FRIDAY AGGREGATE: Scoping Memo Lands in CPUC's Demand Response Rulemaking
Today's end-of-week roundup includes:
- A scoping memo in the CPUC's Demand Response rulemaking confirming that the CPUC is moving toward a comprehensive reset of DR policy, not just a bridge-year funding patch;
- PG&E's opposition to a motion by Cal Advocates, TURN, and CLECA to pause the Electric Rule 30 proceeding on transmission-level retail electric service;
- SoCalGas's response to parties who protested its Advanced Meter Infrastructure Replacement Project;
- A new proposed decision authorizing SCE to issue up to $9.85 billion in new debt and $1.155 billion in preferred equity;
- An SDG&E advice letter that seeks CPUC approval of amendments to long-term bundled renewable energy sales agreements with San Diego Community Power and Clean Energy Alliance; and
- A SDG&E request for CPUC approval to update the definition of “mixed-fuel” in its electric and gas service rules to reflect prior Commission guidance on building electrification policy.
DEMAND RESPONSE
Commissioner John Reynolds issued a scoping memo in R.25-09-004, which is focused on enhancing Demand Response programs across California by improving their consistency, predictability, reliability, cost-effectiveness, and integration with markets and dynamic rates.
The ruling establishes the schedule for addressing topics such as:
- Extending funding for existing Demand Response programs authorized in prior decisions;
- Continuing the Flex Alert marketing campaign;
- Updating guiding principles for Demand Response policy; and
- Developing standardized data systems and communication protocols to support these resources.
The ruling also raises questions about valuation methods, dual participation, Resource Adequacy treatment, cost-effectiveness evaluation methodology, prohibited resource policy, and CAISO integration, portending a broad review of how DR is planned, measured, and compensated.
The memo says that evidentiary hearings may be required for the bridge-year funding issue and adopts a detailed timeline the Commission intends to complete within 24 months, with separate tracks for bridge funding decisions, Flex Alert funding, and data-system reforms.
INSTANT ANALYSIS: This scoping memo confirms that the CPUC is moving toward a comprehensive reset of DR policy, not just a bridge-year funding patch. The scope inclusion of data systems, valuation methods, resource adequacy treatment, and CAISO integration indicates the Commission is preparing to treat DR as a fully operational grid resource rather than a seasonal emergency tool. Parties with exposure to Resource Adequacy, dynamic pricing, DER aggregation, or load flexibility markets should view this as groundwork for future procurement rules and compensation frameworks.
Perhaps most important for near-term planning: the timeline creates a regulatory gap that stakeholders need to manage. The ruling calls for two distinct engagement tracks:
- Near-term fights over money and program continuation; and
- Longer-term battles over market design and data infrastructure.
Bridge-year funding decisions are expected to land in Q3 or Q4 of 2026, well before deeper policy matters are finalized, meaning stakeholders will likely have to operate under temporary rules while the Commission builds a new DR regime.
TRANSMISSION-LEVEL RETAIL SERVICE
PG&E recently filed its opposition to a motion by Cal Advocates, TURN, and CLECA to pause the Electric Rule 30 proceeding on transmission-level retail electric service. PG&E says it will file a motion for leave to submit supplemental testimony on February 13, covering three topics:
- Revisions to its proposed minimum demand charge methodology;
- An option for transmission-level customers to perform undergrounding and certain Facility Type 3 work under the Applicant Build Option; and
- Additional ratepayer protections in the Electric Rule 30 form agreement.
PG&E moved this filing up from February 18 and agreed to expedited five-business-day discovery turnaround, framing both concessions as good-faith responses to concerns raised by intervenors on a February 9 call. It argues the current schedule allows fair participation and that an open-ended delay would push a decision well past the expected mid-2026 timeframe.
PG&E cites the Commission's own November 2025 comments to FERC (Docket No. RM26-4-000) stating the CPUC expects to issue a decision on Electric Rule 30 by mid-2026, arguing the intervenors' stay request contradicts the Commission's representations to a federal agency.
Additionally, PG&E warns that a long delay would force large customers to keep negotiating one-off agreements instead of using a uniform tariff, prolonging uncertainty on cost responsibility and ratepayer protections. It frames this status quo as harmful to both existing ratepayers and prospective transmission-level customers (the very constituencies represented by Cal Advocates, TURN, and CLECA). If the Commission wants more time, PG&E proposes a revised spring 2026 schedule rather than an indefinite stay. It asks the Commission to deny the motion or adopt that alternative timeline to keep the case within statutory deadlines.
