CalReg CPUC Docket Monitor

This PD is the CPUC’s first attempt to convert SB 1221 from gas-transition policy into a working project pipeline, and it is structured to make conversion difficult by design. Slot allocation is primarily between PG&E and SoCalGas/SDG&E by 2024 gas demand (7 each per round for the first two rounds), with one slot reserved for Southwest Gas and one for smaller CPUC-regulated gas corporations. Application deadlines are December 15, 2026; December 15, 2027; and July 1, 2028 if slots remain. (The PD summary states June 1, 2028, conflicting with the ordering paragraph; the discrepancy should be resolved before adoption.)

Each application must demonstrate via net-present-value analysis (using the applicant’s WACC as the discount rate) that avoided gas infrastructure costs exceed the zero-emission alternative cost. Four cost-effectiveness tests are required, varying inclusion of non-ratepayer funding and administrative costs; the governing test excludes both. Applications must also document electric infrastructure upgrades, outreach, GHG emissions forecasts using the Avoided Cost Calculator, and cost-recovery proposals. Crucially, the PD imposes a 67% non-binding expression-of-interest threshold before filing and a 67% binding notarized consent threshold after Commission approval but before any building remediation, appliance removal, or implementation spending. Behind-the-meter costs must be expensed rather than capitalized, meaning utilities cannot earn their authorized rate of return on BTM investments and may propose amortization periods of up to 10 years. The application process (rather than the lower-touch advice-letter process) keeps every pilot subject to full Commission and intervenor scrutiny, which is where cost allocation, bill-impact assumptions, and electric-grid attribution will be contested. Data collection, reporting, evaluation, and shareholder incentive mechanics are all deferred to Track 4. For ratepayer advocates, the key wins in this PD are (a) governing-test exclusion of admin/outreach costs, (b) BTM expensing, and (c) the application process itself. The principal risk is that the high-touch consent and outreach burden filters out exactly the kinds of dense, working-class, multi-family neighborhoods where pilots would most efficiently displace gas spending.

D.26-04-034 is the decision that effectively ended SoCalGas’s near-term path to ratepayer-funded Angeles Link development. The Commission’s denial of the Phase 2A request ($266M for continued pre-development) signaled that ratepayers should not bear ongoing development costs absent stronger evidence of project viability and customer benefit. The May 29 ALJ ruling in the Phase 1 cost-recovery proceeding now asks parties (1) whether it is just and reasonable for ratepayers, or a subset of ratepayers, to bear Phase 1 costs and if so when recovery should occur; (2) whether the CPUC must reach jurisdiction over Angeles Link or can dispose of the proceeding on cost-recovery grounds alone; and (3) the remaining schedule including whether evidentiary hearings are necessary. From a ratepayer protection perspective, the favorable framing is that the Phase 2A denial creates a strong precedent for refusing socialization of Phase 1 sunk costs as well, since the Commission’s rationale (insufficient evidence of project viability) applies equally to retroactive recovery of money already spent. The most defensible outcome is shareholder absorption of all Phase 1 costs, with any cost recovery limited strictly to identifiable subsets of customers who would benefit from a hypothetical built project — a class that may not exist on the current record.

Public Utilities Code §851 acquisitions are typically reviewed for (a) consistency with public interest, (b) absence of harm to ratepayers, and (c) reasonable terms. The scoping memo identifies what issues will be litigated and on what schedule. From a ratepayer protection perspective, two questions warrant scrutiny. First, the price paid for Chevron’s 1/7 stake and the 20-year stock purchase: if the purchase price reflects pre-2022 valuations or excludes the discounting that should apply to long-life gas-transmission assets during the gas-transition era, ratepayers will bear an inflated rate-base addition for decades. Second, the transportation agreements preserving Chevron’s system access: if Chevron receives below-cost transportation as part of the deal, the difference is a cross-subsidy from PG&E ratepayers to Chevron. A §851 challenge or conditioned approval is most effective at the scoping-memo stage, when the issues for hearing are set. Given the long-life nature of the asset and California’s 2045 gas-transition deadlines, an asset useful life shorter than the standard depreciation schedule should also be requested.

