MONDAY AGGREGATE: CPUC Approves SCE Rate-Design Settlements, Denies SoCalGas $266M for Angeles Link Hydrogen Pipeline

Today's roundup examines:

• A proposed decision largely approving SCE's 2024 General Rate Case Phase 2 settlements;
• A PD denying SoCalGas's request to recover $266 million from gas ratepayers for Angeles Link hydrogen pipeline engineering work;
• A ruling in the CPUC's Building Decarbonization proceeding soliciting input on scaling beyond pilot programs toward a formal action plan; and
• A workshop report in the High DER Future proceeding exploring flexible grid connections that would allow faster customer energization under "operating envelopes."

SCE 2024 GENERAL RATE CASE PHASE 2

A new proposed decision at the CPUC approves nine of 10 settlement agreements resolving SCE's 2024 General Rate Case Phase 2 on marginal costs, revenue allocation, and rate design. The PD denies a Vehicle-to-Grid Rate Proposal Settlement Agreement and declines to adopt three contested proposals (deferring PRIME Plus and baseline allowance expansion to future rulemakings, and finding the Solar Energy Industry Association's transmission marginal cost proposal outside the proceeding's scope).

The PD adopts a comprehensive settlement on marginal cost methodology and revenue allocation, agreed to by utilities, consumer advocates, and large customer groups. It sets key cost inputs (a $132.72/kW-year generation capacity marginal cost, Avoided Cost Calculator-based energy costs, and Real Economic Carrying Charge-based customer costs) and uses these to allocate SCE's revenue requirement across customer classes.

The settlement applies a revenue-neutral allocation framework built on an illustrative $17.5 billion consolidated revenue requirement (approximately $17,466 million as of October 2024), with rates ultimately updated to actual authorized revenues at implementation. To limit bill volatility, the PD introduces "collars" that constrain how far class revenues can move from current levels: +4.0%/−6.0% for delivery revenues around the System Average Percentage Change, and +0.97%/−1.9% for generation revenues for bundled service customers.

• A major element is the treatment of wildfire-related costs, which are allocated using a hybrid formula: 21.5% tied to distribution cost causation and 78.5% spread broadly based on system revenues, balancing cost causation with rate stability. The formula will be updated annually and governs until the next GRC Phase 2 proceeding.
• The V2G settlement was the only opposed agreement, with Cal Advocates arguing that using the Avoided Cost Calculator to set EV export compensation is premature. The ALJ agrees, finding that the CPUC has not sufficiently evaluated the accuracy of Avoided Cost Calculator-based versus real-time marginal-cost-based credits, customer behavior regarding export rates, or export flexibility under different compensation structures. Existing dynamic pricing pilots should be used until that evaluation is complete, which portends broader implications for the Avoided Cost Calculator's expanding role in ratemaking.
• On residential rate design, the approved settlement establishes a four-year glide-path moving Time-of-Use period rate differentials toward 80% of settled marginal cost ratios, with adjustments occurring each October 1 from 2026 through 2029. The TOU-D-PRIME seasonal differential increases from 2.4 to 6 cents/kWh, moving toward 100% of marginal cost levels over the same period.
• SCE's PRIME Plus proposal (a demand-based residential rate variant) was not rejected on its merits. The PD defers it to an anticipated industry-wide rulemaking on residential Time-of-Use rate structures, preserving the concept for future consideration.
• TURN's baseline allowance proposal raised a substantive issue: residential solar adoption is depressing metered usage and thereby shrinking baseline quantities, disproportionately harming non-Net Energy Metering customers. The ALJ acknowledges the problem but rules that the statutory definition of "residential consumption" under the Public Utilities Code refers to utility-delivered energy, not customer-generated energy. The issue was referred to a future rulemaking affecting all large electric investor-owned utilities.
• The Economic Development Rate settlement raises the EDR discount from 12% to 20%, increases the MW cap from 200 to 300 MW, expands the small customer demand threshold from 150 kW to 200 kW, and includes a limited Economic Development Rate program for host sites supporting the 2028 Olympic Games.

