CalReg CPUC Docket Monitor

D.25-08-032 closed Phases IV and V of the post-2018 Safety Policy Division OIR, replaced the RMAR with a consolidated set of adopted requirements, and made the operative test for RAMP Four Optimized Enterprise Portfolios at 85, 90, 95, and 100 percent of the Baseline Cost Forecast, constructed using a prescribed binary or mixed-integer optimization (objective = risk reduction; constraint = budget in dollars; decision variable = include mitigation y/n).

Threshold compliance concerns under review include: (1) whether the optimization is a true constrained binary program or a greedy BCR-sort heuristic with cumulative-spend column; (2) whether the Baseline Cost Forecast is drawn from the current RAMP/GRC rather than the prior GRC (Conclusion of Law 12); (3) whether mutually exclusive mitigations (CC, VM, CC+VM) are bounded against additive alternatives (Row 25.2); (4) whether Overall Residual Risk shows a longitudinal trajectory across the 2018, 2021, and 2026 cycles (Modified Row 9); (5) whether RRU datasets ranked by BCR have cell-level formulas linked to a permanently accessible source sheet (Modified Row 26; D.24-05-064 auditability standard); (6) whether 2026-2028 tranche-level spending is disclosed at all chapters (not just 2029-2032); (7) whether the WIM-Climate disclosure documents GCM ensemble, SSP pathway, and downscaling method at the circuit-segment level. Reply window opens after the Jun 29 protests close.

A $33 million state appropriation reverted to the General Fund in June 2025; the EPA terminated California's Solar for All award in August 2025, leaving the program structurally without third-party funding. The decision proceeds anyway by tying the new Community Renewable Energy tariff to ReMAT, rejecting proposals for capacity adders, expanded project sizes, time-of-delivery adjustments, and above-avoided-cost compensation as inconsistent with the Public Utilities Code. President Reynolds framed the structure as ratepayer-protective: ReMAT permits 20-year contracts vs. 12 years under the PURPA standard offer. Commissioner Houck dissented, arguing that ReMAT-based compensation is unlikely to make community-solar projects financeable absent external funding or legislative action. The decision also consolidates Green Tariff oversight into procurement review and ERRA cost proceedings, eliminates annual forums and advisory boards, moves stranded Green Tariff costs into ERRA, and reduces the advice-letter tier required for new CCA DAC-GT programs from Tier 3 to Tier 2. If no developer executes a ReMAT PPA within two years of the Tier 2 disposal date, the structure quietly sunsets.

Cal Advocates says the External Outage Report identifies no Emergency Flow Orders over the past decade and only one curtailment affecting noncore electric-generation customers; SoCalGas managed every listed external weather event without gas-customer impacts while Aliso operated at or below its current maximum allowable reservoir pressure. On the internal side, Cal Advocates says SoCalGas describes pipeline incidents, curtailments in the San Joaquin Valley, North Coastal System, and San Diego County, and other constraints, but never claims or shows that additional Aliso inventory was necessary to address them, or that the preferred 86.2 Bcf level would have prevented them. Sierra Club echoes the framing. The proceeding is the latest round in CPUC consideration of Aliso Canyon under the 2025 Biennial Assessment; the dispute will set up next-year capacity decisions and will inform whether the Commission reverses or expands prior inventory caps.

Once the embedded-cost framework is agreed, the dispute shifts to allocators, where the intervenors fracture. Indicated Shippers' witness Brian Collins argues peak-day demand sizes the system; TURN's witness Mike Florio argues that with load declining and spending now safety- and reliability-driven, annual throughput is the true cost driver — a package that shifts roughly $67 million onto retail noncore customers. Clean Energy opposes Florio's throughput allocator, citing an approximate $17 million (30%) hit to the natural-gas-vehicle class tied to transit agencies facing about $1.3 billion in budget cuts. Two issues unite intervenors against the utilities: the backbone-to-local-transmission reallocation (~$116.4 million) and the FASRMA storage-account treatment, where the factual record is lopsided enough that the applicants are likely to lose. For a gas-only utility with a contracting customer base, locking in cost-based allocation now is the strategic objective.