The reopened EITE exemption question is the structural issue. EITE customers (cement, steel, food processing, refineries) argue they will relocate production out of California if forced to bear RGS above-market costs, citing emissions-leakage risk. The principle is sound but the implementation matters: a poorly designed exemption shifts those costs to core residential and small commercial customers via rebalancing. The CPUC’s prior position was reluctance to extend new exemptions absent demonstrated leakage risk. Now D.26-04-044 has reshaped the RGS in ways that may alter the cost incidence, and the ALJ is asking parties to revisit their positions. Most defensible ratepayer position: any EITE exemption must (a) be capped at a defined percentage of RGS volume; (b) be conditioned on demonstrable trade-exposure metrics from CARB’s existing cap-and-trade leakage framework, not ad hoc industry self-certification; and (c) include sunset provisions tied to the RGS itself. Without these guardrails, EITE exemptions become a permanent cross-subsidy from residential to industrial customers.

PG&E sought to exclude debt and equity impacts tied to (a) the 2019 Kincade Fire, (b) the 2021 Dixie Fire, and (c) a $1.4 billion forgivable DWR loan tied to the Diablo Canyon extension. The PD rejects PG&E’s request on three separate grounds: the wildfire costs amount to only 0.6% of equity, well below the rule’s 1% adverse-financial-event threshold; the PD refuses to aggregate the Kincade and Dixie events (unrelated incidents years apart) to manufacture a qualifying reduction; and the DWR loan fails independently because a forgivable loan is not an adverse financial event. PG&E’s 2020 waiver covered $8.9 billion in wildfire costs — an order of magnitude larger — and SCE’s approved request would have represented approximately 10% of equity. Neither offers persuasive precedent here.

The most consequential implication sits in the affordability section. The ALJ declines to accept PG&E’s carrying-cost argument at face value and instead credits the ratepayer-protection critique: that operating with debt excluded from capital structure calculations allows PG&E to compensate shareholders based on an inflated authorized equity ratio while ratepayers absorb the leverage risk. The intervenor record shows PG&E’s actual equity has run 7 to 10 percentage points below its authorized 52% since 2021, producing an estimated $2.4 billion in shareholder profits from ratepayers. That theory is now on record and likely travels into Cost of Capital proceedings, wildfire financing debates, and affordability dockets. Comments due June 10. Earliest CPUC consideration: July 2, 2026.

RAMP filings are required under D.18-12-014 and are the foundational input to a utility’s forward GRC capital plan. SCE’s 2026 RAMP frames the risk-spend efficiency and capital prioritization for SCE’s TY 2029 GRC. The proceeding sits in parallel with the new Risk-Based Decision-Making OIR (R.26-04-016) opened at the April 30 voting meeting.

The 10 RAMP risks: (1) Wildfire and Public Safety Power Shutoffs; (2) Overhead Equipment Failure; (3) Underground Equipment Failure; (4) Seismic; (5) Public Safety Risk Not Attributable to Asset Failure; (6) Major Physical Security Incident; (7) Cyber Attack; (8) Hydro Dam Safety; (9) Employee Safety; (10) Contractor Safety. The January 2025 Southern California fires dominate SCE’s case for planning around tail-risk events beyond historical experience. SCE developed an enhanced Wildfire Integrated Model and a climate-informed variant using data underlying the forthcoming California Fifth Climate Change Assessment, which has not yet been released.

BCR screen as the contested design choice. Grid hardening runs through a Benefit-Cost Ratio screen at the circuit level. SCE selects either covered conductor or targeted undergrounding based on whichever yields the higher BCR, provided at least one exceeds 1.0. Where neither clears that threshold, no proactive hardening is proposed; vegetation management, inspections, and PSPS continue, but no grid investment moves forward. SCE characterizes the BCR as one input among feasibility, operational, and execution constraints. Intervenors are likely to argue that communities on sub-1.0 circuits are being left without physical protection because of a cost screen, not because the risk is low — a challenge that could force SCE to revisit its 2029 hardening scope before GRC filing.

REFCLs. Rapid Earth Fault Current Limiters — substation-based protection devices that suppress ground-fault current when an energized conductor contacts the ground — are prioritized separately at circuits where covered conductor hardening is already prevalent. Covered conductor raises wind-speed thresholds but does not remove shutoff risk above those thresholds.

