Sign in Subscribe
9 min read Demand Response

WEDNESDAY AGGREGATE: Demand Response Bridge Funding; CalCCA on PCIA Reform; New PG&E Data Center in Gilroy

Today's aggregate looks at:

  • A ruling in the CPUC's Demand Response proceeding regarding "bridge year" funding for utilities' DR programs;
  • Ex parte communications in the ERRA/PCIA Reform docket between CalCCA and President Alice Reynolds' office;
  • PG&E, Stanpac, and Chevron's argument that the CPUC's Affiliate Transaction Rules do not apply to the sale of Stanpac gas transmission assets to PG&E;
  • PG&E's request for approval of agreements that provide transmission-level electric service for a data center project in Gilroy;
  • PG&E's ex parte communication on post-2018 wildfire mitigation spending being an emergency response exceeding GRC assumptions; and
  • SCE's annual status update on Transportation Electrification Grid Readiness projects.

Parties also filed comments in:

Senate Bill 1221 Implementation; Reining in RNG Costs
Commissioner Karen Douglas issued a third amended scoping memo in the CPUC’s Long-Term Gas Planning docket.
CALIFORNIA REGULATORY INTELLIGENCEMC

CRI is available to fully update your organization on these matters and other standalone projects – contact us if interested.

DEMAND RESPONSE

A new ruling in the CPUC's Demand Response docket seeks comments on an Energy Division staff proposal that would authorize interim “bridge year” funding for investor-owned utility DR programs.

  • The proposal recommends extending the utilities’ existing 2027 demand response portfolios for two additional years, covering 2028–2029, while the CPUC completes broader policy updates in the current rulemaking.
  • Energy Division staff argue that a bridge period is necessary because the current schedule would require PG&E, SCE, and SDG&E to file their next demand response applications before the rulemaking’s policy changes are finalized. The Commission employed the same bridge-year approach during the last DR rulemaking, authorizing interim funding in a 2014 decision (D.14-01-004).
  • Staff therefore recommend maintaining the utilities' approved 2027 program structures and budgets (excluding pilots, though the proposed budget table includes a separate pilots line item) during 2028–2029 while giving utilities additional time to incorporate new policy requirements, including the Societal Cost Test, into program design and cost-effectiveness reporting tools for the subsequent 2030–2034 application cycle.
  • The proposal recommends exempting the bridge-year portfolios from the Societal Cost Test requirement while funding the utilities' integration of the Societal Cost Test into their reporting tools ahead of the 2030–2034 cycle. Under the proposal, utilities would file the next full DR program applications by January 1, 2029.

The proposal also outlines preliminary annual bridge-year budget levels that mirror existing program categories such as supply-side demand response, auction mechanisms, enabling technologies, marketing, and portfolio support. Estimated annual totals would be $82.7 million for PG&E, $159.2 million for SCE, and $8.5 million for SDG&E, plus additional funding to implement SCT reporting capabilities.

Opening comments are due April 15, with replies due May 6.

INSTANT ANALYSIS: This is a timing fix. The CPUC's Demand Response rulemaking will not finish in time for the utilities' next program filings, so staff proposes extending the existing 2027 portfolios through 2028–2029. The result is a temporary hold on new program authorization while the Commission finishes rewriting DR policy and finalizes how the Societal Cost Test will apply to the next full program cycle starting in 2030. Utilities will presumably be designing their 2030–2034 programs during the bridge period, but no new program structures can be approved until this rulemaking concludes.

ERRA/PCIA REFORM

In a March 5 ex parte meeting in R.25-02-005, CalCCA presented its position to President Alice Reynolds' office regarding Track 2 of the PCIA reform proceeding. Recall that this track focuses on how pre-2019 banked Renewable Energy Credits should be valued within the PCIA framework.

CalCCA argued that customers who were originally on bundled IOU service and paid for these RECs through rates (but later departed to Community Choice Aggregators, termed "Later Departing Customers") currently receive no value when the investor-owned utilities later use those banked RECs for Renewables Portfolio Standard compliance. This is distinct from customers who were already unbundled at the time of REC generation, who received value through a PCIA credit at that time.

According to CalCCA, this outcome violates the statutory "indifference" principle underlying the PCIA by creating a cost shift from current bundled customers to later-departing customers, because only bundled customers receive the compliance value of RECs that all then-bundled customers helped fund.

