MONDAY AGGREGATE: Load Growth Caps, PG&E ERRA Compliance; Crimson's 67% Crude Pipeline Rate Hike

February 2026 ended with a bang; many items surfaced late last week and spilled over into Monday. We're getting you caught up on them now.

• DISTRIBUTED ENERGY RESOURCES/LOAD GROWTH: The major electric IOUs submitted filings to address a longstanding tension identified in the High DER proceeding: the CEC's IEPR forecasts are system-level and coincident, while distribution planning is circuit-level and based on non-coincident peaks. Applying system caps directly to circuit forecasts can either distort known load data or suppress near-term distribution upgrade needs. Consequently, all three utilities propose formal adoption of a “Non-Coincident IEPR Cap” methodology that reconciles IEPR system forecasts with bottom-up circuit planning.
• PG&E'S ERRA COMPLIANCE: PG&E's new ERRA compliance filing requests that issues pertaining to the extended operations of Diablo Canyon be excluded from the ERRA venue, arguing those costs are reviewed under a separate statutory framework.
• HYDRO ASSETS: PG&E filed an application seeking approval under the Public Utilities Code to sell its 4.8-MW Hamilton Branch Hydroelectric Project, located near Lake Almanor in Plumas and Lassen Counties, to Hamilton Branch Hydro, LLC. This is a straightforward portfolio exit of a mothballed hydro unit.
• ARTIFICIAL OIL ISLANDS: SCE, THUMS Long Beach Company, and the City of Long Beach recently submitted a Joint Mediation Statement reporting continued progress toward a potential sale of the THUMS Added Facilities from SCE to THUMS. Read our "instant analysis" to understand why this proceeding is not trivial.
• CRUDE OIL TRANSPORTATION: Crimson California Pipeline L.P. filed an application with the CPUC seeking authorization to increase rates on its Southern California crude oil pipeline system by 66.97%, retroactive to April 1, 2026. This is a declining-asset ratemaking case.

Also, please see our standalone summaries from earlier today covering the gas utilities' major infrastructure investments, PG&E's March 1 electric rates filing, and the first real test of the CPUC's narrow exception pathway after it eliminated gas line extension allowances in a 2022 decision (D.22-09-026). 

DERS/LOAD GROWTH

In recently-filed advice letters, SDG&E (AL 4809-E, available here) and PG&E/SCE (AL 7850-E/5747-E) respond to a 2024 decision (D.24-10-030), which requires the utilities to formalize improved methods for setting caps on load growth derived from the California Energy Commission’s Integrated Energy Policy Report.

The filings address a longstanding tension identified in the High DER proceeding: IEPR forecasts are system-level and coincident, while distribution planning is circuit-level and based on non-coincident peaks. Applying system caps directly to circuit forecasts can either distort known load data or suppress near-term distribution upgrade needs.

All three utilities propose formal adoption of a “Non-Coincident IEPR Cap” methodology that reconciles IEPR system forecasts with bottom-up circuit planning. The approach integrates:

• IEPR baseline (R/I/C) growth;
• IEPR load modifiers such as light-duty and medium/heavy-duty EV and fuel substitution;
• Known loads; and
• Commission-adopted pending load categories under Resolutions E-5413 and E-5414.

Known loads are modeled at their specific circuit locations and may exceed the IEPR cap. Higher-confidence pending loads may also exceed the cap depending on category and scenario. Specifically, Category A and B1 loads can exceed IEPR under the Base Scenario, and Category B2 loads can exceed IEPR only in designated hot spot areas), while lower-confidence pending loads are limited to IEPR-consistent growth and, if necessary, rolled forward to later years.

Both the joint PG&E/SCE filing and SDG&E describe the cap as implementable on either an energy or peak basis depending on the forecast element, with circuit-level growth compared annually to the corresponding IEPR value and with capped pending loads allocated until the IEPR limit is reached. If non-capped load alone exceeds IEPR, capped loads are deferred. If total load remains below IEPR, no cap applies and remaining IEPR headroom is filled with econometric growth. SDG&E presents a functionally similar framework, emphasizing avoidance of double counting and explicit treatment of non-coincident peak effects.

Protests are due March 19.

INSTANT ANALYSIS: The IOUs are formalizing a method that lets high-confidence electrification loads exceed IEPR caps at the circuit level while limiting lower-confidence projects. That shifts away from the "borrow forward" approach described by PG&E/SCE and gives distribution planners more room to reflect real interconnection demand. For CRI readers, this affects upgrade timing, queue movement, and rate base growth. If approved as filed, utilities gain clearer authority to plan ahead for EV and fuel-switching load rather than pushing it into later years to match IEPR.

ERRA COMPLIANCE

PG&E filed its 2025 ERRA compliance application. It seeks a Commission finding that, for the January 1–December 31, 2025 record period, it complied with its CPUC-approved Bundled Procurement Plan and applicable decisions across:

• Generation operations;
• Fuel procurement;
• Contract administration;
• Hedging;
• GHG compliance instrument procurement; and
• Resource Adequacy sales.