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.

The Notice frames the federal buyout structure as ultra vires under OCSLA on three grounds: the leases were competitively awarded under a federal statute that requires development; the cash buyout plus mandated out-of-state fossil reinvestment is itself a substantive policy reversal not authorized by the statute; and the cumulative effect across eight lease areas ($2.6 billion) materially impairs California's ability to meet the 25 GW by 2045 offshore wind target adopted under AB 525. Golden State Wind's 2 GW Morro Bay lease (OCS-P 0564) and Invenergy's adjacent 1.5 GW lease (OCS-P 0565) are the two largest single buyouts. If the suit succeeds, the federal Interior Department would be enjoined from finalizing the buyout structure pending judicial review; if it fails, the practical effect is that the California port and transmission investments already underway (Humboldt Bay, Long Beach, Port of San Luis) absorb the stranded-asset risk while the offshore generation pipeline collapses. The case will be watched as a test of state standing to challenge federal lease modifications affecting state energy planning.

The "roughly commensurate benefits" doctrine was articulated in Illinois Commerce Commission v. FERC (7th Cir. 2009) and codified in Order 1000: transmission cost allocation must trace cost causation to beneficiaries with reasonable proportionality. The Maryland OPC argues that PJM's regional Order-1000 allocation lumps Maryland ratepayers into a generalized beneficiary pool for transmission upgrades whose actual cost driver is hyperscaler load growth in Virginia, Pennsylvania, and Ohio. The complaint, if granted, would either remand PJM's allocation methodology or direct PJM to develop a participant-funded sub-regional surcharge for data-center-driven upgrades. The decision is precedent-setting for California in three ways: (1) it tests whether large-load cost causation can be statistically separated from generalized regional reliability needs at scale; (2) it informs CAISO's pending revisions to Rule 30 network-upgrade allocation; and (3) it establishes a record for CPUC arguments in future PG&E, SCE, and SDG&E exceptional-case AL filings that customer-specific cost-causation refunds (BARC) should be paired with non-detriment tests for non-participating bundled customers. Watch for whether FERC opens a Section 206 investigation, which would dramatically expand the proceeding's scope.

BTM cost recovery (the central §663(b)(8) dispute): The PD treats BTM costs as expenses amortizable over up to 10 years, with carrying cost capped at the utility's authorized cost of debt — aligning with TURN's framework from its December 17, 2025 Reply Comments and March 27, 2026 Opening Comments on the ALJ Ruling. PG&E and SoCalGas/SDG&E (Joint Utilities) oppose, seeking full WACC / rate of return via regulatory-asset treatment; Sierra Club + NRDC also prefer regulatory-asset at standard ROR but accept the PD's expense framing. Indicated Shippers and SBUA support the PD's no-ROR holding and ask for express language extending the bar to "regulatory assets, or another return-bearing mechanism."

Application vs. Advice Letter: The PD requires an Application; PG&E and Sierra Club/NRDC oppose (favoring 2- or 3-tier AL); Indicated Shippers and Cal Advocates support the PD; SCE asks for bifurcation (AL for <$7M, Application for larger).

67% pre-filing EOI threshold: Cal Advocates wants 80%; PG&E and Sierra Club/NRDC want elimination; most parties accept 67%. Cal Advocates also seeks a $3M cap on project-development costs for projects that never become applications, plus a lessons-learned report.

Cost-effectiveness level: PD adopts project-level; PG&E asks for program-level; Sierra Club/NRDC ask for portfolio-level (citing "legal error"); Indicated Shippers defends the PD.

Track 4 deferrals: Performance-based shareholder incentive deferred to Track 4. TURN's reply preview characterizes any incentive tied to BTM-driven savings as a prohibited deferred return under §663(b)(8). Cal Advocates opposes any shareholder incentive on speculative-need grounds. Sierra Club + NRDC want an equity-focused incentive added.

