public Convenience and Necessity to construct electrical upgrades at the S-238 Hinkley Compressor Station directs PG&E to provide additional information regarding its recent motion to withdraw the application and pursue the project under an emergency exemption.
• Load Control: SCE filed a report describing the results of its Load Control Management System pilot, a two-year program that tested whether customer-owned load-control technology could allow new electric loads to be energized in grid-constrained areas before distribution upgrades are completed.
• Public Safety Power Shutoffs: PG&E, SCE, and SDG&E each submitted their 2025 Public Safety Power Shutoff Post-Season Reports in the CPUC’s de-energization rulemaking (R.18-12-005). The filings are compliance updates, but they help finalize the official record of 2025 PSPS operations.

INTERCONNECTION

The CPUC issued a scoping memo in the rulemaking whose focus is to update Rule 21 interconnection rules for Distributed Energy Resources. The proceeding marks the Commission’s next step in adapting Rule 21 to a grid with growing volumes of storage, electric-vehicle charging, and hybrid DER resources.

Phase 1 will focus on whether the Commission should:

• Modify Screens Q and R (technical screening tools used to evaluate grid impacts);
• Revise interconnection timelines and compliance benchmarks established in a 2020 decision (D.20-09-035); and
• Reconsider the $800 flat interconnection application fee currently applied to non-Net Energy Metering and non-Net Billing Tariff resources.

The ruling also outlines a broader set of issues that may be addressed in later phases, including updates to Rule 21 technical standards, communications and interoperability requirements for DERs, alignment with the Wholesale Distribution Access Tariff, cost-sharing mechanisms for grid upgrades, and potential changes related to emerging technologies such as vehicle-to-grid systems and plug-in solar. Opening comments on the Phase 1 questions are due March 11, with replies due March 18.

INSTANT ANALYSIS: This ruling will first focus on screening failures, utility processing timelines, and the flat $800 application fee for non-NEM resources. These areas represent the main friction points in the DER pipeline, where projects stall after failing technical screens or waiting for utility review.

DER developers may push for revised screens or alternative review paths to avoid lengthy cluster studies, while utilities will focus on reliability and ensuring upgrade costs fall on applicants rather than ratepayers. The ruling's interest in D.20-09-035's interconnection timelines suggests a continuing concern with processing delays. The fee issue could also prove significant: moving from a flat $800 charge to cost-based fees would raise application costs for many projects while better reflecting utility workload.

PG&E GENERAL RATE CASE

Commission President John Reynolds issued a second amended scoping memo in PG&E's 2027 General Rate Case, expanding the proceeding to address new statutory requirements enacted in 2024.

The ruling incorporates implementation questions related to Assembly Bill 2666 and Assembly Bill 2847, which require the CPUC to examine utilities’ actual-versus-forecasted rates of return and to evaluate the revenue-requirement impacts of proposed capital expenditures in future applications.

• Under AB 2666, the Commission must establish guidelines for utilities to report actual annual rates of return and track deviations from GRC forecasts, including identifying cost categories where forecasts diverged from recorded costs.
• AB 2847 requires the Commission to determine whether applications seeking authorization or recovery of capital spending must include estimates of annual revenue-requirement impacts and the Net Present Value of those impacts over the life of assets placed in rate base.

The ruling adds these statutory implementation issues to the PG&E GRC scope and directs PG&E (and other parties) to provide input on how the CPUC should calculate and track actual rates of return, what methodologies should be used to compare forecasted and recorded costs, and what capital-expenditure impact estimates should be required in the application. The ruling also asks PG&E to report its actual annual rates of return for 2023–2026 and explain the methodology used.

Responses are due March 17.

INSTANT ANALYSIS: This ruling introduces two new statutory requirements into PG&E’s 2027 GRC that increase scrutiny of both utility earnings and capital spending forecasts. AB 2666 requires the CPUC to examine utilities’ actual-versus-forecasted rates of return and identify cost categories where forecasts diverged from recorded costs, creating a new evidentiary path for parties to challenge forecast accuracy in future rate cases.

AB 2847 pushes utilities to show the revenue-requirement and NPV impacts of proposed capital projects, giving intervenors clearer tools to contest large investments before approval. In the near term, PG&E must provide data on its 2023–2026 realized returns, which could widen the record around earnings performance and cost forecasting in the GRC.

