MONDAY AGGREGATE: Water District Petition Suggests Crack in SGIP Program Logic; CAISO Documents Multi-State Market Options
Today's roundup includes summaries of the following items.
- A new petition for modification of a 2011 CPUC decision governing the Self-Generation Incentive Program that exposes a mismatch between SGIP’s site-based sizing rules and the portfolio-based self-generation model explicitly authorized for local governments under the Renewable Energy Self-Generation Bill Credit Transfer framework.
- The CAISO's Assembly Bill 825 Report, a document that preserves optionality for a potential expansion of voluntary, multi-state wholesale electricity markets governed by an independent regional organization.
- A ruling in PG&E's 2024 ERRA Compliance filing that addresses a narrow vintaging issue affecting a small subset of Community Choice Aggregator customers.
- A 2025 Demand Response audit detailing compliance with CPUC rules prohibiting the use of certain fossil-fueled distributed generation resources to produce DR load reductions.
- An SDG&E informational filing that confirms the Department of Energy's rescission of the ARCHES hydrogen hub award and issuance of a termination directive.
SELF-GENERATION INCENTIVE PROGRAM
Moulton Niguel Water District filed a petition seeking to modify a 2011 decision (D.11-09-015) governing the Self-Generation Incentive Program (SGIP). The petition argues that current SGIP sizing rules conflict with the Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT) framework available to local governments.
The District plans to install a 224-kW in-conduit micro-hydropower system at its Bridlewood Flow Control Facility that would generate roughly 820 MWh annually (far more than the facility’s onsite load) and apply the excess generation as bill credits across its broader portfolio of SDG&E accounts under RES-BCT.
While RES-BCT explicitly allows this portfolio-wide self-generation model, the SGIP Handbook limits incentives to generation sized to the load at the physical site, effectively disqualifying much of the project’s capacity. The District asks the Commission to clarify that a local government participating in RES-BCT is still “offsetting onsite load” within the meaning of Public Utilities Code section 379.6(e)(1), and therefore eligible for SGIP incentives for the full system capacity. The petition asks the CPUC to direct program administrators to update the SGIP Handbook accordingly.
The petition emphasizes that aligning SGIP with RES-BCT would remove an internal policy inconsistency and unlock stranded SGIP Generation budget funds.
ADDED CONTEXT: This petition arrives under a procedural cloud. Nine days before Moulton Niguel re-filed, Commissioner Karen Douglas issued a proposed decision denying Bloom Energy's petition to increase the SGIP export cap from 25% to 50% (see CRI's coverage here).
MC
The PD rejects Bloom's justification that technology evolution excused a 13-year delay, finding that routine technological or policy change cannot justify reopening settled decisions.
Moulton Niguel's petition faces the same timeliness hurdle but may present a stronger case. Unlike Bloom's export-cap request (which the PD characterizes as inconsistent with SGIP's load-serving purpose), Moulton Niguel's request reinforces rather than undermines that purpose: it seeks to count portfolio-wide load for RES-BCT participants, not to enable greater grid exports.
INSTANT ANALYSIS: This petition exposes a consequential mismatch between SGIP’s site-based sizing rules and the portfolio-based self-generation model explicitly authorized for local governments under RES-BCT. Moulton Niguel’s project is baseload, conduit hydropower that converts otherwise wasted pressure into continuous clean generation, with clear grid, emissions, and resiliency benefits.
- The policy issue is narrow: whether “onsite load” under SGIP can be interpreted at the local-government portfolio level when RES-BCT is used. Energy Division staff previously endorsed that interpretation, and the administering program administrator supports it, suggesting limited institutional resistance.
- Denial risks stranding remaining SGIP Generation funds while discouraging a class of infrastructure-adjacent distributed resources that perform well during peak and emergency conditions.
CAISO NEWS/ASSEMBLY BILL 825
The CAISO submitted its 2026 Assembly Bill 825 Report to the Legislature, which provides a comprehensive accounting of CAISO activities in 2025 as required under Assembly Bill 825. Recall that this legislation was enacted to support the potential expansion of voluntary, multi-state wholesale electricity markets governed by an independent regional organization.
The report explains that, beginning no earlier than 2028, the CAISO could pursue FERC-approved tariff changes to enable such a transition, but only if statutory conditions are met, the CAISO Board affirms compliance, and the CPUC authorizes IOU participation. For 2025, the report is limited to CAISO-only activities, as the regional governance entity contemplated by AB 825 remains in formation.