Other party-specific asks: SCE wants single-fuel electric-IOU co-administration (electric IOU cost recovery); CMUA wants reimbursement clarity for electric utilities (including POUs); CCSF wants ZEA limited to non-combustion (exclude hydrogen/propane/biomethane); ECCHHC wants tenant protections; CforAT wants outreach materials in large print/Braille; CCR REN wants RENs added to "coordinating entities" definition.

Reply window is the last opportunity to shape the Jul 2 voting outcome on California's structural overhaul of Resource Adequacy. Storage operators have the most to lose from the PD's penalty structure (charging-sufficiency shortfalls convert to a flat 24-hour MW adder, with the largest hourly deficiency setting the penalty) and from the UCAP derating that will move 2028 RA accreditation off nameplate capacity. LSEs have the most to gain from real-time deliverability tightening as paper capacity is formally ended. LDES developers get a formal RA accreditation pathway for the first time via the Forward Charge Period multiplier (2x for 8-hour resources, scaling to 8x for 72-hour-plus). The six Track 2 deferrals — hybrid resource methodology, Must-Offer Obligation basis, EFORd for the energy component of storage, fifth-hour foldback, Flexible RA interaction, and Slice-of-Day template integration — do not delay the 2028 effective date but remain unsettled 15 months before the first UCAP compliance year opens.

FERC's six-takeaway order signals that flexible-load tools (Grid-Enhancing Technologies, demand response) and Co-located Load Behind the Meter arrangements may have to satisfy federal cost-causation tests before being allowed to bypass RTO interconnection processes. Berkeley Lab's parallel analysis projects data centers could use up to 15% of all U.S. electricity by 2030, up from 5% in 2024. For California, the order matters in three ways: (1) it sets a federal floor for the kind of refund-cap and BARC-mechanism protections the CPUC is layering onto exceptional-case agreements like PG&E + Google; (2) it tightens the legal basis for arguments that hyperscale loads bear cost causation for upstream transmission; (3) it pressures CAISO's 2025-2026 Transmission Plan ($6.7B / 38 projects) toward more rigorous large-load attribution as the Tesla-Trimble-Metcalf 230 kV corridor and other South Bay reliability projects move forward. The Imperial County, CA 950,000-square-foot data center reversal reported by CalMatters (Jun 23) underscores that the federal backstop is colliding with local opposition at the same moment.

Why the data failed. D.24-09-020 established enforceable 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.

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 have start or end dates for those steps. SCE provided complete step-date data across all eight steps (the only utility to do so) but cannot separate IOU-controlled time from customer or third-party time. SDG&E struggled with multiple steps and could not track utility-controlled time separately.

Guidehouse's sufficiency thresholds: 95% availability for compliance data points; 75% for contextual data points. None met those thresholds. The ruling asks parties whether utilities that fail the proposed sufficiency thresholds should be required to file additional reporting on their energization backlogs — effectively converting bad data into its own regulatory problem. 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.

The PD adopts CAISO's recommended Local Capacity Requirements: 23,618 MW for 2027; 24,545 MW for 2028; and 25,480 MW for 2029. The LA Basin climbs from 6,823 MW to 7,721 MW over the three years; seven of 10 local areas carry the CAISO's resource-deficiency notation. Effective for the 2028 RA compliance year, dispatchable thermal, nuclear, geothermal, and non-hybrid storage resources will have accreditation reduced by their Equivalent Forced Outage Rate during RA Measurement Hours: UCAP = (1 - EFORd) x Pmax, applied separately for summer and non-summer seasons using the best three of the prior four calendar years of CAISO outage data. New resources receive class-average EFORd values until unit-specific history accumulates; thermal generators get NOAA 30-year typical weather-year derates. Preliminary UCAP values publish early 2027; final values September 2027.

Long-Duration Energy Storage is defined as any storage capable of discharging at maximum capacity for at least 8 continuous hours. For 2027, LSEs may count LDES capacity across the full 24-hour Slice-of-Day period using a Forward Charge Period multiplier ranging from 2x (eight-hour resources) to 8x (72-hour-plus resources). Closed-loop pumped storage hydropower receives LDES treatment; open-loop PSH deferred.