Forward-looking risk modeling. By incorporating climate projections rather than historical fire data into the risk calculations that drive mitigation prioritization, SCE creates a methodology that has not yet been evaluated by CPUC safety staff. A successful challenge to the underlying assumptions would not just affect the climate modeling — it would shift the risk scores, and with them the hardening investments SCE plans to ask ratepayers to fund in 2029.

Beneath the near-flat system average sits a major redistribution of cost drivers. The largest upward driver is a $380.7M distribution revenue increase tied to SCE’s wildfire self-insurance program. After SCE entered into 2025 wildfire settlement agreements expected to exceed $1 billion, it triggered an adjustment mechanism that raises its 2026 self-insurance revenue requirement from $274M to $650M — an increase of $376M before Franchise Fees and Uncollectibles. SCE will amortize the increase over 12 months to moderate rate impacts.

Offsets: $84.5M reduction in Transmission Access Charge Balancing Account recovery (overcollection); $73.4M credit from the 2023 ERRA review; $240.3M reduction in energy efficiency funding requirements; expiration of $34.7M in Thomas Fire Catastrophic Event Memorandum Account recovery rolling off rates after May 31. Smaller items: $15.4M increase for the Electric Program Investment Charge RD&D and renewables program, $6.8M for the 2026 Flex Alert paid media campaign, and $3.6M annually for SCE’s tariff on-bill financing pilot for residential clean-energy upgrades.

Takeaway. For large customers tracking distribution cost growth and wildfire exposure, the filing is another reminder that California utility rates remain under steady upward pressure even when bill impacts appear benign. The TACBAA reduction shows how balancing-account timing can temporarily absorb rate pressure without altering the broader cost trajectory.

The 2024 ERRA compliance proceeding reviewed PG&E’s utility-owned generation operations, fuel procurement, Resource Adequacy accounting, portfolio balancing entries, and contract administration. Both Cal Advocates and CalCCA initially protested portions of PG&E’s application; both now support approval subject to settlement terms.

Four substantive disputes resolved:
1. Humboldt Bay Unit 3 exhaust valve failure — Cal Advocates withdrew its demand for an outside metallurgical review after PG&E confirmed the failed valve had been recycled. In its place, PG&E agreed to hire an outside consultant for root-cause analysis if a repeat exhaust valve failure causes another forced outage.
2. Balancing account scope — PG&E agreed to include four accounts in future ERRA compliance reviews: New System Generation Balancing Account, Modified Transition Cost Balancing Account, Tree Mortality Non-Bypassable Charge Balancing Account, and BioMat Non-Bypassable Charge Balancing Account.
3. Resource Adequacy — CalCCA accepts that PG&E reasonably calculated retained RA using final derated capacity values for monthly compliance filings; no revision to 2024 accounting needed.
4. PCIA customer vintaging — CalCCA accepts PG&E’s supplemental testimony on customers who opt out of CCA service, opt back in, and relocate within the same CCA territory. Of 156 customers meeting those criteria, PG&E identified one improperly vintaged customer; attributed to human error rather than a system logic defect.

Takeaway. After more than a year of testimony, supplemental testimony, and reopened discovery, Cal Advocates and CalCCA arrive at procedural refinements rather than financial consequences. The most substantive forward-looking change is the expansion of ERRA compliance review scope to four additional balancing accounts. For PG&E this is a favorable compliance outcome.

PG&E’s position. Type 4 Transmission Network Upgrade costs should continue flowing through the Transmission Access Charge rather than being assigned upfront to individual customers. PG&E argues that the Resolution E-5420 75% revenue refund approach is proven, supported, and low-risk; that requiring upfront Type 4 financing would drive load to publicly owned utility territory or out of California entirely, leaving existing ratepayers holding upgrade costs with none of the rate-reduction benefit. PG&E illustrated the point with a Silicon Valley Power example: a CAISO-approved 230 kV line estimated at $593M–$858M, whose costs would flow through TAC regardless of whether the associated load lands in PG&E territory. PG&E also told commissioners that no customer has yet used interim Rule 30 implementation.

