CPUC April 9 Voting Preview: New Rulemaking Forces a Decision on Who Pays for Large Load

The CPUC published the agenda for its April 9 business meeting. Items that are up for consideration include:

• A major new rulemaking on electric rate design;
• Utility remediation plans that address problems in their Integration Capacity Analysis tools;
• Modification of the Renewable Gas Standard program;
• PG&E's arrangement with Citizens Energy Corporation for transmission entitlements; and
• ERRA compliance findings for SDG&E and SCE.

This agenda reflects a Commission increasingly focused on cost control, data accountability, and who ultimately bears system costs across rate design, procurement, and infrastructure investment.

We will provide same-day coverage of the meeting's results next week.

ELECTRIC RATE DESIGN

The Commission is expected to launch a new rulemaking on advanced electric rate design. The focus is on cost causation, affordability, and clearer price signals for grid use, covering both residential and non-residential rate structures.

• The proceeding carries forward unresolved issues from the Demand Flexibility rulemaking, including the Base Services Charge, dynamic rates, and electrification incentives. It also implements two new statutory requirements: a data-center cost impact assessment due to the Legislature by January 1, 2027, and an exemption from non-bypassable charges for certain industrial customers using process heat recovery technology (Assembly Bill 2109).
• A proposed consultant scope expands E3's existing public rate-design modeling tool and adds a new toolkit for large non-residential customers. Parties will be able to model bill impacts under different rate structures, including Time-of-Use periods, demand charges, and major cost drivers like transmission and wildfire costs.
• An Income Verification Process Working Group report addresses one specific question: how to subdivide the current undifferentiated Tier 3 (all non-CARE, non-FERA customers) into separate moderate- and high-income tiers. The near-term framework uses American Community Survey census tract median income data for initial classification. A customer-initiated appeals process, administered by a third-party vendor using tax transcripts and income documents, handles exceptions. Classifications refresh on a five-year cycle.
• The long-term direction points toward Franchise Tax Board tax data, but that requires legislative authorization that does not currently exist. The report is a consultant synthesis, not a consensus document. Advocate statements from TURN, Cal Advocates, Sierra Club, and others reflect significant remaining disagreement on methodology, cost, and accuracy tradeoffs.

INSTANT ANALYSIS: This new OIR is a major reset. The CPUC is pulling unresolved issues from multiple proceedings into one venue, with affordability, electrification, and large-load growth now colliding in a single docket. Standardized tools will compress disputes on inputs. That pushes fights toward methodology, cost-allocation assumptions, and who controls the analytical frame.

Two areas merit close attention.

• First, income-based charges depend on a verification framework that carries real cost and misclassification risk.
• Second, large-load treatment, especially data centers, sets up a direct allocation battle over who carries system costs. The Senate Bill 57 mandate frames that conflict explicitly around stranded costs and cost-shifting.

The outcome of this proceeding will shape rate structure and whether new load is treated as a benefit or a burden. Interconnection economics are a natural downstream consequence, though not a stated scope item in this order.

INTEGRATION CAPACITY ANALYSIS

Draft Resolution E-5440 approves, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their Integration Capacity Analysis tools. These tools estimate how much distributed energy can be added to the grid without upgrades.

The draft resolution requires the utilities to correct data errors, reactivate inactive circuits on maps, improve the timeliness of map updates, and expand reporting so stakeholders can track when Integration Capacity Analysis results diverge from real interconnection outcomes.

• It also establishes a formal concordance/discordance framework that categorizes interconnection and energization applications into one of four scenarios based on whether the ICA map value and the actual engineering outcome aligned. In so doing, it creates, for the first time, a structured taxonomy for measuring ICA usefulness across all three major electric utilities.
• The draft resolution orders SDG&E to stop excessive redactions of generation data, directs all utilities to publish more complete system information (including substations up to the transmission level) on public planning portals, and establishes new metrics to measure whether Integration Capacity Analysis outputs align with actual engineering results.
• The draft resolution codifies new definitions, distinguishing "ICA accuracy" (whether the utility correctly followed the approved methodology) from "ICA alignment" (whether ICA results match real-world engineering outcomes).

INSTANT ANALYSIS: This draft resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. The draft resolution finds SDG&E explicitly out of compliance on redaction practices, reinforcing that these are enforceable obligations.

For developers, DER providers, and large load customers, the main takeaway is that Integration Capacity Analysis outputs will become more auditable over the next six to 12 months as the new tracking and reporting requirements take effect. Utilities facing concordance scrutiny now have the incentive to understate available capacity.

BIOMETHANE

A proposed decision modifies the CPUC's Renewable Gas Standard program created under Senate Bill 1440 to modify biomethane procurement requirements for California's gas utilities.

The PD concludes that the procurement framework adopted in a 2022 decision (D.22-02-025) would impose excessive above-market costs on ratepayers given the early-stage biomethane market and limited feedstock supply.

• To address this, the PD adopts a Cost Containment Mechanism that caps average program rate impacts at 1% of each utility's bundled core customer revenue requirement with a maximum 3% year-over-year increase. The Cost Containment Mechanism is the controlling constraint; the CPUC will not approve contracts that would cause rates to exceed it.
• The PD also reduces the overall biomethane procurement target from 72.8 billion cubic feet annually to 36.4 billion cubic feet and extends the compliance timeline from 2030 to 2035. The prior short-term/medium-term structure is eliminated in favor of a single 2035 deadline. The Diverted Organic Waste procurement goal of 17.6 Bcf remains unchanged, tied to California's Senate Bill 1383 methane-reduction policy.
• The PD opens all feedstocks to bid into utility solicitations while maintaining the dedicated Diverted Organic Waste target and directs utilities to revise their Renewable Gas Procurement Plans via Tier 2 Advice Letters. The 4% livestock biomethane procurement limit is retained.