Storage charging sufficiency penalty: beginning 2027, an LSE with a MWh charging sufficiency shortfall has that shortfall converted to a flat 24-hour MW adder, applied to each hourly position, with the largest resulting hourly deficiency determining the RA penalty. Energy-only resources may not count toward RA capacity requirements; same-Point of Interconnection rule from 2027 allows EO excess to count toward charging sufficiency at deliverable storage co-located at the same POI, after subtracting the paired storage's own energy sufficiency need.

Rejections: hourly load obligation trading rejected (Energy Division's Transactability Report found no demonstrated inability for LSEs to meet Slice-of-Day obligations under existing mechanisms). The Commission ends paper capacity. Six implementation questions deferred to Track 2: hybrid resource methodology; Must-Offer Obligation basis; EFORd for storage energy component; fifth-hour foldback; Flexible RA interaction; Slice-of-Day template integration. None of those open items will delay the 2028 effective date. Comments due Jun 22; earliest vote Jul 2.

I.19-06-014 is the OII opened after the 2015 Aliso Canyon leak and the cascading findings on SoCalGas's institutional safety practices. The decision approves the revised plan as a foundation for implementation, while expressly declining to find that any specific intervention is adequate or effective. SoCalGas must, in its next quarterly compliance report: integrate security into its definition of comprehensive safety; strengthen contractor integration with metrics and oversight comparable to employee-focused efforts; expand its corrective-action program to capture public and non-occupational safety concerns; and demonstrate that "Learning Team" sessions on resource allocation continue until no new insights emerge. The decision also creates a Tier 2 Advice Letter pathway delegating Safety Policy Division authority to approve Safety Culture Improvement Plan revisions when interventions fall short, bypassing a full Commission vote. The decision finds Sempra's participation minimal; SoCalGas must maintain a consolidated plan tracking Sempra contributions and demonstrate through quarterly reporting how parent-level governance responds to assessment findings originally directed at Sempra. CPUC staff retains authority to engage SoCalGas's board directly.

Dais discussion (Jun 11): Commissioner Houck framed approval as a starting point, not an endpoint, with quarterly compliance reports until the next safety culture assessment (no later than August 2029). Commissioner Douglas said safety culture improvement must be demonstrated through measurable outcomes. Commissioner Harada drew on her aerospace background, distinguishing real safety from polished reports and dashboards. President Reynolds emphasized implementation must show measurable outcomes over time.

Cost recovery is the decision's most consequential outcome. SoCalGas has already incurred more than $5 million in unrecoverable Safety Culture Improvement Plan costs; the CPUC again rejects ratepayer recovery for safety culture remediation through the next assessment cycle. Expect Sempra investor disclosures to flag the decision as a 2026 charge against equity.

Google's load depends directly on the Newark-NRS 230 kV line (a $1 billion-plus project whose FERC-approved revenue requirement reaches ratepayers at roughly $100 million per year) plus more than ten other South Bay transmission upgrades. The CPUC previously capped refunds at 75% of net revenues for the STACK Infrastructure and Microsoft data centers (Resolutions E-5420 and E-5439); here it allows 100%, but only because the Rule 30 proceeding handles network-upgrade cost exposure separately. Energy Division notes that the Base Annual Revenue Calculation (BARC) process — built for distribution-scale energization where many similar customers statistically absorb stranded-cost risk — can, unadjusted, refund a large-load customer up to nine times first-year net revenues. The draft therefore caps refunds at actual net revenues and ties final terms to Rule 30. This is the first major California utility–data center supply agreement to clear CPUC staff review under the post-2024 large-load framework and will be cited in every subsequent large-load AL from PG&E, SCE, and SDG&E.

The project came online in December 2024 and already dispatches in CAISO markets, where RWE sells short-term resource adequacy on a merchant basis, so SDG&E's purchase adds no new physical capacity. Resolution E-5467 finds the project incremental on a technicality (it is not on the baseline resource list) and authorizes full CAM cost recovery. Energy Division reads the 120–220 MW Effective Planning Reserve Margin range as a floor utilities may exceed, rejecting CalCCA's argument that only ~11.4 MW should flow to CAM. The core ratepayer risk is deliverability: the project has interim status for 2025–2026 but will not reach Full Capacity Deliverability Status until transmission upgrades complete, potentially in 2034.