PG&E asks the CPUC to confirm that it reasonably managed utility-owned generation, achieved least-cost dispatch, and made accurate entries to ERRA, PABA, and related balancing accounts. The filing also includes required Public Safety Power Shutoff revenue showings and Central Procurement Entity cost reporting.

Notably, PG&E is presenting entries to the Modified Transition Cost Balancing Account, Bioenergy Market Adjustment Tariff Non-Bypassable Charge Account, Tree Mortality Non-Bypassable Charge Balancing Account, and New System Generation Balancing Account for compliance review for the first time, based on a stipulation from its 2024 ERRA case (A.25-02-013). This will expand the scope of what is subject to annual compliance review going forward.

PG&E also requests deferral of review for three Utility-Owned Generation outages still in progress at the end of the record period:

• Bucks Creek Unit 2;
• Cresta Powerhouse Unit 2; and
• Elkorn Battery Energy Storage System.

Additionally, PG&E requests that Diablo Canyon extended operations be excluded, arguing those costs are reviewed under a separate statutory framework. PG&E frames this as a legal preemption argument under the Public Utilities Code, which provides that there shall be "no further review" of Diablo Canyon extended operations costs if actuals remain below 115% of forecasted costs. PG&E contends the legislature foreclosed ERRA review of extended operations entirely, and that duplicating review in this proceeding risks inconsistent results.

No new rate recovery is requested.

INSTANT ANALYSIS: This is a ledger-protection filing. A disallowance would flow through ERRA and PABA true-ups and ultimately affect bundled rates and PCIA vintages. Areas to watch: least-cost dispatch metrics, whether the Commission accepts PG&E's statutory preemption effort to keep Diablo Canyon extended operations in a separate review track, and whether the expanded balancing account scope invites new intervenor scrutiny.

HYDROELECTRIC ASSETS

PG&E filed an application seeking approval under the Public Utilities Code to sell its 4.8-MW Hamilton Branch Hydroelectric Project, located near Lake Almanor in Plumas and Lassen Counties, to Hamilton Branch Hydro, LLC.

The project, originally built in 1921 and acquired by PG&E in 1946, has been in decline since 2016, when one of its two units was mothballed; the second unit followed in 2018, due to the significant capital investment required to restore operations. The transaction includes the powerhouse, dams, water conveyance facilities, non-consumptive water rights, and approximately 6,800 acres of land subject to an existing conservation easement.

PG&E conducted a public Request for Offers process beginning in April 2021, selected a winning bidder later that year, but paused negotiations in 2022 while pursuing its Pacific Generation LLC application to transfer all non-nuclear generation assets to a subsidiary. After that application was denied (in a 2024 decision, D.24-05-004) PG&E resumed negotiations in 2024 and executed a Purchase and Sale Agreement on January 1, 2026.

• PG&E proposes to transfer the project “as-is” and make certain interconnection-related improvements prior to closing. The net book value of the project is approximately $1.16 million, and PG&E will make a $19.26 million transfer payment to the buyer, resulting in an estimated pre-tax loss of about $22.29 million.
• PG&E asserts that selling the project will save customers between roughly $38.6 million and $61.8 million compared to refurbishing or decommissioning the facility, due to avoided future capital and operating costs.
• PG&E proposes to record the loss in its Portfolio Allocation Balancing Account and recover it consistent with prior CPUC gain-on-sale precedent, with recovery flowing through Power Charge Indifference Adjustment-related mechanisms.
• PG&E also requests a categorical CEQA exemption, consistent with prior hydro divestitures, and outlines compliance with tribal notice policies and procedural requirements. PG&E proposes an aggressive procedural schedule.

INSTANT ANALYSIS: This is a straightforward portfolio exit of a 4.8 MW mothballed hydro unit. PG&E argues the sale avoids $38–$62 million in future refurbishment or decommissioning costs, framing the transaction as a customer savings move. The failed Pacific Generation reorganization is the background context; this asset would have transferred to that subsidiary had the CPUC approved PG&E's application, and PG&E is now unwinding these assets individually.

The financial tension sits in the estimated $22.29 million pre-tax loss and the proposed PABA/PCIA treatment. Intervenors may question whether ratepayers should absorb the full depreciable asset loss under existing gain-on-sale rules. PG&E invokes the percentage allocation rule of a 2006 decision (D.06-05-041): 100% of depreciable asset losses go to customers, with a 67/33 customer/shareholder split on non-depreciable assets.

Given that approximately 6,800 acres of land represents a significant non-depreciable component of the transaction, the breakdown between depreciable and non-depreciable portions of the $22.29 million loss is likely to draw scrutiny from Cal Advocates.

CEQA is positioned as categorically exempt based on continued hydro use. Unless the buyer’s rehab scope expands, approval risk appears low.

ARTIFICIAL OIL ISLANDS/ADDED FACILITIES

SCE, THUMS Long Beach Company, and the City of Long Beach recently submitted a Joint Mediation Statement reporting continued progress toward a potential sale of the THUMS Added Facilities from SCE to THUMS.