To address this issue, CalCCA proposed that, when IOUs use pre-2019 banked RECs for compliance, the value of those credits should be reflected in the PCIA for the customers who originally paid for them. Its primary proposal would credit the PCIA at the current RPS Market Price Benchmark when the RECs are used, applied to the appropriate customer vintage year; an alternative approach would allocate the benefit by reducing the RPS procurement requirement for the load-serving entity serving those later-departing customers.

CalCCA maintains that either approach restores customer indifference and prevents cost shifting. The utilities have advanced five primary counterarguments:

  • Pre-2019 banked RECs were already valued in the year of generation and the accounting is closed;
  • The PCIA "collective rights" framework forecloses any claim by later-departing customers to REC value "left behind";
  • Valuation of pre-2019 banked RECs would impermissibly open up the pre-2019 PCIA methodology;
  • Pre-2019 banked RECs are categorically different from post-2018 RECs and cannot be valued at the current Market Price Benchmark; and
  • CPUC precedent precludes the valuation, which would also produce impermissible consequences.

CalCCA characterized these arguments as "clouds" over what it views as a straightforward valuation issue, arguing that none of them refute the core fact that bundled customers only receive value when the RECs are actually used, and later-departing customers should receive equivalent value to ensure indifference.

INSTANT ANALYSIS: This is a technical but consequential dispute over who captures the value of pre-2019 banked RECs. CalCCA argues that customers who paid for those RECs before departing utility service should receive value when the credits are later used for RPS compliance, likely through a PCIA credit tied to the RPS market price benchmark.

If adopted, the proposal would require that compliance value flow to CCA and departing-load vintages (a correction, in CalCCA's view, of what it characterizes as an unlawful cost shift under current practice), though the utilities contest both the legal basis and the practical implications of such a change.

The CPUC's eventual decision on this matter will shape the treatment of banked environmental attributes in PCIA accounting, with direct implications for CCA economics and future REC valuation.

NATURAL GAS TRANSMISSION ASSETS

PG&E, Standard Pacific Gas Line Incorporated (Stanpac), and Chevron Pipe Line Company filed an opening brief in A.25-12-014, arguing that the CPUC’s Affiliate Transaction Rules do not apply to their proposed transaction involving the sale of Stanpac gas transmission assets to PG&E.

The brief responds to a protest from Cal Advocates asserting that the transaction should be evaluated under the Affiliate Transaction Rules. PG&E, Stanpac, and Chevron contend the rules are not triggered because Stanpac is a regulated subsidiary whose revenues and expenses are already subject to CPUC ratemaking oversight, and therefore it is expressly excluded from the Affiliate Transaction Rules definition of an “affiliate.” They argue further that Chevron is not an affiliate of PG&E under the ownership or control thresholds used in the Affiliate Transaction Rules.

  • The transaction itself would transfer substantially all Stanpac pipeline and land assets to PG&E for approximately $150.4 million, with Stanpac then paying a dividend to its owners proportional to their ownership interests (PG&E 6/7, Chevron 1/7), resulting in an effective $21.5 million economic buyout of Chevron's one-seventh interest in the assets.
  • The transaction also establishes a long-term transportation arrangement under which Stanpac remains contractually obligated to provide gas service to Chevron's Richmond refinery but subcontracts actual performance to PG&E through an Inter-Utility Service Agreement, effectively making Stanpac a contractual pass-through entity operating on PG&E's system.

Under the proposed structure, Stanpac would remain in existence during a 20-year service term before PG&E ultimately acquires Chevron’s remaining Stanpac shares for $1.00 and seeks Commission approval to dissolve the entity. The parties maintain that the CPUC’s existing statutory review under the Public Utilities Code already provides the appropriate framework for evaluating the transaction and protecting ratepayers without applying the Affiliate Transaction Rules regime.

INSTANT ANALYSIS: This filing is a procedural move by PG&E and its partners to narrow the scope of this docket by keeping the transaction out of the CPUC’s Affiliate Transaction Rules framework. If the Commission agrees, the proceeding stays focused on the key statutory questions rather than expanding into a broader affiliate-conduct inquiry. The dispute reflects a familiar regulatory refrain: Cal Advocates attempting to widen scrutiny over a complex utility transaction, and the utilities pushing to confine the case to traditional public-interest and ratemaking review. The outcome will not determine whether the transaction proceeds, but it could affect how heavily the CPUC interrogates potential cross-subsidization and corporate-structure issues tied to PG&E’s consolidation of Stanpac pipeline assets serving Chevron’s Richmond refinery.

