FRIDAY AGGREGATE: DER Flexible Connections; IRP Procurement; Gas Distribution Cost Data

Regulatory activity this week ricochets between near-term innovation and longer-term strategic uncertainty.

• PG&E's DER flexible connections filing shows the utility examining meter-based workarounds for panel upgrades while the broader ADMS/DERMS modernization remains years away.
• CalCCA's continued pushback on additional IRP procurement orders highlights a serious issue now facing the Commission: whether to direct thousands more megawatts of capacity based on unprecedented load forecasts, or wait until 2027 for better visibility on data-center interconnections and import availability.

Elsewhere, contract amendments reflect persistent storage-market pressures, routine transmission and ERRA compliance items are in the mix, and tariff clarifications close loops from prior decisions.

DISTRIBUTED ENERGY RESOURCES

PG&E filed a supplemental response to an Assigned Commissioner’s Ruling seeking additional information on near-term, DER-enabled flexible connections for single-phase customers in the CPUC's High DER Future docket.*

PG&E says it is developing a suite of approaches (ranging from traditional service upgrades to new AMI-2.0-enabled controls) to help residential customers electrify without immediate panel or service upgrades.

• A key part of the work is an Electric Program Investment Charge-funded pilot that uses an AMI 2.0 meter running a local DER management application, which communicates with peer meters and customer devices to calculate and enforce real-time dynamic service limits based on local grid capacity.
• PG&E describes this as a residential, secondary-system version of Flex Connect intended to minimize or defer upgrades while keeping load within safe limits.
• PG&E outlines expected implementation steps, identifies protocols such as Open Charge Point Protocol 1.6J and UL 3141/Matter for device coordination, and explains how aggregators or manufacturers could scale multi-customer coordination across shared infrastructure.
• PG&E argues that current rules already allow dynamic operating envelopes and opposes mandatory enrollment of these customers into dynamic rate pilots, citing both customer choice and the potential mismatch between operating-envelope constraints and price-response opportunities.

The company anticipates early customer testing in 2026 and a broader rollout (contingent on proof-of-concept results) and approval of AMI 2.0 in its General Rate Case.

INSTANT ANALYSIS: This filing reinforces the broader picture that California is still years away from systemwide, customer-level dynamic envelopes. However, PG&E's exploration of a narrower, meter-based pathway could enable early flexible connections for single-phase residential customers. While PG&E's AMI-2.0 edge-control concept doesn’t eliminate the multi-year runway facing Advanced Distribution Management System/Distributed Energy Resource Management System modernization, it does suggest that limited, local forms of flexible interconnection may emerge sooner for panel-upgrade deferral, even as full circuit-level dynamic operations remain out of reach.

LONG-TERM GAS PLANNING

Separately, PG&E submitted an amended response in the Long-Term Gas Planning rulemaking to correct and clarify the gas distribution cost data it previously filed on November 5.

After reviewing PG&E’s original submission, Energy Division requested specific corrections, including fixing an “average” that should have been a “total” in one row and revising the dataset to include only medium-pressure regulator stations to ensure comparability across utilities.

The amended filing republishes the data with corrected summary and district-level cost figures for regulator-station replacement work, covering such metrics as per-service and per-meter replacement costs, total recorded work-order expenditures, and planning and construction durations. For SoCalGas/SDG&E's equivalent filing, see our summary here.

INSTANT ANALYSIS: PG&E’s amended filing is a technical correction, but it matters for the Commission’s emerging gas-distribution cost baseline in this proceeding. The main takeaway is that PG&E’s average regulator-station rebuild cost remains extremely high ($3.0 million per station; $1,224 per service) and planning durations remain long (782 days). These numbers will inform future debates about gas portfolio right-sizing, district-level risk targeting, and long-run rate impacts.

PG&E NATURAL GAS RATES

The CPUC issued a ruling in PG&E's 2027 Gas Cost Allocation and Rate Design case ("GCARD"), adjusting the normal 30-day protest window because it would otherwise fall during the year-end holidays. The ruling extends the protest deadline to January 7, 2026, with PG&E’s reply due January 20, 2026.

