FRIDAY AGGREGATE: Direct Access Conflicts Reignite as California Load Growth Accelerates

Today's briefing:

• A new Direct Access battleground has emerged;
• The Sempra Utilities unveil a $348 million enterprise system migration;
• Winter gas bill shocks have become a cost-deferral exercise;
• The fee structure for Core Transport Agents is affirmed; and
• Fixed avoided-cost rates are proposed for small renewable generators.

DIRECT ACCESS

On May 6, parties filed responses to a petition for modification filed by the Alliance for Retail Energy Markets et al on April 6. The petition seeks to reverse a 2021 CPUC decision (D.21-06-033) and have the CPUC recommend the Legislature lift the statutory cap on non-residential Direct Access enrollment.

Recall that D.21-06-033 recommended that the Legislature not expand Direct Access any further. The decision reasoned that “expansion of Direct Access to all non-residential customers would present an unacceptable risk to the state’s long-term reliability goals.”

Utilities, Cal Advocates, and Community Choice Aggregators oppose the PFM but competitive suppliers and large energy users support it. Supporters argue that the CPUC's original reliability and greenhouse gas concerns no longer apply because Electric Service Providers are now subject to the same Resource Adequacy, Integrated Resource Planning, and Renewables Portfolio Standard obligations as other load-serving entities.

Opponents argue the petition is procedurally improper, unsupported by sufficient evidence, and risks reliability and cost-shifting if DA load migration accelerates.

• Cal Advocates argues a petition for modification is not the proper vehicle for reversing a major policy determination built on a lengthy evidentiary record. Cal Advocates warns that removing the DA cap could increase procurement uncertainty, complicate long-term resource financing, and shift costs onto remaining bundled customers if lower-cost customers migrate to DA providers.
• The three large investor-owned utilities take similar positions.
  • SDG&E argues the petition is untimely because the load-based procurement allocation methodology cited as the triggering "new fact" (D.26-02-057) is not new at all, tracing directly to D.21-06-035 (issued one day after the DA Decision) and D.19-11-016 (issued six months before it).
  • SCE similarly argues that the impacts of the 2021 decision were foreseeable at the time it was issued and says the petition fails to justify reopening the matter through a modification request rather than a new rulemaking with a full evidentiary record.
  • PG&E advances the strongest legal argument: that Assembly Bill 1373 repealed Section 365.1(f) of the Public Utilities Code in 2023, extinguishing the CPUC's statutory authority to issue a new DA recommendation to the Legislature. PG&E also argues the petition improperly seeks new factual determinations on issues (including cost-shifting) that the original decision expressly declined to reach. SCE independently raises the same AB 1373 point.
• CalCCA leads with the same jurisdictional argument, contending the CPUC has no further role in making DA recommendations to the Legislature now that Section 365.1(f) is inoperative, and that authority to modify the DA cap rests with the Legislature under current Section 365.1(a).
• CalCCA also disputes claims that ESPs are uniquely suited to serve emerging large loads such as data centers, noting that IOUs and CCAs already serve those customers and can structure dedicated contracts in the same way. CalCCA further argues that ESPs continue to lag behind utilities and CCAs in clean energy procurement and new resource development despite now operating under equivalent procurement frameworks.

Supporters framed the issue as a mismatch between modern procurement obligations and outdated enrollment limits.

• CLECA argues that California's load-growth outlook has shifted fundamentally since 2021 (driven by data centers, electrification, and EV charging) and that the DA cap now constrains industrial customer siting decisions, accelerates emissions leakage as energy-intensive businesses locate outside California, and imposes costs on existing DA customers for load they are legally barred from serving. CLECA cites EIA data showing California's industrial electricity rates have diverged dramatically from neighboring states since 2021, giving the affordability argument an evidentiary foundation the other supporters lacked.
• Commercial Energy of California and 3 Phases Renewables support lifting the cap on the same IRP-mismatch theory: ESPs now carry procurement obligations tied to anticipated load growth while remaining legally prohibited from serving most of that load. Both characterize this as an improper cost shift onto existing DA customers and argue the reliability and emissions concerns underlying the original decision are outdated given current regulatory oversight and compliance performance.

