WEDNESDAY AGGREGATE: Gas Distribution Cost Data; Honor Rancho; Bio-Synthetic Natural Gas

Below is a consolidated look at notable filings, advice letters, and ex parte meetings from the past few days, spanning Long-Term Gas Planning updates, compressor modernization work, IRP positions, long-duration storage procurement, Diablo Canyon cost tracking, and Rule 30 implementation.

Long-Term Gas Planning Data

SoCalGas/SDG&E (the Sempra Utilities) submitted revised gas distribution cost data in the Long-Term Gas Planning docket after CPUC Staff requested corrections to their November 5, 2025 filing.

In this updated package, SoCalGas/SDG&E supply six revised attachments covering average costs per service and per mile of main, program-level expenditures, district-level breakdowns, and planning timelines.

• For main and service replacement work, the utilities report average costs of about $21,000 per service and $2.5 million per mile of main, while service-only replacements average $13,700 per service.
• Annual pipeline replacement spending across programs totals approximately $315 million, with notable variation by operating district.
• Regulator station replacements show an average cost of about $650,000 per station, affecting approximately 2,200 services per station on average.
• The filing also includes updated metrics on planning periods, completion times, and the utility-wide aggregation of cost categories such as internal labor, external labor, materials, and miscellaneous overhead.

INSTANT ANALYSIS: By forcing SoCalGas/SDG&E to resubmit corrected, granular cost data, the Commission is laying the evidentiary groundwork for a much more disciplined gas-distribution planning regime. With this new approach, replacement costs, planning timelines, and district-level variances are no longer treated as opaque utility estimates but as standardized, comparable inputs to long-term system planning. This data will be used to shape future debates over affordability, asset retirements, and whether current replacement trajectories are economically justifiable.

Compressor Modernization Work

SoCalGas filed Advice Letter 6567-G (available here), notifying the CPUC that construction will begin on the Honor Rancho Compressor Modernization Project, a compliance and reliability upgrade required under South Coast AQMD Rules 1110.2 and 1100.

• The project replaces five obsolete gas compressors with four new low-NOx gas units and two new electric-driven compressors, supported by a new 27,800-square-foot building, updated cooling and emissions-control systems, and related piping and electrical equipment. To power the electric units, SCE will build a new substation, install loop-in 66-kV lines, and complete breaker and protection upgrades at nearby substations.
• Environmental impacts were previously analyzed under South Coast AQMD’s Program Environmental Impact Report and Subsequent Environmental Assessment, with an Addendum underway to cover SCE’s electrical work.
• SoCalGas says that construction emissions will be mitigated, and operations are expected to reduce overall pollutant emissions. Since this is an information-only filing, it is not subject to protests.

For added context, recall that, in the 2024 decision addressing the 2024 Test-Year General Rate Case of the Sempra Utilities (SoCalGas/SDG&E), the Commission capped Honor Rancho Compressor Station Modernization work at $525.2 million.

INSTANT ANALYSIS: This filing is procedural but noteworthy: SoCalGas is moving forward with a major compressor overhaul that swaps out legacy engines for a mixed gas-electric configuration, cutting NOx and aligning with AQMD compliance timelines. Although exempt from General Order 177, the scale of SCE’s associated substation and line work suggests rising electric-load implications at storage fields, which is an emerging operational trend that bears watching.

Bio-Synthetic Natural Gas 

Earlier this month, SoCalGas filed a reply defending its proposed Woody Biomass Pilot Project after protests from the Sierra Club, Cal Advocates, the Bioenergy Association of California, and Small Business Utility Advocates. (See our summary of those protests here.)

• SoCalGas argues that its proposal to use Cap-and-Trade funds is consistent with Commission precedent (pointing to the Senate Bill 1383 dairy pilots) and emphasizes that project-readiness safeguards and statutory deadlines will prevent the construction of stranded infrastructure.
• SoCalGas contends that its application provides adequate greenhouse-gas reduction estimates using the 2024 "Research & Development Greenhouse gases, Regulated Emissions, and Energy use in Technologies" (R&D GREET) model and clarifies that the project’s gasification pathway differs from the biogas-to-biomethane systems criticized by the Sierra Club.
• SoCalGas also maintains that detailed emissions-monitoring plans are not required at the application stage, though it is committed to developing reporting templates in coordination with CPUC staff, following the model of earlier biomethane pilots.

In response to environmental justice concerns, SoCalGas highlights expected community benefits, job creation, and baseline-to-project emission contrasts, noting that the Sierra Club misinterprets the location and distribution of emissions.