As previously noted at CRI, this filing combines PG&E's historically separate Gas Cost Allocation Proceeding and Gas Transmission & Storage CARD into a single, unified framework.

• The proposal recalibrates distribution, transmission, storage, and inventory-management costs using updated 2027–2030 forecasts, a shift to embedded-cost distribution methods, revised backbone path differentials, a new empirical imbalance-cost model, and an increase to the residential minimum monthly charge from $4 to $15.
• While falling backbone and inventory-management costs look to provide short-term relief (especially for residential customers in 2027) projected increases in storage revenue requirements and class rebalancing drive future upward pressure on rates, with small commercial, industrial, and certain wholesale/noncore groups seeing the largest impacts.

INSTANT ANALYSIS: This ruling is purely procedural but still relevant: it pushes protest deadlines into January, ensuring parties have a full opportunity to develop substantive objections or proposals rather than rushing through the holiday period.

INTEGRATED RESOURCE PLANNING

The California Community Choice Association (CalCCA) met with Commissioner Matt Baker’s advisors on December 8 to outline its concerns with issuing another near-term procurement order in the Integrated Resource Planning proceeding.

• CalCCA emphasized that ad hoc procurement directives tend to distort markets, elevate developer leverage, and raise costs, noting Sonoma Clean Power’s experience before and after recent procurement mandates.
• To mitigate these effects, CalCCA described its proposal to mask individual load-serving entities' net positions in reporting so that procurement orders do not unintentionally shift market power.
• CalCCA then presented data comparing historic load forecasts to actual load, arguing that the unprecedented, highly uncertain load growth embedded in the 2024 Integrated Energy Policy Report update warrants a cautious approach.
• CalCCA suggested that if the Commission ultimately orders new reliability procurement, it should adopt a phased, flexible structure (2,000 MW in 2029–2030 and another 2,000 MW in 2031–2032) paired with a 2027 reevaluation that could incorporate updated information on large-load interconnections and import availability.

CalCCA also recommended several design features for any order: crediting excess procurement toward future compliance, assigning procurement to load-serving entities rather than a central buyer, using generic (not technology-specific) capacity requirements, and applying the extended compliance rules previously adopted in a decision last September (D.25-09-007).

For details on CalCCA's recent IRP meeting with Commissioners Darcie Houck and Karen Douglas, see our summary here.

INSTANT ANALYSIS: CalCCA is urging the Commission to pause before directing any additional procurement, pointing to the 2024 IEPR’s extraordinary load uncertainty and the unresolved questions around future import availability. Their proposed two-tranche framework reflects the central debate in this rulemaking:

• Act now to expand clean-firm capacity; or
• Wait until the state has a clearer read on load growth, large-load interconnection activity, and Western Resource Adequacy conditions before committing load-serving entities to another large procurement cycle.

MID-TERM RELIABILITY

The Commission issued Draft Resolution E-5432, which approves PG&E’s request to further amend its Mid-Term Reliability contract with Nighthawk Energy Storage, LLC (an Arevon Energy affiliate) by extending the project’s required online date from June 1, 2025 to June 1, 2026 and adjusting the contract price to reflect current market conditions.

The Nighthawk project, originally approved in 2022 as part of PG&E’s Mid-Term Reliability procurement obligation, has faced successive delays due to interconnection challenges, permitting issues, supply-chain pressures, inflationary cost increases, and higher financing costs.

Energy Division finds PG&E’s negotiated amendment reasonable, noting that absent this relief the developer would likely default, jeopardizing a 300-megawatt storage resource essential to PG&E’s Mid-Term Reliability compliance. The Draft Resolution, which is redacted, concludes that the revised price remains competitive in the current market and that the project (now permitted, financed, and holding a CAISO interconnection agreement) has a credible path to meeting the amended June 1, 2026 delivery date.

The earliest the Commission will consider this item is January 15.

INSTANT ANALYSIS: This third amendment reflects the Commission’s preference to preserve a contracted 300-MW storage asset rather than risk losing it to default. The draft resolution finds a one-year delay and higher price less harmful than replacing the project mid-stream.