INSTANT ANALYSIS: The proceeding is evolving into a battleground over who gets to serve California's next wave of load growth and who pays for the procurement tied to it. The DA parties are reframing Direct Access from a legacy deregulation issue into a modern load-accommodation tool for data centers, electrification, and industrial expansion. Their main argument is simple: ESPs now carry the same procurement and reliability obligations as utilities and CCAs, yet remain legally constrained from serving much of the load driving those obligations.

The underlying concern of the opposing parties is migration risk. If the DA cap disappears during a period of accelerating load growth and rising bundled-service rates, large industrial and commercial customers could increasingly seek competitive supply arrangements, leaving utilities and CCAs with a more expensive residual customer base and more difficult procurement planning assumptions.

The developing flashpoint is significant: will California's future large-load growth remain utility-and-CCA anchored or become more contestable?

UTILITY OPERATIONS/ENTERPRISE SYSTEMS

SoCalGas and SDG&E filed a $348 million application seeking CPUC authorization to migrate their enterprise resource planning systems to SAP S/4HANA before SAP terminates support for the legacy platform at the end of 2027. The utilities frame the request as non-discretionary, characterizing Enterprise Resource Planning as the "central nervous system" of operations supporting more than 11,000 users, 57 million monthly transactions, and over 400 business processes spanning finance, procurement, inventory, and emergency response.

The proposal builds on $51.2 million already authorized in the Sempra Utilities' prior General Rate Case for Phase 1A, which migrates the core platform and is expected to complete by May 2027. Phase 1B adds O&M activities, including data migration and organizational change management. Phase 2 migrates connected systems, analytics platforms, and FERC reporting infrastructure. Total program cost reaches approximately $348.1 million through 2030. Peak residential bill impacts are estimated between 0.2% and 0.8%.

An accompanying motion requests immediate establishment of SAP Migration Memorandum Accounts to track approximately $13.7 million in Phase 1B O&M costs before a final Commission decision, which is not expected until mid-2027. The utilities request retroactive effectiveness to the May 1 application filing date.

Illustrative rate changes for SoCalGas customers are noted below.

Illustrative SDG&E electric rates are noted below, followed by illustrative SDG&E gas rates.

Protests are due June 4.

INSTANT ANALYSIS: This is a back-office reliability case built to survive a Commission that is nominally hostile to discretionary spending. The retreat from transformation to migration is deliberate, scoped to the minimum necessary to avoid operating an unpatched platform after January 1, 2028.

The memorandum account motion is revealing. The migration timeline has outrun the regulatory calendar and the utilities need retroactive ratemaking protection before Phase 1B spending begins. Authorization does not guarantee recovery; every dollar will face prudence and reasonableness review

NATURAL GAS PRICE SPIKES

PG&E filed an advice letter implementing D.26-02-058's mandate to cap monthly Core Procurement Charges for all five core customer classes: Residential; Residential NGV; Small Commercial; Large Commercial; and Natural Gas Vehicles, when winter gas prices exceed 150% of the 10-year average for the same month (November through March).

The cap operates by freezing the Weighted Average Cost of Gas component across all classes at the level that holds the Core Procurement Charge increase to that threshold. Any undercollection must be amortized into rates within nine months and cannot carry into the following winter season. The cap itself cannot exceed three months.

Two benchmark design rules prevent the 10-year average from drifting upward: prior spike-event months and prior undercollection amortizations are both excluded from the rolling calculation. Within one business day of identifying a qualifying event, PG&E will notify customers through its monthly Gas Core Procurement Rate Change advice letter.

Protests are due May 21.

INSTANT ANALYSIS: The CPUC has converted winter gas bill shock into a managed cost-deferral exercise. Extreme procurement costs no longer flow through to customers in real time during crisis months. They get redistributed across the following nine months instead.