- The report documents extensive federal tariff activity during 2025, including compliance filings, market-design amendments, interconnection agreements, EDAM-related changes, and settlements, most of which were approved by FERC. These filings span transmission service priorities, interconnection process reforms, billing and credit rules, market enhancements for storage, congestion revenue allocation, capacity procurement mechanisms, and agreements enabling broader Western market participation through the EDAM and Western Energy Imbalance Market.
- The report also outlines the status of the CAISO’s major policy initiatives and recurring processes, emphasizing a structured, stakeholder-driven roadmap for market evolution. Active initiatives in 2025 included congestion revenue rights enhancements, day-ahead and extended day-ahead market development, demand and distributed energy integration, storage market design, gas resource management, greenhouse gas coordination, price formation reforms, and Resource Adequacy modeling updates. Additionally, the CAISO continued its transmission planning cycles and independent release process to coordinate implementation timing and system needs.
- The report further catalogs actions taken by the CAISO Board of Governors throughout 2025, including approvals of market design changes, interconnection reforms, EDAM congestion revenue allocation, Resource Adequacy modeling updates, transmission planning decisions, budget adoption, and governance matters. These actions reflect ongoing oversight of both grid reliability and evolving wholesale market frameworks.
- The report summarizes assessments by the CAISO’s Department of Market Monitoring, which serves as the independent market monitor for both CAISO markets and the Western Energy Imbalance Market. It references annual and quarterly market performance reports, resource sufficiency evaluations, special studies on Demand Response and battery storage, and formal comments submitted to FERC and within CAISO stakeholder processes.
The report concludes with a description of transmission planning activities, highlighting how CAISO evaluates reliability, public-policy, and economic needs through its annual transmission planning process in coordination with state agencies and stakeholders.
The ISO Board approved the 2024-2025 Transmission Plan in May 2025, recommending 31 transmission upgrades totaling an estimated $4.8 billion in infrastructure investment. The plan enables over 30 GW of solar, 7 GW of onshore wind, 2 GW of geothermal, 9 GW of out-of-state wind imports, and 4.5 GW of offshore wind capacity (reflecting accelerated load growth, including a Greater Bay Area peak demand forecast increase of over 2,000 MW compared to the prior cycle).
This coordinated approach follows a December 2022 Memorandum of Understanding among the CAISO, CPUC, and California Energy Commission to better align linkages between resource planning, transmission development, interconnection queuing, and procurement. The report also notes that the CAISO filed for compliance with FERC Order No. 1920 in December 2025, which will require a transition from annual to biennial comprehensive transmission planning beginning in 2028, with a new 20-year planning horizon for regional facilities.
INSTANT ANALYSIS: This report is a compliance and informational document, not a decision memo. It confirms that the CAISO spent 2025 laying procedural track (tariff hygiene, EDAM expansion, interconnection reform, and governance choreography) while keeping the statutory bar for any future regionalization deliberately high.
Nothing here commits California to a multi-state market shift; instead, it preserves optionality by documenting readiness, process discipline, and federal alignment. The key takeaway is timing: the earliest legal pivot point remains 2028, and only if the CPUC, the CAISO Board, and FERC all independently concur. Until then, AB 825 functions as a guardrail, allowing exploration without surrendering state control.
On the transmission side, the $4.8 billion in approved projects and the pivot to longer-horizon planning under Order 1920 indicate that California is building the physical infrastructure for decarbonization at scale, independent of whether regionalization ultimately proceeds.
ENERGY RESOURCE RECOVERY ACCOUNT/UTILITY-OWNED GENERATION COMPLIANCE
ALJ Goldberg issued a ruling in PG&E's 2024 ERRA Compliance filing modifying the schedule and scope of PG&E’s 2024 Utility-Owned Generation compliance review. The ruling follows a finding that PG&E’s request for a six-month delay would push the case past the statutory 18-month deadline.
The ruling focuses on a narrow vintaging issue affecting a small subset of Community Choice Aggregator customers (those who opted out, opted back in, and then moved within a CCA territory) where PG&E reports that only 163 customers fall into this category and that just eight may have been incorrectly vintaged.
The ALJ:
- Denies PG&E’s extension request;
- Directs PG&E to file supplemental testimony by March 11 (with workpapers included at CalCCA's request, to which PG&E did not object);
- Reopens discovery on a limited and expedited basis through April 10; and
- Sets an accelerated briefing schedule aimed at final resolution by August, the statutory deadline.