SEMPRA UTILITY RAMP SUBMISSIONS

A new ruling in the Sempra IOUs' Risk Assessment Mitigation Phase docket directs SoCalGas and SDG&E to provide additional information regarding their 2025 RAMP filings, which will inform the utilities’ upcoming Test Year 2028 General Rate Case application.

The ruling follows a review by the CPUC’s Safety and Policy Division, which found that the utilities’ RAMP submissions generally comply with the CPUC’s Risk-Based Decision-Making framework but contain several deficiencies that must be corrected before the GRC is evaluated.

Specifically, the ruling directs the utilities to improve transparency and comparability in their risk analyses, including clearer presentation of risk-scaling methods, cross-cycle comparisons of risk results, and documentation of how risk tranches correspond to mitigation programs and cost-benefit ratios.

The ruling also requires standardized cost-benefit calculations, explicit justification for mitigation programs with cost-benefit ratios below 1.0, and more granular reporting of underground gas storage risks for SoCalGas. The utilities must incorporate these corrections into their Test Year 2028 GRC filings, provide replicable Excel workpapers supporting their analyses, and submit a roadmap linking each RAMP risk to the relevant GRC testimony by June 15.

INSTANT ANALYSIS: This ruling is demanding greater transparency from SoCalGas/SDG&E regarding how they calculate risk, select mitigation programs, and justify spending. The ruling orders replicable models and Excel workpapers, which gives intervenors a clearer path to challenge risk assumptions and cost-benefit calculations. The ruling also places attention on mitigations with cost-benefit ratios below 1.0 and large shifts in risk values across RAMP cycles. Both issues are likely to become major points of dispute once the 2028 GRC applications are filed.

ERRA COMPLIANCE

SCE filed Advice Letter 5756-E (available here) to implement the CPUC’s decision in its 2022 Energy Resource Recovery Account compliance proceeding (D.26-01-003; see CRI's coverage here.)

SDG&E Wildfire Costs + Provider of Last Resort Framework

An SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures

CALIFORNIA REGULATORY INTELLIGENCEMC

The filing carries out D.26-01-003's findings that SCE prudently managed its procurement activities during the 2022 record year, including administration of utility-owned generation, procurement contracts, least-cost dispatch, and greenhouse-gas compliance.

D.26-01-003 also verified the accuracy of SCE’s ERRA-related balancing and memorandum account entries, while approving recovery of $50.873 million in undercollected costs, plus franchise-fee and uncollectibles adjustments, for a total revenue requirement increase of about $51.5 million to be reflected in future rates.

These costs stem from several CPUC-authorized programs and accounts, including residential rate implementation, Integrated Resource Planning costs, a summer reliability demand response program, a climate adaptation vulnerability assessment, and the Percentage of Income Payment Plan.

Last, the advice letter implements several small disallowances and accounting corrections as ordered by the decision.

• SCE must return $14,547 in unrealized revenues associated with two 2022 Public Safety Power Shutoff events, and remove $56,500 in CAISO sanctions previously recorded in procurement balancing accounts, shifting those costs to shareholders.
• In addition, SCE will eliminate its Wheeler North Reef Expansion Project memorandum account, since the project is no longer incurring costs, and will stop including the permanently offline Tehachapi Storage Project in future ERRA review proceedings.

Protests are due March 23.

INSTANT ANALYSIS: The dollar amounts involved with this filing are modest, but it illustrates how a wide range of policy programs (from IRP compliance work to demand-response pilots and affordability programs) ultimately flow through ERRA-adjacent mechanisms and land in rates years after the costs were incurred.

ERRA TRIGGER

PG&E filed Advice Letter 7851-E to establish its 2026 ERRA trigger amount, a routine annual calculation required under multiple CPUC decisions governing electric procurement balancing accounts.

The ERRA trigger mechanism is designed to prevent large over- or under-collections in utility power procurement accounts. If the net balance of procurement costs and revenues exceeds defined limits relative to prior-year generation revenues, the utility must file an expedited application to adjust rates and amortize the imbalance.

For 2026, PG&E calculates total 2025 generation-related revenues of about $4.16 billion, derived from ERRA and several related balancing accounts, including:

• The Portfolio Allocation Balancing Account;
• Modified Transitional Cost Balancing Account;
• New System Generation Balancing Account; and
• Green Tariff Shared Renewables Balancing Account.