An attached email chain tells its own story: Cal Advocates gave PG&E roughly two hours' notice before filing the motion to stay, initially declined to take a call, and never responded to PG&E's proposed alternative schedule before filing unilaterally with TURN and CLECA. PG&E clearly wants this procedural record before the ALJ.
INSTANT ANALYSIS: We are witnessing a battle over whether transmission-level retail service moves from bespoke approvals to a standardized tariff. The current environment is flexible but discretionary, with projects advancing through negotiated agreements that still require Commission sign-off. PG&E wants a predictable framework but intervenors may prefer retaining leverage that comes from case-specific scrutiny. The intervenors' interest in coordinating with PG&E's 2027 General Rate Case (raised on the February 9 call) suggests they want to tie Rule 30 cost-allocation questions to the broader rate case, which would give them more leverage over how costs flow through but could delay resolution into late 2026 or 2027. For developers and large loads, the real question is flexibility versus certainty. The current path allows tailored deals but carries approval risk and timing uncertainty, while a Rule 30 tariff would create a defined lane with known cost rules.
NATURAL GAS ADVANCED METERING INFRASTRUCTURE
SoCalGas filed a reply to protests from Cal Advocates and TURN, and a response from the Small Business Utility Advocates, regarding its Advanced Meter Infrastructure Replacement Project, arguing that the filings provide no valid basis to deny or defer the proposal.
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SoCalGas maintains that replacing aging meter communication modules through a standalone proceeding is appropriate, necessary to avoid system failures and higher long-term costs, and consistent with prior Commission practice for large projects. It cites decisions in which the Commission directed SDG&E and permitted PG&E to file standalone applications for their own AMI replacement programs.
SoCalGas:
- Rejects claims that the project should instead be handled in a future general rate case;
- Disputes allegations that it failed to justify costs or alternatives; and
- Clarifies that the work largely involves replacing communication modules rather than gas meters themselves, with minimal expected service disruption.
SoCalGas also pushes back on TURN's call for a retrospective review of SoCalGas's original smart meter system (AMI 1.0). SoCalGas asserts that AMI 1.0 outperformed its original business case and that this was already demonstrated in the Test Year 2019 General Rate Case and through semi-annual reports filed with the Commission's Energy Division.
On accounting treatment, SoCalGas distinguishes two mechanisms:
- The Advanced Meter Infrastructure Replacement Memorandum Account is an interim cost-tracking tool filed via separate motion; SoCalGas argues it should not be litigated in this proceeding; and
- The Advanced Meter Infrastructure Replacement Balancing Account is the cost-recovery vehicle through which authorized costs would ultimately be recorded and recovered in rates. SoCalGas agrees this account is properly within scope.
SoCalGas otherwise outlines what issues it considers properly within the proceeding's scope: project prudence, cost forecasts, cost allocation among customer classes, and treatment of stranded assets. It argues that Cal Advocates' proposal to allocate project costs to shareholders is improper and "confiscatory." SoCalGas invokes the regulatory compact framework and foundational ratemaking precedent from Hope Natural Gas and Bluefield to support that position.
INSTANT ANALYSIS: SoCalGas is trying to keep its AMI replacement project on a fast, standalone track rather than letting intervenors move it into the next General Rate Case, which would slow approval and expand the scope of review. SoCalGas holds that aging meter communication modules pose an operational risk if replacement authority is delayed, and it characterizes timely approval as necessary to avoid reactive repairs and higher costs later.
Readers with exposure to gas utility capital plans, rate impacts, meter data infrastructure, or electrification strategy should watch this proceeding. A CPUC decision allowing the project to proceed independently would show that large gas infrastructure replacements can move outside the crowded GRC process. A decision forcing consolidation into broader proceedings would indicate tougher scrutiny of long-term gas investments going forward.
TURN's push for a retrospective benefits review of AMI 1.0 is worth tracking as a proxy fight over whether the Commission should apply greater skepticism to the next generation of gas metering investment, particularly for a gas-only utility with no electric portfolio to fall back on.
UTILITY FINANCES
A new proposed decision would authorize SCE to issue up to $9.85 billion in new debt and $1.155 billion in preferred equity, a $525 million reduction that SCE itself proposed after updating forecasts to reflect the CPUC's 2025 General Rate Case decision (D.25-09-030). The funds would finance capital expenditures, refinance maturing obligations, and address wildfire-related liabilities through 2028.