Ratepayer advocates including Cal Advocates, Sierra Club, and NRDC argue Rule 30 as proposed exposes existing ratepayers to unacceptable cost-shift risk from speculative hyperscale load. All call for upfront financing requirements, direct cost-assignment mechanisms, or refundable load-development fees grounded in cost causation. A refundable $667/kW interim load-development fee for loads ≥25 MW has been advanced by consumer advocacy parties; Cal Advocates proposes the same figure as one of several interim options alongside a flat $50M fee, with primary emphasis on a Revenue Cap methodology. Both treat Resolution E-5420 as a fallback. Sierra Club and NRDC reject PG&E’s FERC preemption argument, citing the CPUC’s own filing in FERC Docket RM26-4-000 that affirmatively argues large-load interconnection cost allocation remains a matter of state jurisdiction.

CLECA does not oppose Rule 30 but argues PG&E is misapplying data-center-driven risk provisions to decarbonizing and EITE customers that do not present comparable stranded-load risks. CLECA urges the CPUC to allow such customers Rule 30 access or continued exceptional-case procedures without the heightened minimum demand charges, extended contract terms, and early termination obligations built for speculative hyperscale load.

CalCCA’s reply takes no position on cost allocation, jurisdiction, or stranded-cost protection. Its one remaining dispute is PG&E’s proposed privacy and cybersecurity review requirements for CCAs receiving Rule 30 customer data.

Stakes. The identical ex parte deck delivered to all five commissioner offices two days before reply briefs shows where PG&E sees its exposure. PG&E is pushing Resolution E-5420 as the endpoint; ratepayer advocates and Cal Advocates treat that resolution as a floor; Sierra Club and NRDC want something more direct. The bigger question is whether the CPUC’s final decision separates hyperscale data-center load from policy-aligned industrial load growth.

Headline numbers. System-wide needs peak in March at 30,378 MW and bottom in December at 25,060 MW. CAISO retains its three-category framework: base flexibility at 27% of total need in non-summer months and 42% in summer; peak at 68% and 53% respectively; super-peak fixed at 5% year-round. For CPUC-jurisdictional LSEs, monthly obligations run from 23,824 MW (Dec) to 29,064 MW (Mar).

The sunset problem. Solar drives the maximum three-hour net-load ramp in every month of 2027. August solar contribution reaches 84.18%. CAISO states this plainly and anticipates continued solar dominance as utility-scale and behind-the-meter penetration grows.

Unresolved battery EFC methodology. The filing’s open question. CAISO states that battery charging in Effective Flexible Capacity accreditation "may be over-credited" in most months outside spring, because batteries transition from charging to discharging during the same ramp window flexible capacity is designed to address. CAISO identifies the problem and defers it, citing unresolved Local Regulatory Authority battery-mapping data.

Takeaway. CAISO’s acknowledgment of potential battery over-crediting creates a procedural record. Questions remain whether the CPUC addresses it in the RA docket, whether parties press for methodology revisions in the 2028 cycle, or whether CAISO’s ongoing Flex RA working group moves first. The mapping-data rationale buys one cycle. As solar dominance of the three-hour ramp deepens, procurement pressure continues shifting toward resources capable of responding during compressed evening windows.

ERRA is the annual reconciliation of forecast vs. actual energy procurement costs for bundled customers. PG&E’s 2027 forecast reflects exposure to wholesale energy markets, GHG allowance prices, and Resource Adequacy procurement obligations. The +5.7% bundled-rate projection follows multi-year affordability pressure on residential bills.

SDG&E’s parallel A.26-05-009 2027 ERRA Forecast seeks approval of an $893 million procurement-related revenue requirement, a 1.5% increase from currently effective levels, with new rates effective January 1, 2027. Inside the SDG&E filing: the ERRA revenue requirement falls 3.3% to $379.3M with a projected $45M overcollection, but the Portfolio Allocation Balancing Account rises 71% to $301.4M, partially offset by a prior-year balance reduction. Bundled customers see an approximate 1.2% rate decline aided by California Climate Credit returns; a typical 400 kWh residential customer sees no bill movement. Unbundled customers face a 1.4% increase in delivery-plus-PCIA charges. SDG&E forecasts $181.4M in GHG allowance revenues, with $137.8M returned via California Climate Credits and $2.8M to EITE customers. The filing also picks up the new Transmission Accelerator Revolving Fund obligation: 5% of qualifying GHG auction revenues remitted to the state beginning July 1, 2026. SCE’s A.26-05-006 shows procurement costs falling versus 2026, yet bundled customer bills are projected to edge higher due to fixed-cost amortization.