Based on these revenues, PG&E sets the 4% ERRA trigger amount at $166.5 million and the 5% threshold at $208 million. If its net ERRA balance (calculated net of bundled customers’ share of PABA balances) reaches the trigger level and approaches the threshold, PG&E must file an application within 60 days proposing rate changes to amortize the balance.

The filing also explains that balances already being amortized through previously approved ratemaking mechanisms are excluded when evaluating whether the trigger is reached, ensuring that only unamortized procurement imbalances are considered. PG&E requests CPUC approval of the calculated trigger and threshold amounts, which would remain in effect until the next annual calculation is adopted. Protests are due March 23.

INSTANT ANALYSIS: The size of the trigger reveals the scale of PG&E’s bundled procurement exposure. A $166.5 million trigger means procurement costs can deviate by that amount before the utility must seek a rate adjustment. That tolerance band gives PG&E substantial room to absorb normal market volatility without returning to the CPUC mid-year.

The more meaningful point is the netting of ERRA against PABA balances adopted in recent decisions. By offsetting bundled procurement balances with PCIA-related allocations, the trigger test now filters out cost-allocation noise between bundled and departing-load customers. In practice, that lowers the likelihood of ERRA trigger applications and reduces the chance of sudden procurement-driven rate adjustments.

The chief takeaway is that ERRA volatility will show up in rates more slowly than before, because the trigger test now smooths fluctuations that previously could have pushed the account toward the threshold.

PG&E HINKLEY COMPRESSOR STATION

A new ruling in PG&E's application for a Certificate of Public Convenience and Necessity to construct electrical upgrades at the S-238 Hinkley Compressor Station directs PG&E to provide additional information regarding its recent motion to withdraw the application and pursue the project under an emergency exemption.

The ruling responds to concerns raised by intervenors, including TURN and Cal Advocates, who questioned whether they should proceed with scheduled testimony given PG&E’s request to withdraw the case.

PG&E Looks to Bypass CPCN Review for Hinkley Project

Topics covered: PG&E’s S-238 Hinkley Compressor Station Electrical Upgrades Project; PG&E’s Billing Modernization Initiative

CALIFORNIA REGULATORY INTELLIGENCEMC

PG&E must submit a compliance filing by March 11 detailing the electrical equipment failures and component obsolescence issues cited as the basis for initiating the project in January 2026, and explaining how those failures relate to the originally proposed project. The ruling also grants parties additional time to prepare testimony while the Commission evaluates the withdrawal request and PG&E’s new claims.

Intervenor testimony is now due March 25, PG&E rebuttal testimony April 17, and an evidentiary hearing (if needed) is scheduled for May 14. The ALJ further asks PG&E to confirm whether construction activity already underway is complying with the mitigation measures identified in the project’s environmental review.

INSTANT ANALYSIS: PG&E’s attempt to withdraw the Hinkley Compressor Station CPCN application and proceed under an emergency exemption has not been accepted at face value. The ALJ is requiring a March 11 compliance filing detailing the specific equipment failures and obsolescence issues that allegedly forced PG&E to begin the project in January. The ruling preserves the procedural track by extending testimony deadlines rather than suspending the case. PG&E must now demonstrate that the situation meets the threshold for a General Order 177 emergency exemption; if not, the proceeding can continue under the original CPCN review schedule.

LOAD CONTROL

SCE filed a report describing the results of its Load Control Management System (LCMS) pilot, a two-year program conducted from January 2024 through January 2026 to test whether customer-owned load control technology could allow new electric loads to be energized in grid-constrained areas before distribution upgrades are completed.

The pilot allowed participating customers (primarily projects such as electric-vehicle charging infrastructure) to operate under approved power-import limits using automated control systems that restricted site demand until grid capacity expansions were finished.

SCE evaluated both autonomous local control systems and the concept of communication-based systems that could eventually interact with utility grid-management platforms such as DERMS and ADMS.

• According to the report, nine projects ultimately participated in the pilot, allowing those customers to energize their facilities an average of about 20 months earlier than if they had waited for grid upgrades, with time savings ranging from five months to more than three years. SCE reports that the participating power-control systems performed reliably and never exceeded approved import limits.
• The pilot also tested the process for reviewing and approving customer equipment, including vendor-specific testing and the emerging UL 3141 certification standard for power-control systems. While the program relied on delayed AMI meter data rather than real-time telemetry, SCE concluded that the concept worked safely and provided significant value for projects facing energization delays.
• Based on the results, SCE recommends continuing the use of LCMS-type “Flexible Service Connections” as a bridge solution for load growth in constrained areas, expanding adoption of UL-certified control equipment, developing better engineering and tracking tools, and eventually moving toward dynamic, communications-based load controls integrated with future grid management systems.