The authority would also allow SCE to use various financing tools such as hedges, swaps, credit facilities, guarantees, and the pledging of utility assets or accounts receivable to lower borrowing costs and manage risk, with proceeds intended to support grid safety, reliability, modernization, and wildfire mitigation investments.
- The PD emphasizes that granting financing authority does not approve specific projects or cost recovery in rates; those issues would be evaluated in separate proceedings.
- The PD also responds to concerns from consumer advocates and small-business representatives about potential over-borrowing and double recovery of wildfire costs by noting that any borrowing must ultimately be repaid by the utility and remains subject to later regulatory review. The PD rejects Cal Advocates' calls for a cost-effectiveness analysis and the Small Business Utility Advocates' request for additional evidentiary filings, finding the supplemented record sufficient.
Comments are due March 4. The earliest the CPUC will consider this item is March 19.
INSTANT ANALYSIS: This PD is a major financing authorization that positions SCE to fund wildfire liabilities, grid hardening, and capital programs through 2028 without returning repeatedly to the CPUC for incremental approvals. It ensures liquidity and balance-sheet flexibility at a moment when wildfire exposure, infrastructure spending, and refinancing needs are converging, while preserving Commission oversight by separating financing authority from cost-recovery determinations.
For market participants, the main takeaway is timing and scale: once approved, SCE gains a large, pre-cleared borrowing envelope that can be deployed opportunistically based on interest rates and financing conditions. Stakeholders exposed to rates, utility credit, wildfire cost recovery, or capital planning should track how quickly SCE draws on this authority, because proceedings downstream of this one will ultimately determine who pays.
POWER CHARGE INDIFFERENCE ADJUSTMENT ALLOCATIONS/CCA PORTFOLIO MANAGEMENT
SDG&E submitted Advice Letter 4803-E (available here) seeking CPUC approval of amendments to long-term bundled renewable energy sales agreements with San Diego Community Power and Clean Energy Alliance.
The amendments modify the contract end dates for a portfolio of 26 PCIA-eligible renewable projects totaling roughly 2,000+ MW of solar PV and wind so that the allocation terms run through the end of the longest contract in the relevant PCIA portfolio, as required by a 2021 CPUC decision (D.21-05-030).
The two amendments differ slightly:
- For San Diego Community Power, the fixed December 31, 2033 end date is replaced with an open-ended term tied to when SDG&E stops receiving product from the project contracts; and
- For Clean Energy Alliance, the original term (tied to the 10th anniversary of the Start Date) is similarly extended but includes a hard backstop of December 31, 2042.
SDG&E states that no other contract provisions would change and that the updates are needed to comply with the Commission's voluntary allocation framework for renewable resources and associated credits previously approved in Resolution E-5206. Protests are due March 4.
INSTANT ANALYSIS: This is technical compliance filing that keeps San Diego Community Power and the Clean Energy Alliance tied to legacy utility renewable contracts for the full duration of the longest PCIA-eligible agreements, preserving existing cost responsibility. The impact is on long-term PCIA exposure and planning assumptions, not procurement policy or near-term market conditions. The Clean Energy Alliance backstop date of 2042 effectively caps that CCA's maximum exposure window, while SDCP's open-ended language leaves its commitment tied entirely to SDG&E's underlying contract portfolio.
BUILDING ELECTRIFICATION POLICY
SDG&E filed Advice Letter 4804-E/3496-G (available here) seeking CPUC approval to update the definition of “mixed-fuel” in its electric and gas service rules to reflect prior Commission guidance on building electrification policy.
The revision would classify new construction projects as mixed-fuel if they either use gas or are stubbed for future gas or propane service, while projects without gas stubs would be treated as all-electric and remain eligible for electric line-extension subsidies.
The changes implement earlier CPUC decisions eliminating subsidies for mixed-fuel new construction as part of the state’s greenhouse-gas reduction strategy (including D.25-06-034's extension of the original implementation deadlines). Their purpose is to ensure consistent utility treatment of subsidy eligibility across projects.
INSTANT ANALYSIS: This filing puts the CPUC’s building electrification policy into SDG&E’s tariffs by tying subsidy eligibility to whether new construction is designed to accommodate gas service, not just whether gas is initially used. By treating projects stubbed for gas as mixed-fuel, SDG&E closes a common developer workaround and increases the financial pressure to commit to fully electric designs upfront. The change does not affect rates or procurement, but it directly shapes project economics, interconnection planning, and future load growth by steering new development toward all-electric pathways aligned with prior CPUC decisions.