PTC applications under GO 131-D authorize construction of transmission facilities below the CPCN threshold (200 kV) but require Commission review of need, alternatives, and environmental impact. The Suncrest Loop-In supports east-San Diego County reliability and integration of large-scale solar and battery generation in the Boulevard and Jacumba corridors. Environmental review will run in parallel with the application; CEQA timing typically drives the schedule.

SDG&E’s Tier 3 advice letter (AL 4736-E) seeks Commission approval to acquire the Westside Canal 2A storage facility via a Membership Interest Purchase Agreement with RWE Clean Energy. Total transaction value is approximately $267.9 million. The 119 MW / 4-hour battery is intended for summer reliability and integration into SDG&E’s Resource Adequacy portfolio. The companion 10-year LTSA covers operations and maintenance for the asset life.

Why the data failed. D.24-09-020 established enforceable average and maximum energization targets, an eight-step framework, and a twice-yearly reporting obligation covering tariff projects under Rules 15, 16, 29, and 45, plus main panel upgrades. The September 2025 reports cover projects with complete applications from January 31, 2023 through June 30, 2025 — a window that straddles the decision’s September 2024 issuance date, mixing pre- and post-decision projects throughout.

Each utility’s tracking systems failed in a distinct way:
PG&E is still integrating systems and cannot reliably track Step 6 (IOU Site Readiness) or Step 8 (Energization); only 6.3% and 47% of completed tariff projects, respectively, have start or end dates for those steps. PG&E did produce the most complete dataset overall, including a methodology for allocating overlapping utility and customer time and outlier flags on individual project records.
SCE provided complete step-date data across all eight steps (the only utility to do so) but its systems cannot separate IOU-controlled time from customer or third-party time — which means SCE cannot compare its reported timelines to the CPUC’s utility-controlled targets at all.
SDG&E struggled with multiple steps, could not track utility-controlled time separately from customer time, and cannot provide reliable end-to-end cycle data. SDG&E cited funding constraints as a barrier to system improvements, noting that many required initiatives were not included in its most recent GRC.

Guidehouse’s sufficiency thresholds: 95% availability for compliance data points (tariff type, IOU-controlled steps, aggregate IOU-controlled and end-to-end timelines); 75% for contextual data points (capacity, costs, upstream triggers, delay causes). None of the three utilities met those thresholds. Approximately one-third of required data fields were missing for more than 75% of projects across all three IOUs. Cost data at the time of energization is unreconciled for 6–12 months after project completion; outlier treatment was inconsistent; and none of the utilities could reliably identify when a tariff project triggered an upstream capacity upgrade.

What the ruling is building toward. The ruling’s questions ask utilities and parties to address: how IOU systems will be upgraded and when; how overlapping IOU and customer time should be allocated; how step start and end dates should be defined where no clear energization or meter-set date exists; how upstream capacity triggers should be tracked; how cost reconciliation should be standardized; what data fields the annual Section 935 staffing reports should contain (including job classifications, staffing levels, apprentice pipeline information); how staffing levels should demonstrate a relationship to energization timeline performance; and whether the proposed data sufficiency thresholds, outlier definitions, and data template modifications should be adopted.

Instant analysis. The ruling means the CPUC cannot yet say whether PG&E, SCE, or SDG&E are meeting the energization targets adopted in D.24-09-020. Guidehouse’s review is also a roadmap for making the next reporting cycles enforceable. The risk for the utilities is that bad data may become its own regulatory problem: the attached questions ask whether utilities that fail Guidehouse’s proposed sufficiency thresholds should be required to file additional reporting on their energization backlogs. Whichever parties shape the definitions of utility-controlled time, customer delay, upstream capacity triggers, actual project costs, and outliers will shape how future energization performance is judged.

R.26-04-009 is the CPUC's successor rulemaking to R.22-07-005, which established the current advanced residential rate framework including default time-of-use rates and income-graduated fixed charges. The new OIR expands scope to non-residential customers and addresses rate design for high-electrification scenarios -- how rates should be structured as buildings and transportation shift to electricity. ALJ Joanna Perez-Green and Commissioner John Reynolds were assigned April 22, signaling Commission prioritization. The proceeding will shape how millions of California ratepayers are billed for electricity as the grid transitions and fixed-cost recovery shifts away from volumetric charges.