ERRA COMPLIANCE

The CPUC issued a proposed decision finding that SCE’s 2022 Energy Resource Recovery Account procurement, generation management, and contract administration were largely compliant with CPUC standards and SCE's Bundled Procurement Plan.

The PD authorizes recovery of $51.442 million in undercollected balances across five memorandum accounts (mainly tied to the Emergency Load Reduction Program) resulting in an estimated $0.45/month residential bill impact in 2026.

SCE must remove CAISO sanctions from the ERRA/Portfolio Allocation Balancing Account because it failed to justify them and refund $1.65 million in double-charged franchise fees to departed customers via a 2026 PABA adjustment.

INSTANT ANALYSIS: This is a straightforward item. The PD gives SCE a largely clean ERRA compliance review for 2022, authorizing recovery of $51.442 million in undercollections. Additionally, the PD affirms prudent management of utility-owned generation and contracts while imposing targeted corrections for CAISO sanctions and PABA franchise-fee overcollections, which must be refunded to customers.

TRANSMISSION/FERC

PG&E filed an advice letter to notify the CPUC that it has submitted its annual Transmission Access Charge Balancing Account Adjustment (TACBAA) update to FERC, requesting new transmission rates effective March 1, 2026.

The TACBAA ensures PG&E’s retail customers either recover or refund the difference between the transmission costs PG&E pays as a load-serving entity and the revenues it earns as a Participating Transmission Owner under the CAISO Tariff.

In its December 5 FERC filing, PG&E reports a total 2026 TACBAA revenue requirement of $591.1 million, driven by a projected $20.8 million credit balance, $604.0 million in forecast TACBA costs for the coming period, and $8 million in revenue-fee and uncollectible adjustments. The resulting rate of $0.00908/kWh would be an increase from the current $0.00770/kWh.

PG&E requests authority to automatically update retail-jurisdictional tariffs once FERC authorizes the change, with adjustments typically consolidated into PG&E’s late-February retail rate filings. The rate change will apply to bundled, Direct Access, and Community Choice Aggregator customers. PG&E will later supplement the advice letter once FERC acts on the filing. Protests are due December 30.

INSTANT ANALYSIS: This TACBAA update points to a modest upward pull on March 1 retail transmission rates, driven primarily by higher forecast TACBA costs rather than true-up volatility. While routine, the increase folds into an already crowded March rate stack, meaning bundled, Direct Access, and Community Choice Aggregator customers should expect incremental pressure on total delivered prices.

PURPA

The CPUC issued Draft Resolution E-5425, which approves, with modifications, PG&E’s and SDG&E’s proposed PURPA-compliant export tariffs for customer-generators who lose Net Energy Metering or Net Billing eligibility due to prevailing-wage violations under the Public Utilities Code and a 2023 CPUC decision (D.23-11-068).

The draft resolution concludes that while the filings generally comply with the decision, an explicit 20-megawatt capacity limit must be added to align with PURPA’s mandatory-purchase rules and the 20-MW standard-offer framework in a 2020 Commission decision (D.20-05-006).

PG&E, SDG&E, and SCE to update must refile their PURPA tariffs accordingly. The earliest the CPUC will consider this item is January 15.

INSTANT ANALYSIS: This draft resolution closes the loop on the wage-violation backstop tariff by standardizing all PURPA export treatment around a 20-MW cap, aligning state practice with federal purchase-obligation limits and eliminating ambiguity that emerged after D.23-11-068. For developers and large customers, this resolves questions about how oversized NEM/NBT projects would be treated if they fall into PURPA status, while requiring all three utilities to operate from a uniform, legally defensible tariff framework.

FOOTNOTE

*For additional coverage on this DERs matter, see our summary here, where the utilities indicated that California is unprepared to operationalize dynamic or customer-level operating envelopes. All three utilities acknowledge that their Advanced Distribution Management System/Distributed Energy Resource Management System stacks lack the forecasting granularity, telemetry, modeling fidelity, and communications architecture needed to support day-ahead or hour-ahead import/export limits across the polyphase grid.