The PD removes the previous 2040 delivery cutoff so contracts can extend beyond that date, retains the M-RETS tracking system, and establishes an 80/10/10 Renewable Thermal Certificate unbundling framework: 80% of biomethane by volume stays bundled with Renewable Thermal Certificate retired by the utility; 10% allows the developer to retain the RTC; 10% allows the utility to market it. Unbundled volumes purchased at market rate do not count against the Cost Containment Mechanism.

INSTANT ANALYSIS: The CPUC is walking back the scale of the Renewable Gas Standard after early procurement revealed high costs and limited biomethane supply. The PD cuts the overall target in half while preserving the full Diverted Organic Waste target, pushes the deadline to 2035, and imposes a strict Cost Containment Mechanism that halts procurement if program costs exceed a 1% average rate impact measured against each utility's bundled core customer revenue requirement.

If the PD is adopted, RNG procurement will continue, but under strict affordability constraints. The program would shift from an aggressive decarbonization mandate to a controlled, ratepayer-limited market experiment. The 80/10/10 Renewable Thermal Certificate unbundling framework is a novel structure worth watching; if it demonstrates cost savings, expect expansion in future proceedings.

In short, the CPUC is capping ambition because the economics failed early.

TRANSMISSION PROJECTS

A proposed decision in A.24-03-009 allows PG&E to enter into a long-term investment arrangement with Citizens Energy Corporation, under which Citizens could lease partial transmission entitlements in future PG&E transmission projects.

The proposal stems from a "Development, Coordination, and Option Agreement" executed in 2024 (and amended in 2025), allowing PG&E to offer Citizens up to five investment tranches totaling as much as $1 billion in transmission projects.

For each tranche, Citizens could acquire up to 49.9% of the transmission entitlement rights through a 30-year lease, paying PG&E a lump-sum “prepaid rent” based on the project’s capital cost share. PG&E would still develop, construct, own, operate, and maintain the transmission assets, while Citizens would receive a share of transmission revenues through the CAISO’s High-Voltage Transmission Access Charge system.

INSTANT ANALYSIS: The CPUC does not fully approve PG&E's $1 billion Citizens Energy transmission financing program but allows the framework to proceed through a closely supervised, tranche-by-tranche process. Stated differently: third-party capital is being allowed in but is not yet trusted. The PD applies a heightened "public interest" standard and extensive reporting requirements, which reflect concern about undefined projects, potential rate impacts, and ratepayer-assistance accountability.

ERRA COMPLIANCE

A proposed decision approves (with modifications) SDG&E's 2023 Energy Resource Recovery Account compliance application, finding that the utility’s power procurement, contract administration, dispatch decisions, and related accounting were largely prudent and consistent with CPUC-approved plans.

The PD adopts several negotiated changes, including revising the valuation of retained Resource Adequacy capacity, correcting the accounting of Renewable Energy Certificates for Renewable Portfolio Standard compliance, and reallocating certain battery storage revenues to a broader customer base. The PD also determines that SDG&E recorded a net undercollection of about $214.6 million across its procurement-related balancing accounts (excluding confidential subaccounts) and allows recovery of those costs through established mechanisms.

Separately, another PD approves SCE's 2023 Energy Resource Recovery Account compliance application. The PD determines that SCE prudently managed its utility-owned generation resources, administered energy contracts appropriately, and recorded costs in ERRA and related balancing and memorandum accounts accurately. As a result of account balances across several regulatory accounts, the PD directs SCE to reduce its revenue requirement by $63.195 million through a rate decrease and to return $70,811 in unrealized revenues associated with four 2023 Public Safety Power Shutoff events.

The key takeaway is what did not happen. The PD declines to escalate oversight of SCE's procurement despite pressure from Cal Advocates. For utilities and counterparties, this preserves (for now) the current ERRA framework as a retrospective accounting review, not a venue for expanding procurement enforcement.

INSTANT ANALYSIS: These two PDs reinforce the Commission’s continued willingness to true-up procurement costs with limited disallowance risk, while using the ERRA forum to impose targeted accounting and allocation corrections rather than broad prudence challenges.

SCE emerges with a straightforward compliance finding and a modest $63.2 million rate decrease tied to overcollection, while SDG&E's filing is approved with modifications that adjust Resource Adequacy valuation, RPS accounting, and battery storage revenue allocation, ultimately preserving cost recovery but redistributing impacts across customer classes.

The PDs telegraph that the Commission is leaning into granular portfolio accounting scrutiny (RA, RPS, storage revenues, affiliate transfers) while avoiding disruptive second-guessing of procurement decisions under the reasonable manager standard. That keeps procurement risk relatively contained for investor-owned utilities, but expands exposure on how value streams are classified and allocated, particularly as storage, RA attributes, and program costs become more complex.

For market participants, these actions suggest a process where cost recovery remains reliable, but margin and cost-allocation outcomes are shaped in compliance proceedings rather than forecasts or procurement approvals.