Comments are due April 9. The earliest the CPUC will consider this item is April 30.

INSTANT ANALYSIS: The PD carries four main implications.

• Cost causation loses to rate stability (by design). The collaring mechanism and System Average Percentage Change-heavy wildfire allocators blunt large redistributions.
• Wildfire costs are being socialized. The 78.5% System Average Percentage Change weighting spreads most wildfire burden broadly across load. This reduces class-specific exposure, especially for distribution-intensive customers.
• The Avoided Cost Calculator's role in ratemaking is now contested ground. The V2G rejection suggests that the CPUC is not prepared to extend Avoided Cost Calculator-based compensation beyond the Net Billing Tariff without further study. Parties pushing Avoided Cost Calculator-derived values into new rate structures (dynamic rates, export credits, marginal cost proceedings) now face a higher evidentiary bar.
• A playbook for the next GRC cycle. The settlement governs allocation mechanics until the next Phase 2. Future battles will shift from methodology to inputs: load forecasts, revenue requirement, and program costs. The baseline allowance and PRIME Plus deferrals ensure those fights will also play out in parallel rulemakings.

HYDROGEN/ANGELES LINK

The CPUC issued a proposed decision denying SoCalGas's request to recover $266 million from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the Angeles Link hydrogen pipeline project.

The project proposes dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. The PD finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision (D.22-12-055) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers.

• The record shows significant opposition from consumer advocates, environmental groups, and shippers, who argue that the project's benefits are indirect and uncertain, and that shifting early-stage development costs onto ratepayers would violate core cost-causation principles. Phase 2 cost estimates have nearly tripled since the project was initially proposed, rising from $92 million to $266 million.
• SoCalGas declined federal IIJA funding through ARCHES ( funding the CPUC had specifically directed the utility to pursue in D.22-12-055 to offset ratepayer exposure) arguing that federal compliance costs would not serve ratepayer interests. The PD notes this means no federal offset exists for the proposed costs.
• The PD concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise sharply, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. The PD does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational.
• The PD declines to resolve jurisdictional questions around whether the project would qualify as a pipeline under Public Utilities Code Section 227/228 or a gas plant under Section 221/222, finding such determinations both premature (because the project is not constructed or dedicated to public use) and unnecessary given the denial of cost recovery. The application is denied in full and the proceeding is closed, leaving SoCalGas to pursue the project, if at all, without ratepayer-backed funding for Phase 2.

Comments are due April 9. The earliest the CPUC will consider this item is April 30.

INSTANT ANALYSIS: The CPUC is rejecting the idea that speculative, pre-construction hydrogen infrastructure can be funded by legacy gas ratepayers, though it is not permanently foreclosing ratepayer recovery if the project is eventually constructed and demonstrated to be used and useful. For now, the PD is pushing hydrogen out of the mainstream utility cost-recovery model and into a merchant or contract-backed lane. The refusal of federal funding compounds the problem: SoCalGas eliminated the one mechanism the CPUC itself identified to cushion ratepayer impact, then asked ratepayers to absorb the full cost anyway. Developers will need anchor customers, bilateral deals, or external capital.

BUILDING DECARBONIZATION

A new ruling in the CPUC's Building Decarbonization rulemaking seeks stakeholder input on lessons learned, best practices, and next steps for scaling building decarbonization programs in California.

The ruling places into the record draft evaluation reports for the BUILD and TECH pilot programs (established under Senate Bill 1477 and D.20-03-027) and directs parties to comment on both those reports and a recent workshop that examined program performance, coordination, and long-term strategy.

The ruling frames this effort as part of Phase 4 of the proceeding, which is focused on developing a formal Building Decarbonization Action Plan. It builds on a January 2026 workshop and a staff-developed framework that identifies six categories of best practices for program design: integrated program offerings, measure-specific successes, right-sizing electric service, recognizing remediation needs, customer buy-in, and data and analytics, along with broader considerations like workforce development, codes and standards, and long-term system planning.