The report concludes that the pilot demonstrated a workable pathway for accelerating new load interconnections while maintaining distribution system reliability and supporting state electrification goals.

INSTANT ANALYSIS: SCE’s LCMS pilot shows a realistic path for energizing new loads in constrained areas before distribution upgrades are complete. Participating projects were energized about 20 months earlier on average, demonstrating that controlled import limits can bridge the gap between load growth and grid expansion.

The concept shifts interconnection from a binary model to a managed-load approach, where customers operate below full capacity until upgrades are finished. If adopted more widely, this could accelerate EV charging and other electrification projects without immediate infrastructure buildout.

The pilot also exposed operational gaps. Monitoring relied on next-day AMI data rather than real-time telemetry, suggesting that larger deployments will require utility-integrated controls through DERMS/ADMS. Overall, the program points toward Flexible Service Connections becoming a standard tool for managing California’s load growth.

PUBLIC SAFETY POWER SHUTOFFS

PG&E, SCE, and SDG&E each submitted their 2025 Public Safety Power Shutoff Post-Season Reports in the CPUC’s de-energization rulemaking (R.18-12-005).

The filings compile supplemental data and corrections to previously submitted 10-day post-event reports and cover multiple 2025 PSPS events across the state. PG&E reports PSPS activity during January and June 2025 events and updates previously reported metrics, including corrected impacted-customer counts and revisions to the number of circuits and transmission facilities within event scope.

• PG&E documents four PSPS events during the year (January 13–15, January 20–21, January 22–24, and June 19–22, 2025) and provides updated operational data required under the CPUC’s PSPS reporting framework. The filing primarily corrects and supplements previously submitted post-event reports. PG&E revised impacted-customer counts for the January 20–21 and January 22–24 events after determining that five customers who received temporary generation had been mistakenly counted as de-energized; the corrected totals reduced the impacted counts slightly.
• PG&E also revised the scope of the June 19–22 PSPS event, increasing the reported number of distribution circuits included in the event from 47 to 67, while simultaneously reducing the count of affected transmission-level facilities from 22 to nine after post-season validation.
• PG&E further updated its mitigation metrics across the 2025 events. In several cases, the company revised downward the number of customers considered “mitigated,” particularly where backup generation was installed after outages had already begun and therefore did not fully prevent de-energization impacts.
• PG&E also includes updated notification-failure explanations and revised mitigation waterfall charts for each PSPS event, reflecting PG&E’s internal root-cause reviews of communication lapses and operational decisions. According to PG&E, some notification gaps occurred when weather conditions escalated more rapidly than forecast models anticipated, resulting in compressed notification timelines during certain events.

The utilities also provided additional operational details on how PSPS decisions were made and how impacts were mitigated.

• For example, SDG&E reports that a January 7–16, 2025 PSPS event ultimately involved de-energization affecting over 23,000 customer accounts (about 15,000 unique customers) due to extreme wildfire conditions tied to historically dry weather.
• SDG&E describes mitigation strategies such as circuit sectionalization that avoided outages for more than 10,000 customers, deployment of temporary generation at critical community sites, and installation of permanent backup generation at hundreds of premises that had previously experienced PSPS events.
• Similarly, SCE’s report provides circuit-level data on 2025 PSPS events, including wind thresholds, fire potential index triggers, and the number of residential, commercial, and medical baseline customers de-energized during specific outages. The filing also details notification performance and identifies instances where some public safety partners or critical facilities did not receive advance PSPS alerts because of messaging errors or rapidly changing weather conditions.

INSTANT ANALYSIS: These filings are compliance updates, but they help finalize the official record of 2025 PSPS operations. PG&E’s revisions (especially the June event scope change from 47 to 67 circuits) illustrate how utilities refine event data after internal validation, which in turn shapes the dataset the CPUC will use to evaluate PSPS performance and oversight.

The reports also highlight utilities’ effort to demonstrate that mitigation tools are reducing outage impacts. Measures such as circuit sectionalization, backup generation, and targeted de-energization are presented as evidence that PSPS events are becoming more precise rather than systemwide.

At the same time, the filings acknowledge persistent notification issues, including missed alerts or compressed timelines when weather conditions escalate faster than forecasts.