R.24-01-018 is the CPUC's rulemaking on energization timelines — the time it takes utilities to connect new customers, rooftop solar, and battery storage systems to the grid. Data shows PG&E and SCE meet Rule 21 interconnection timelines as little as 18% of the time, prompting the JLAC to authorize a state audit (JLAC 2026-126) and the CPUC to develop formal enforcement mechanisms.
This April 17 ALJ ruling by ALJ Dugowson sets out the procedural schedule and framework for how the Commission will enforce compliance going forward, including potential penalty mechanisms. The ruling is significant because it marks the CPUC's first formal procedural step toward creating binding enforcement tools for energization delays — a longstanding pain point for solar installers, EV charging developers, and customers awaiting new service connections.

Angeles Link is SoCalGas's proposed 36-inch hydrogen transmission pipeline spanning roughly 215 miles across Los Angeles County. The Phase 2 cost estimate ballooned from $92 million (2022) to $266 million (2024) -- a 189% increase before a single pipe was laid. SoCalGas applied to recover this cost from ratepayers under A.24-12-011. The CPUC rejected the request, holding that SoCalGas had not demonstrated specific, quantified ratepayer benefits sufficient to justify ratepayer funding. The decision effectively forces SoCalGas either to abandon Phase 2 or fund it with shareholder capital. Environmental and consumer groups including Sierra Club and EDF supported the denial, arguing the project would lock ratepayers into a hydrogen infrastructure bet that may not materialize as green hydrogen costs remain far above natural gas.

R.13-02-008 is the CPUC's Renewable Gas Standard rulemaking, which sets mandatory procurement targets for biomethane (renewable natural gas from organic waste) that gas utilities must meet. The April 30 decision reflects a significant policy retreat: the 2030 annual procurement target was halved from 72.8 to 36.4 billion cubic feet, and both the Diverted Organic Waste and overall targets were extended from 2030 to 2035. A new Cost Containment Mechanism limits ratepayer exposure to above-market biomethane prices. All feedstocks remain eligible to bid into future utility solicitations, and all procurement contracts must go through Tier 3 Advice Letters regardless of price. Gas utilities must also submit revised Renewable Gas Procurement Plans. The decision reflects growing CPUC caution about the cost trajectory of renewable gas mandates as biomethane prices remain high relative to conventional gas.

The California Climate Credit is a twice-yearly credit on utility bills funded by cap-and-trade auction revenue, providing meaningful bill relief for residential customers. For 2026, the April credit for PG&E residential electric customers was paused and redistributed to August and September -- when air conditioning demand drives bills to annual highs. For smaller utilities (Bear Valley, Liberty, Pacific Power), the credit shifts to April and November for 2026, then October and November in future years. The total annual credit per household remains the same; only the delivery timing changes. The policy rationale is straightforward: delivering bill relief when bills are highest has greater affordability impact than spreading it to lower-use spring months. The decision applies to the electric Climate Credit; gas credits follow a separate schedule.

GRC Phase 2 proceedings set rate design -- the allocation of revenue requirement authorized in Phase 1 across SCE's various customer rate schedules (residential, commercial, industrial, agricultural, EV, etc.). The April 30 decision adopts the negotiated rate design settlements, locking in how SCE will recover its authorized revenue from different customer groups through at least the next general rate case cycle. Rate design outcomes directly affect the distribution of costs between high- and low-usage customers, the structure of tiered vs. flat rates, and the incentive signals embedded in time-of-use and demand charge schedules. The decision follows separate Phase 1 revenue requirement proceedings already concluded.

The California DGStats platform (californiadgstats.ca.gov) aggregates interconnection data from all California IOUs and publishes monthly reports on distributed energy resource deployments -- rooftop solar capacity, battery storage installations, EV chargers, and interconnection queue status by utility and zip code. It is the authoritative public data source used by CPUC staff, researchers, local governments, and industry to track California's DER buildout.
Resolution E-5436 increases the contract budget from approximately $875,000 to $2.6 million per 3-year cycle -- roughly tripling current funding -- and authorizes the Energy Division to adjust annually for inflation. The funding increase reflects the platform's growing role as the backbone for CPUC interconnection planning, enforcement, and ICA (Integration Capacity Analysis) compliance tracking. All three large electric IOUs (PG&E, SCE, SDG&E) contribute data to the platform and fund it through their rates.