Through an extensive set of questions, the CPUC is probing gaps in current programs, coordination challenges across agencies and market actors, funding strategies, equity considerations, and infrastructure constraints. This includes the role of thermal energy networks and networked geothermal, zonal electrification lessons from PG&E's CSU-Monterey Bay project, and utility pilot authority under Senate Bill 1221, with the goal of shaping a more coherent, scalable, and cost-effective statewide decarbonization strategy.

Opening comments are due April 10, with replies due April 17.

INSTANT ANALYSIS: This is a record-building step ahead of a formal action plan. The CPUC is forcing parties to convert workshop input into concrete program design recommendations. The focus is on scaling beyond pilots. The explicit attention to thermal energy networks, CSUMB zonal electrification, and SB 1221 pilot authority signals where the Commission sees actionable near-term pathways. Expect movement toward integrated, zonal electrification tied to grid capacity, funding, and customer adoption. Outcomes here will feed into General Rate Cases, gas planning, and cost allocation.

DISTRIBUTED ENERGY RESOURCES

SCE filed an all-party workshop report in the CPUC's High DER Future proceeding regarding a February 20 Flexible Connections workshop.

The report explains that as electrification and DER adoption accelerate, traditional grid planning and infrastructure upgrades alone may not be sufficient to meet growing demand quickly or cost-effectively. To address this, regulators and stakeholders are exploring “flexible connections,” which allow customers to connect to the grid under time-varying or conditional limits (operating envelopes) so that existing grid capacity is used more efficiently without compromising safety or reliability.

The workshop brought together utilities, regulators, and industry stakeholders to evaluate the implementation of these flexible approaches. Discussions focused on enabling technologies such as:

• Advanced grid management systems (ADMS/DERMS);
• AMI data and metering capabilities (noting that PG&E cautioned against reliance on existing AMI 1.0 data for secondary-level operating envelopes due to data latency and limited load diversity, and that EPIC-funded pilots are exploring AMI 2.0 capabilities to address these gaps);
• Communication protocols (specifically the debate between utility-preferred IEEE 2030.5 and aggregator-preferred OpenADR for scalability); and
• Aggregators.

Discussions also focused on critical policy questions including:

• Customer participation and the shift from utility-controlled "top-down" models to elective "bottom-up" models;
• Cost-benefit considerations, with the Vehicle Grid Integration Council pointing to New York’s Load Management Technology Incentive Program as a potential model for upfront incentives; and
• The distinction between "bridging" solutions (temporary limits to allow faster connection before upgrades) and "non-bridging" solutions (ongoing flexible service that could defer or replace infrastructure investments).

Participants generally agreed that flexible connections (especially bridging solutions) offer immediate value by speeding up customer energization and reducing upgrade costs.

However, they expressed differing views on technical readiness and scalability. PG&E highlighted real-world "Flex Connect" deployments already in use on primary distribution systems, while SDG&E emphasized that it is not currently positioned to deploy a standardized, systemwide dynamic operating envelope offering, characterizing its current status as proof-of-concept and stating that the need for such an offering has not yet been demonstrated.

Stakeholder groups stressed the importance of transparency, consistent cost-benefit analysis, and regulatory clarity regarding compensation to ensure equitable and effective adoption.

INSTANT ANALYSIS: The CPUC is shifting from a "build-first" model to an "operate-first" model. Flexible connections let utilities constrain load and connect customers now, rather than wait for years of infrastructure upgrades.

• Near-term impact: Speed-to-power. PG&E is already using this approach for faster interconnections and avoided costs, specifically for large new loads on primary systems.
• The Scalability Constraint: The major hurdle is "non-bridging" (permanent) flexible service. Without clear rules on financial compensation, upfront hardware incentives (like New York's LMTIP), and a transition from "top-down" utility control to "bottom-up" customer election, long-term flexible service will not scale.
• Technical Readiness: PG&E's DERMS-enabled Flex Connect is operational on primary feeders today. Secondary-level success for residential and small business customers depends on multiple factors: the rollout of AMI 2.0, resolution of communication protocol standards, DERMS deployment and full secondary-system modeling (SCE targets 2027-2028), and validation through pilots currently underway.