INSTANT ANALYSIS: SoCalGas’ reply pushes back hard on the Sierra Club’s attempt to knock out the woody-biomass pilot at the outset, leaning on SB 1383 precedent, project-readiness safeguards, and GREET-based emissions estimates to argue the application follows the CPUC's Rules of Practice and Procedure. SoCalGas frames the remaining disputes (GHG methods, emissions monitoring, and environmental/social impacts) as issues properly handled in discovery and scoping, not as reasons to reject the pilot.

Natural Gas Leak Abatement

SDG&E filed Advice Letter 3474-G (available here) to implement the requirement adopted in Resolution G-3606, which partially approved SDG&E’s 2024 Natural Gas Leak Abatement Compliance Plan (see our October 30 summary here).

AL 3474-G updates 2026 gas transportation rates to reflect the approved Natural Gas Leak Abatement revenue requirement of $2.9 million for 2025–2026. This amount is offset by a larger amount currently embedded in rates, which results in a net $2.6 million reduction.

SDG&E explains that the revenue requirement and associated balancing accounts will be amortized in transportation rates using the Equal Percent of Authorized Margin method, spreading adjustments across customer classes proportional to their base margin shares.

As shown in SDG&E's updated rate tables, core customers will see modest decreases, and noncore classes experience slightly smaller reductions, producing a systemwide revenue decrease of about $8.1 million. SDG&E requests a January 1, 2026 effective date. Protests are due December 29, 2025.

INSTANT ANALYSIS: This is a straightforward rate change that will roll into SDG&E's broader year-end consolidation. SDG&E’s updated Leak Abatement revenue requirement is lower than current levels, producing an $8.1 million systemwide reduction. This clean correction flows mostly to core customers.

Integrated Resource Planning

Below is a look at some recent ex parte communications in the CPUC's Integrated Resource Planning docket.

California Resources Corporation

• California Resources Corporation (CRC) met with the offices of President Alice Reynolds and Commissioner John Reynolds, emphasizing that the current Transmission Planning Process and busbar mapping process overlooks natural-gas generation paired with carbon capture and sequestration (NGCCS). CRC argued that this technology is already commercially viable and capable of delivering near-term, clean-firm capacity.
• CRC highlighted that its Elk Hills Carbon Terravault I project will begin CO₂ injection in Q1 2026, that additional Class VI permits are imminent, and that retrofitting existing plants such as Elk Hills and La Paloma could provide over 1.1 gigawatts of decarbonized capacity using existing interconnections. CRC maintained that NGCCS reduces both carbon and criteria pollutants, offers cost-effective firm power, and should therefore be eligible in any additional reliability procurement the Commission may order.

California Community Choice Association

• On the same day, the California Community Choice Association (CalCCA) held separate ex parte meetings with advisors to Commissioners Darcie Houck and Karen Douglas.
• CalCCA warned that ad hoc procurement orders create market distortions, shift leverage to developers, and may unnecessarily raise costs. They presented historical load-forecast data showing unprecedented uncertainty in the 2024 Integrated Energy Policy Report forecast and urged the Commission to take a cautious, flexible approach before mandating new procurement.
• CalCCA also argued that further study is needed before modifying import assumptions, citing publicly available Western Electricity Coordinating Council data. If the Commission nonetheless orders procurement, CalCCA recommends a two-tranche structure totaling 4,000 megawatts between 2029 and 2032, with a 2027 reassessment to incorporate updated load and import information.
• CalCCA further advocated for individual load-serving entity procurement obligations, use of excess procurement toward future requirements, generic capacity (rather than technology-specific) mandates, and the continued application of extended compliance provisions adopted in a decision last September (D.25-09-007)

INSTANT ANALYSIS: CRC is pushing the Commission to treat NGCCS as a near-term clean-firm resource, arguing it can be deployed quickly at existing gas sites with real Class VI permits in hand, while CalCCA urges caution on any additional procurement. CalCCA points to unprecedented load-forecast uncertainty and the risk of repeating costly, ad hoc procurement cycles. The meetings highlight a core tension in this rulemaking: whether to expand the clean-firm toolkit now or wait for clearer load and import signals before authorizing another statewide procurement mandate.

Long-Duration Storage

The CPUC issued Draft Resolution E-5437, which approves PG&E’s long-duration storage contract with the Balsam Project LLC for:

• A 225-MW Dirac Battery Energy Storage System; and
• An eight-hour lithium-ion facility expected online by May 20, 2028 and delivering Resource Adequacy beginning August 1, 2028.

The contract emerged from PG&E’s Long-Lead-Time Mid-Term Reliability solicitation and is intended to satisfy a portion of the utility’s long-duration storage obligations under the following decisions:

• D.21-06-035;
• D.23-02-040; and
• D.25-06-005.