Following a July 17, 2025 full-day mediation and subsequent negotiations, the parties conducted site visits at the Pico Substation to plan separation of the THUMS facilities from SCE’s remaining assets and engaged in ongoing calls, email exchanges, and in-person discussions to resolve outstanding issues.

And since a January 29 Mediation Status Conference, SCE and THUMS have agreed on a sales price and all three parties are close to finalizing a term sheet, which they expect to complete within 60 days. They will provide a status update at a March 4 Mediation Status Conference and propose filing a further Joint Mediation Statement by March 27, noting that confidentiality limits additional detail at this stage.

Previous CRI coverage of this proceeding can be found at the link below, which provides background on this application. In short, Edison seeks to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the THUMS artificial oil islands must be replaced under a new, customer-financed Added Facilities Agreement (with THUMS or any successor customer providing all upfront capital and assuming all removal-cost risk).

Update on $190 Million THUMS Oil Islands Cable Replacement

Topics covered: SCE’s role in the Microgrid Incentive Program, an agreement serving the THUMS artificial oil islands, and PG&E’s RAMP

CALIFORNIA REGULATORY INTELLIGENCEMC

INSTANT ANALYSIS: This proceeding is not trivial. If SCE and THUMS finalize a sale of the Added Facilities, the Commission will effectively bless a negotiated unwind of utility-owned infrastructure serving a single, highly specialized customer. That keeps cost responsibility contained and avoids litigating broader Rule 2 added-facilities doctrine.

• For SCE, the upside is balance sheet simplification and reduced long-term operational exposure tied to oil-field infrastructure.
• For THUMS and the City of Long Beach, ownership clarity provides control and planning certainty. The key issue for observers is whether the CPUC treats this as a one-off transaction or articulates principles that could be cited in future large-load or co-located infrastructure separations.

Most readers will not see immediate rate impacts. The longer-term relevance lies in how the CPUC handles negotiated asset boundary shifts between IOUs and major customers.

CRUDE OIL TRANSPORTATION

Crimson California Pipeline L.P. filed an application with the CPUC seeking authorization to increase rates on its Southern California crude oil pipeline system by 66.97%, retroactive to April 1, 2026.

• Crimson argues that, under current rates, it would earn a negative 24.00% overall return on rate base and a negative 48.01% return on equity in the 2026 test year, leaving it unable to cover operating expenses and placing the system at risk of shutdown.
• Crimson's supporting declaration (from CEO/CFO Robert Waldron) explains that projected 2026 operating expenses increase to approximately $41.9 million (excluding depreciation), driven largely by higher integrity, insurance, and shared-cost allocations, with the single largest adjustment being a $6.0 million reallocation of unavoidable shared costs following the idling of affiliated San Pablo Bay and KLM pipelines. (Though the remaining eight test period adjustments collectively add about $5 million more across wage reallocations, integrity spending, insurance repricing, and other categories).
• Crimson calculates an average original cost rate base of approximately $52.6 million and proposes a 4.90% composite depreciation rate to ensure full recovery by 2036, consistent with the CPUC's previously recognized remaining economic life.
• Crimson further models an imputed capital structure assuming 40% debt at a 12.0% cost, citing the term loan of its parent company CorEnergy (placed June 2024, maturing April 2029) as the best proxy for market debt costs.

Crimson itself carries no third-party debt; all debt on its books is intercompany with its parent CorEnergy, which has 100% voting control. The 60/40 debt-equity structure and 12% cost of debt are therefore analytical constructs, not reflections of actual entity-level financing.

With the full 66.97% increase, Crimson projects a 13.80% overall return on rate base and a 15% return on equity, which it contends falls within the “zone of reasonableness” under Hope Natural Gas and is necessary to maintain financial integrity and continued operations.

INSTANT ANALYSIS: Crimson frames this matter as existential. At current rates it projects a negative 24% return on rate base and negative 48% ROE. With the full 66.97% increase, returns move to approximately 13.8% and 15% respectively. Its message is simple: no increase, no viable system.

The conflict here will center on three issues:

• Cost reallocations after affiliated pipelines were idled, pushing shared overhead onto Southern California crude pipeline shippers (the $6 million SPB/KLM reallocation alone accounts for about half the total test period adjustment, and shippers will challenge whether those costs are properly assignable to this system);
• The imputed 12% cost of debt and 60/40 capital structure. Given that Crimson carries zero third-party debt, shippers will argue the CPUC should not impute a 12% borrowing cost for debt that does not exist at the entity level, and the CPUC itself may scrutinize whether the CorEnergy Term Loan is an appropriate proxy; and
• A 7.5% annual volume decline forecast, which Robert Waldron justifies by citing California's approximate 8% five-year average production decline and an approximate 7.6% year-over-year throughput drop from 2024 to 2025.

This is a declining-asset ratemaking case. The CPUC must decide how aggressively to allow cost recovery for oil infrastructure nearing end-of-life, and who bears the contraction risk as throughput shrinks.