The benchmark exclusions are the mechanism's critical design choice. Without them, repeated volatility events would ratchet the 10-year average upward and weaken the protection over successive winters.

The filing ultimately expands PG&E's administrative discretion. PG&E determines when a qualifying event has occurred, when the cap activates, and how deferred balances amortize. These are questions D.26-02-058 does not resolve and this advice letter does not address.

The more macro takeaway: California's gas system remains acutely exposed to winter commodity volatility, electrification trajectory notwithstanding. A formal emergency Core Procurement Charge cap is institutional acknowledgment that severe winter price dislocation is a recurring credible risk, not a resolved one.

CORE TRANSPORT AGENTS

A proposed CPUC resolution (Draft Resolution G-3621) reaffirms the annual fee structure for California Core Transport Agents, the non-utility gas suppliers serving residential and small commercial customers. The draft resolution retains the framework from a previous resolution (Resolution G-3597, 2023) without introducing new fee design. Each registered CTA pays a $5,000 base fee, with variable fees assessed only against companies that generated complaints or faced unauthorized enrollment investigations and enforcement activity in 2025.

The CPUC grounds the structure in Senate Bill 656 and a 2018 decision (D. 18-02-002), which expanded CTA oversight after years of deregulated gas procurement. With 39 registered CTAs and 36 active participants, the CPUC argues the market is mature enough that higher fees pose no meaningful barrier to entry.

Fixed administrative costs rose 34% in 2025 but remain within the tolerance band established in G-3597, so the base fee remains at $5,000. The more notable development is complaint volume, which surged 75% over the prior year. Unauthorized enrollment complaints reviewed by the CPUC's Utility Enforcement Branch rose nearly as much, even as formal enforcement actions fell by more than half.

The complaint surge produces wide fee dispersion. Wave Energy faces the largest total assessment at approximately $206,000. SFE Energy exceeds $118,000. BP Energy, Shell, and Calpine each pay only the $5,000 base fee, having generated no complaints or enforcement activity. The earliest the CPUC will consider this matter is June 11.

INSTANT ANALYSIS: This draft resolution further embeds complaint-driven cost allocation as the basis of California's retail gas oversight regime. CTAs with persistent enrollment and marketing problems are funding a growing share of CPUC enforcement infrastructure, while operators with clean complaint records pay only the administrative floor. The draft resolution does not propose market reforms or stricter registration standards, but the staffing expansion suggests that the CPUC expects elevated oversight demands to persist.

ReMAT PRICE UPDATE

The CPUC issued a draft resolution updating fixed avoided-cost rates for California's Renewable Market Adjusting Tariff, a feed-in tariff for small renewable generators at (or below) 3 MW. PG&E, SCE, and SDG&E would have 30 days from the effective date to amend their tariffs.

The 2026 rates reflect a weighted average of Renewable Portfolio Standard contracts executed 2020–2025 for projects 20 MW or smaller:

The 43-contract pricing dataset is heavily weighted toward CCA-procured solar PV in Los Angeles County, including a substantial Prologis rooftop portfolio. The baseload category draws almost entirely on Nevada geothermal. A confidential geothermal contract executed in 2025 is the only new baseload entry (the most plausible driver of the $16.37 increase, though the draft resolution does not say so explicitly). As of February 2026, the program totals 65 contracts and approximately 112 MW since inception.

INSTANT ANALYSIS: The baseload rate eclipsing $92/MWh confirms that firm renewable capacity (geothermal above all) commands a widening premium over intermittent resources in California's small-scale procurement market. The near-flat peaking price tells the opposite story: CCA solar has saturated that category to the point where new contracts move the weighted average almost nothing. CCAs now dominate the RPS contract dataset that sets these rates. The avoided-cost benchmark for small QFs is increasingly a CCA-derived number, not a utility one (a shift with long-term implications for how ReMAT prices reflect actual utility procurement costs).