The supplemental testimony must quantify the scope of any vintaging errors, propose customer remedies for 2024 billing impacts without reworking the entire Portfolio Allocation Balancing Account, and explain whether system programming changes are needed and how they would be funded.
INSTANT ANALYSIS: This ruling rejects PG&E’s request for a lengthy extension, making clear that a potential error affecting a handful of CCA customers does not justify pushing the case past the August 2026 deadline. The ruling treats the vintaging issue as a limited accounting correction rather than a basis to reopen PG&E’s broader PABA framework.
The ruling suggests that any misallocations should be resolved through customer-level remedies, not a recalculation of systemwide balances. This constrains both financial exposure and precedential spillover, while still giving CCAs a defined opportunity to examine PG&E’s vintaging logic and controls before the case moves to briefing and submission.
DEMAND RESPONSE
The electric investor-owned utilities (PG&E, SCE, and SDG&E) jointly filed a 2025 Verification Administrator’s Report detailing the annual audit of compliance with CPUC rules prohibiting the use of certain fossil-fueled distributed generation resources to produce Demand Response load reductions.
Conducted by Resource Innovations under Resolution E-4906 and subsequent decisions, the audit examined 206 randomly selected non-residential participants across multiple Demand Response programs, including RA-eligible resources.
The review combined attestation validation, cross-checks with IOU records and air quality permits, and (most notably for Scenario 2 customers) the installation and analysis of data loggers on prohibited resources during the 2025 event season.
The audit found a high overall compliance rate of 93%, with no instances where prohibited resources were used during Demand Response event hours and no evidence of fuel switching from renewable to non-renewable sources.
Identified issues were limited to administrative discrepancies, such as incorrect attestations or non-responses, with nine of 14 violations already cured and the remainder subject to cure windows through late January before escalation. The report concludes that the verification framework is functioning as intended (both reinforcing compliance through regular oversight and providing statistically reliable compliance estimates) while recommending clearer guidance for handling sites with multiple small, portable generators that rotate across locations.
INSTANT ANALYSIS: The 2025 DR Prohibited Resources audit shows the compliance regime is mostly working as designed. Across 206 audited accounts, there were no cases where fossil-fueled generators were used during DR event hours, even among Scenario 2 sites monitored with continuous data loggers. Issues identified were administrative rather than behavioral (misclassified attestations, minor nameplate discrepancies, or non-responses) most of which are already curing within the allowed window. The one soft spot remains Local Capacity Requirements, where compliance rates are behind other programs, but even there the shortfall reflects paperwork and responsiveness, not improper generator dispatch.
CLEAN ENERGY FUNDING
SDG&E filed Advice Letter 4796-E (available here) to comply with Resolution E-5254’s requirement for quarterly reporting on federal clean-energy funding activity under the Infrastructure Investment and Jobs Act, Inflation Reduction Act, and CHIPS Act.
The filing provides SDG&E’s fourth-quarter 2025 update, covering seven active or pending projects and noting routine administrative updates across multiple entries.
Most notably, SDG&E reports that the U.S. Department of Energy formally rescinded up to $1.2 billion in previously awarded funding for California’s ARCHES hydrogen hub in October 2025, issuing a termination directive instructing ARCHES to immediately cease all project activities. This was part of a broader federal review that terminated 223 clean-energy projects totaling $7.56 billion nationwide. Separately, DOE also cancelled SDGE-001, SDG&E's inverter-based resources grid protection demonstration project with Quanta/V&R Energy.
While ARCHES leadership has indicated an intent to continue pursuing hydrogen development through state and private avenues, SDG&E states it is awaiting further direction.
INSTANT ANALYSIS: This procedural filing confirms a significant reversal in federal clean-energy funding: DOE’s rescission of the ARCHES hydrogen hub award and issuance of a termination directive. That development highlights the fragility of large, federally sponsored hydrogen initiatives and introduces renewed uncertainty around California’s hydrogen roadmap.
For ratepayers, the immediate impact is muted (no cost recovery is triggered and no rates are affected) but the longer-term implication is that projects once assumed to be federally backstopped may now re-emerge in state proceedings seeking alternative funding or recovery mechanisms. The ARCHES outcome is an early warning that federal clean-energy grants should be treated as contingent rather than settled when evaluating future utility investment strategies and risk allocation.