Dais discussion (Jun 11): Commissioner Baker called it the weakest of three utility-owned battery projects before the Commission, citing four reservations — SDG&E's incremental EPRM need may be only about 11 MW; SDG&E is long on Resource Adequacy; the battery likely would remain in service under RWE; and full deliverability remains unresolved until 2034 absent operational changes such as an eight-hour configuration. He nevertheless supported it, saying he would be nervous letting the opportunity pass. President Reynolds emphasized the multi-year review process, independent evaluator oversight, and Energy Division's cost review against comparable projects, framing planning reserve margins as an insurance policy. Mitigation rests on price concessions, RWE penalty provisions, continued CAISO participation, and quarterly CAM Procurement Review Group reporting rather than a firm RA-value guarantee.

The ratepayer-protection structure runs on actual costs with progress billing rather than estimates. Refunds on the regular-service facilities are tied to actual revenues after service begins, calculated through PG&E's BARC process over 10 years: if load underperforms, refunds shrink or disappear. The customer-funded redundant 115 kV line carries no refund rights — the customer eats every dollar of optional redundancy. PG&E's template across recent large-load advice letters: actual-cost payment; BARC-based refunds; minimum demand protections; no refund rights for customer-requested redundancy; and a CPUC/FERC jurisdictional split on cost recovery. PG&E is normalizing bespoke large-load agreements ahead of the Rule 30 outcome, using each filing to reinforce the same basic bargain: accelerated transmission service in exchange for upfront risk absorption.

Prices reflect weighted-average Renewable Portfolio Standard contract prices from utility, CCA, and ESP contracts executed 2020–2025 for projects of 20 MW or less. The baseload rate jumps 21% from $75.96/MWh, driven by geothermal contracts dominating the baseload reference set; non-peaking rises from $52.85/MWh; peaking is essentially unchanged from $67.99/MWh. The ReMAT program has produced 65 contracts totaling roughly 112 MW since inception, mostly small hydro and solar PV, with only two contracts executed in 2025. The resolution changes nothing about program design — it is the administratively set avoided-cost rate catching up to a higher-cost environment for small baseload renewables.

The methodology from Resolution G-3597 remains intact: fixed administrative costs ($212,491, or $5,449 per CTA, within the 20% tolerance band) are spread across all 39 registered agents, while variable costs are assigned by complaint and unauthorized-enrollment activity. The 2026 charges are $5.94 per phone contact and $189.52 per informal written complaint, with $680.43 per unauthorized-enrollment complaint and $739.17 per enforcement action. Unauthorized-enrollment complaints rose nearly 88%, even as total enforcement actions fell 83% (393 in 2024 to 65 in 2025). Four suppliers generated 52% of all complaints, so the cost-causation design leaves high-complaint CTAs paying substantially more than clean-record operators such as BP Energy, Shell, and Calpine, which pay only the $5,000 floor.

SERVM tests whether CAISO meets the 0.1 days/year LOLE standard. The baseline expansion makes over-reliability a plausible starting point, raising the stakes of staff's stress-test choices (adding perfect demand, reducing capacity pro rata, or lowering the import limit). The load assumptions remain contested: SERVM's modeled 2028 managed peak of 49,388 MW sits 1,032 MW above the IEPR projection because staff calibrate to consumption rather than managed demand. Diablo Canyon is counted in the 2028 RA baseline but excluded from IRP modeling, a mismatch that any RA determination premised on its presence will need to revisit. This ruling sets the assumptions that will produce the first major reliability determination in the proceeding.