DATA CENTERS

PG&E submitted Advice Letter 7853-E requesting CPUC approval of several agreements to provide transmission-level electric service for a new data center project in Gilroy with a projected peak demand of 49.5 MW operating continuously.

To serve the load, PG&E proposes constructing a new 115-kV "Garlic Switching Station" connected via a dual circuit transmission line loop configuration to the Morgan Hill and Llagas substations, with the facilities expected to enter service by March 2027. The project includes multiple agreements covering interconnection facilities, special facilities, design review, and an engineering-procurement-construction arrangement under which the customer will build the switching station and transfer it to PG&E once completed and inspected.

PG&E also requests several exceptions to standard Electric Rules 2, 15, and 16 governing line extensions and special facilities. Instead of the usual estimated-cost framework, the agreements require the customer to pay PG&E's actual project costs with progress billing, while certain project elements are treated as refundable depending on future revenue generated by the load over a 15-year period.

The customer is not entitled to refunds on Special Facilities and will pay ongoing cost-of-ownership charges for those components. PG&E argues this structure protects existing ratepayers by ensuring the data-center developer bears the upfront infrastructure costs while allowing refunds only if the project ultimately produces sufficient electric revenues.

Protests are due March 26.

INSTANT ANALYSIS: This filing shows another data center load pushing into transmission territory in Silicon Valley’s southern corridor. A 49.5 MW facility now requires its own 115-kV switching station and dual transmission feeds. The key point is cost structure. PG&E is shifting construction risk to the customer through actual-cost billing and customer-funded infrastructure. That model is becoming the default template for large data-center interconnections in California.

WILDFIRE & GAS SAFETY

PG&E reported a March 2 ex parte meeting with advisors to Commissioner John Reynolds and President Alice Reynolds regarding its request to recover wildfire mitigation costs recorded in memorandum accounts in A.23-06-008. PG&E argued that 2020–2022 wildfire mitigation work was reasonable, necessary for public safety, and consistent with its approved Wildfire Mitigation Plan, citing audits supporting the costs’ incrementality.

PG&E also opposed intervenor proposals for permanent capital disallowances and asked the CPUC to allow recovery of its 2023–2030 capital revenue requirement through a compliance advice letter rather than a new application, arguing the streamlined process would save time and about $52 million in ratepayer interest.

INSTANT ANALYSIS: This ex parte shows PG&E reinforcing the overriding narrative of this proceeding: wildfire mitigation spending after the 2017–2018 fires was an emergency response that exceeded General Rate Case assumptions and should be fully recoverable. PG&E is also laying groundwork against TURN and Cal Advocates’ proposed capital disallowances, which would set a precedent for excluding portions of wildfire mitigation investment from rate base.

PG&E is also advocating for recovery of the 2023–2030 revenue requirement through a compliance advice letter rather than a new application. If the CPUC accepts that approach, the remaining cost-recovery phase becomes faster and more administrative, limiting additional litigation risk around the wildfire mitigation spending.

TRANSPORTATION ELECTRIFICATION

SCE submitted Advice Letter 5758-E (available here), providing its first annual status update on Transportation Electrification Grid Readiness (TEGR) projects required by the Commission’s decision in SCE’s 2025 General Rate Case.

The filing reports progress on distribution and subtransmission upgrades intended to prepare the grid for transportation electrification and other load growth, including substation capacity expansions, new circuits, and reconductoring projects across SCE’s service territory.

SCE explains that some TEGR projects have changed scope, been deferred, or migrated into its standard distribution and transmission planning process as updated load forecasts and engineering assessments emerged. The report also provides project-level information such as status, expected in-service dates, capital expenditures, and anticipated hosting capacity increases for infrastructure upgrades supporting future electrification demand.

SCE did not include project-specific energization request details or customer benefit types, stating that this information is "not readily accessible."

INSTANT ANALYSIS: This filing shows how transportation electrification is migrating from policy aspiration into routine grid planning. Many projects originally labeled as TEGR in SCE’s General Rate Case are now being absorbed into the utility’s normal distribution and subtransmission planning process as load forecasts evolve and specific interconnection needs emerge.

Published by:

MC

You might also like...