The Draft Resolution finds PG&E’s solicitation, bid evaluation, and Independent Evaluator review to be reasonable, concluding that the project represents a competitively selected, cost-effective option for meeting Mid-Term Reliability requirements.

Costs will be recovered through the Portfolio Allocation Balancing Account and assigned a 2021 Power Charge Indifference Adjustment vintage. The draft resolution also affirms that the project meets updated eight-hour dispatch requirements. The earliest the CPUC will consider this item is January 15.

INSTANT ANALYSIS: This draft resolution advances PG&E’s long-duration procurement by approving a vetted 225-MW, eight-hour storage project that satisfies the Commission’s strengthened Mid-Term Reliability requirements. It affirms that PG&E’s solicitation, evaluation, and cost-recovery approach meet CPUC expectations, reinforcing a shift toward genuinely long-duration resources in the 2028 portfolio.

Diablo Canyon

PG&E filed Advice Letters 7776-E and 7777-E to provide the CPUC with its latest semiannual reporting on Diablo Canyon–related costs pursuant to a 2022 decision (D.22-12-005).

• AL 7776-E reports that the Department of Water Resources (DWR)’s Spring 2025 true-up found all $193.9 million in PG&E’s license-renewal and transition costs recorded in the Diablo Canyon Transition and Relicensing Memorandum Account to be eligible, reasonable, and in the public interest. DWR found no reason for disallowances, bringing total allowable loan proceeds approved to date to $850.9 million.
• AL 7777-E provides the parallel record of Diablo Canyon Extended Operations Balancing Account costs for the same October 2024–March 2025 period. These costs total $172.6 million in plant operations, maintenance, projects, fuel procurement, and employee-retention expenses, plus $14.7 million in volumetric performance-fee-related hydro expenditures, none of which are subject to DWR review but must be reported semiannually under the same statutory schedule.

Protests are due December 24.

INSTANT ANALYSIS: These filings show that Diablo Canyon’s extension continues to move through the cost-tracking framework with no friction. DWR again validated 100% of PG&E’s relicensing and transition spending, while the utility logged nearly $190 million in additional extended-operations and performance-fee costs that will flow through the Diablo Canyon Extended Operations Balancing Account. Financial commitments for continued operation are accelerating cleanly, with no disallowance pressure emerging in the semiannual cycle.

Rule 30 Implementation

PG&E filed Advice Letter 7772-E to correct and refile its interim Electric Rule 30 tariff and associated form agreements after Energy Division rejected its prior filing (AL 7671-E).

Recall that a decision last summer (D.25-07-039) required PG&E to implement Rule 30 on an interim basis and to submit updated tariff language within 15 days. However, when PG&E filed AL 7671-E, Cal Advocates protested, and Energy Division subsequently rejected the filing because it did not clearly require 100% pre-funding of all Transmission Network Upgrades (Facility Type 4) attributable to a customer’s retail-service request.

In this new submission, PG&E revises Section F.5 of Rule 30 (and the companion form agreement) to explicitly require applicants to finance the entire cost of Network Upgrades through a pre-funding loan, pay associated Income Tax Component of Contribution (ITCC) taxes, and accept that repayment terms will be determined later in A.24-11-007.

PG&E's new filing attaches redlined and clean versions of both documents. Protests are due December 24.

INSTANT ANALYSIS: This filing closes a loophole from PG&E’s earlier submittal and makes explicit what Energy Division already indicated: any large-load customer triggering Transmission Network Upgrades must now finance 100% of those costs upfront, including ITCC. The unresolved repayment framework in A.24-11-007 remains the key variable, but until that decision lands, project developers should assume full capital exposure and plan accordingly.

Public Utility Regulatory Policies Act of 1978 (PURPA)

PG&E filed an advice letter to propose a small, corrective change to its E-ELEC tariff (PG&E’s Residential Time-of-Use “Electric Home” rate) to address an unintended gap created by the Net Billing Tariff (NBT) and prevailing-wage enforcement rules.

Under current language, an NBT customer who is forced onto the PURPA-compliant tariff due to a contractor’s willful prevailing-wage violation could lose eligibility for E-ELEC. PG&E seeks to allow these customers (expected to be very few) to remain on E-ELEC despite not meeting the usual technology requirements, arguing this avoids unnecessary rate changes and administrative confusion during the transition.

INSTANT ANALYSIS: PG&E proposes a narrow fix to ensure NBT customers forced onto the PURPA-compliant tariff due to their contractor’s wage violations can remain on E-ELEC. This is an administrative cleanup filing that reveals how the Commission’s new prevailing-wage enforcement is beginning to interact with existing electrification rate design.