The proceeding picks up unfinished tasks from D.25-08-032: adopting a formal risk tolerance standard, formalizing added RAMP review time for the Safety Policy Division, and standardizing Benefit-Cost Ratio methodology. TURN is the most skeptical that an abstract standard can be built at all, warning that utilities will drive stated tolerance toward zero because capital grows rate base and profit; it invokes Arrow's Impossibility Theorem against any representative-consensus working group and favors building on D.25-08-032's budget-constrained portfolios anchored in ESJ affordability. PG&E wants the standard built through evidentiary hearings; SCE wants Benefit-Cost Ratio methodology stabilized first. The key test across parties is unscaled, risk-neutral Benefit-Cost Ratio reporting: a mitigation that clears 1.0 only after risk-aversion adjustments is not the same as one that clears 1.0 before utility scaling.

On GHG issues, staff propose to (a) collapse separate electric and gas values into a single electric-sector figure derived from Integrated Resource Planning modeling; (b) eliminate the GHG Rebalancing component; and (c) cap total GHG value at the high societal cost of carbon. The Integrated Calculation moves from a Python optimization criticized by stakeholders as a black box to an Excel-based framework using RESOLVE GHG shadow prices; marginal capacity value would be derived from a hybrid solar-plus-storage resource rather than solved through the optimization. Hourly allocation changes are also substantive: staff would swap expected unserved energy for loss-of-load hours as the basis for capacity value allocation, on the theory that each avoided LOLH carries equal marginal reliability value regardless of shortfall magnitude. Temperature would give way to SERVM energy prices as the trigger for identifying high-capacity-value days, reflecting IRP modeling showing California's reliability risk migrating from hot summer peaks toward winter periods driven by electrification load and low renewable output. Staff also propose weekday/weekend differentiation consistent with reliability modeling and with downstream uses such as Net Billing Tariff export rates. The proposal is a reweighting of the economic signals that flow through DER cost-effectiveness tests, electrification incentives, gas-substitution economics, and Net Billing Tariff export rates across CPUC programs.

E-5456 (SCE): closes a participation shortfall that was leaving Self-Generation Incentive Program customers without a qualifying DR option when third-party aggregators withdrew. E-5444 (SDG&E): the proposal weakened penalties too far from the existing model and lacked the Resource Adequacy compliance and load-impact filings required of supply-side resources. E-5450 (PG&E ART): 30-day performance evaluation timeline, Day-of Adjustment standardization, CAISO tariff alignment, and minor formatting updates approved; the 30% capacity-payment rate increase rejected. E-5453 (Joint PG&E + SCE AutoDR): expands eligible customer segments and measures and adds PG&E's ART program as a qualified residential AutoDR program. The Commission will fix program-access problems and approve narrow implementation changes; it will not approve residential DR expansion or DER-based supply-side programs without the documentation that real capacity products require. Earliest vote July 2.

CAISO is planning around load growth from electrification, data centers, manufacturing, and transportation. PG&E's Greater Bay Area dominates the reliability picture — Tesla-Trimble-Metcalf and related Bay Area upgrades indicate that South Bay load growth is now a system-planning driver, not a one-off interconnection issue. Path 15 congestion forecasts have moved from 244 hours on the most-limiting circuit in 2030 (per the 2021-2022 plan) to 3,256 hours forecast for 2035, supporting the Gates-Los Banos project now and pointing toward a larger backbone decision next cycle. The Serrano-Del Amo-Mesa cancellation shows the ISO will kill projects when costs outrun the original planning case; its reliability function is replaced with the Mesa-Laguna Bell 230 kV #2 Upgrade and the policy need dropped after updated resource portfolios. Transmission planning is becoming bigger, more iterative, and more politically exposed to large-load cost allocation.

Vehicle-to-Grid commercial track record has promising data: Tellus Green Power's school-bus deployment ran 74 bidirectional chargers at 98%+ uptime over two years. Residential is a different story: PG&E's Vehicle-to-Everything pilots are behind enrollment targets, held back by equipment costs, customer-side integration complexity, and rate-design constraints. The record now shows the familiar California sequence: large theoretical avoided-cost value, thin customer uptake, rate design that can't target distribution-level constraints, uncertain export compensation, and pilots expiring before they generate scalable rules. The unresolved question is whether VGI can convert from pilot to scaled program before transportation electrification adds incremental peak load that the distribution system cannot absorb without bidirectional flexibility.

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.