Natural Gas Ratepayer Protection Act.

The entire legislative findings and declarations section (old Section 2) was removed, which had stated California's greenhouse gas obligations, acknowledged structural load decline in the gas system, declared that continued investment under declining demand creates stranded asset risk, affirmed electrification as the lowest-cost pathway, and expressed intent to direct the PUC toward a managed transition of the gas system.

Annual report item (6) was narrowed from requiring disclosure of all 'available electrification and nonpipeline alternatives' to only those 'implemented or evaluated since the gas corporation's immediately preceding general rate case decision,' reducing the breadth of alternatives analysis required.

Annual report item (5) now requires an assessment of 'the distributional impacts of stranded assets on remaining gas ratepayers,' adding a new equity-focused analytical requirement beyond the existing stranded asset risk assessment.

A new Section 329.1(b)(2) allows the commission to specify reporting requirements that reduce duplication and align timelines with other existing reporting obligations, giving the PUC flexibility to streamline compliance.

A new standalone section (second 329.1) requires the commission, as part of its long-term gas planning rulemaking or a successor proceeding, to consider developing a framework for depreciation of gas distribution infrastructure that reflects reasonably foreseeable changes in gas demand and is designed to minimize future ratepayer exposure to stranded asset costs, and authorizes the commission to apply that framework in evaluating depreciation and cost recovery.

Annual report item (1) now requires expenditures to be 'as determined by the commission, in alignment with information already reported through general rate case, risk assessment mitigation phase, or successor proceedings,' adding a coordination requirement with existing reporting processes.

Removed the requirement that the commission determine consistency with state greenhouse gas emission reduction targets before approving any gas distribution infrastructure capital investment exceeding $10 million. Also removed the associated requirement that utilities provide evidence on electrification infeasibility, nonpipeline alternatives, stranded asset risk, and climate policy consistency, and the requirement to prioritize lower-cost nonpipeline alternatives.

Added a requirement that the commission adopt implementing rules (in its long-term gas planning rulemaking or successor proceeding) for the electrification-alternative cost recovery analysis, including a reasonable cost threshold below which the requirement would not apply. This gives the commission flexibility to set a de minimis level rather than applying the analysis to every project.

Added a savings clause (new Section 329.1(c)) stating that nothing in the section shall delay or disallow recovery of prudently incurred costs required for safety, reliability, legal compliance of gas distribution infrastructure, or emergency or catastrophic event response. This carves out a broad exception to the new cost-recovery review requirement.

The bill title was shortened from 'Gas Transition Responsibility and Electrification Act. Natural Gas Ratepayer Protection Act' to simply 'Natural Gas Ratepayer Protection Act,' dropping the broader 'Gas Transition Responsibility and Electrification' framing.

Removed amendments to Public Utilities Code Section 451, which would have required gas corporation service obligations to be interpreted consistent with greenhouse gas reduction mandates and building electrification policies, and authorized the commission to order retirement of gas distribution infrastructure.

Removed the broad transition framework (former Section 329.1) that would have required the commission to identify electrification priority zones, establish a retirement process with a five-year minimum notice period, allocate unrecovered net book value between shareholders and ratepayers, and evaluate depreciation practices.

Removed amendments to Public Utilities Code Section 977, which would have prohibited ratepayer recovery of costs associated with avoidable natural gas leakage (including methane from inadequate maintenance or replacement delays) and banned recovery of the value of all natural gas lost to the atmosphere beginning January 1, 2030.

Removed the Gas Infrastructure Decommissioning Trust requirement (Section 329.2), which would have required each gas corporation to establish a trust funded by shareholders for decommissioning, environmental remediation, and workforce transition, with no ratepayer recovery of contributions.

Removed the annual transition report requirement (former Section 329.3) that would have required gas corporations to file reports beginning January 1, 2030, including long-term demand forecasts, scenario analysis assuming up to 90 percent reduction in natural gas demand by 2045, and estimated stranded asset exposure.

Added an annual report requirement for each gas corporation describing expenditures on gas distribution infrastructure replacement and upgrade projects during its current general rate case cycle, including planned and actual expenditures, project status, remaining costs, memorandum account entries (wildfire, catastrophic event), material changes in assumptions including stranded asset risk, and available electrification and nonpipeline alternatives.

Added a requirement that before authorizing recovery of costs for gas distribution infrastructure replacement or upgrade projects, the commission must consider whether cost-effective electrification or nonpipeline alternatives could reasonably avoid or reduce those costs.

Added a requirement that the commission evaluate whether depreciation schedules for gas distribution infrastructure replacement and upgrade projects appropriately reflect projected reductions in gas demand and consider alternative depreciation methodologies that minimize future ratepayer exposure to stranded asset costs.

Removed the prohibition (former Section 329.4) on extending new natural gas service to residential or mixed-use developments unless the applicant pays the full cost of the extension, effective January 1, 2030.

Removed the requirement (former Section 329.5) that the commission initiate a rulemaking to implement the article by July 1, 2029.

The bill's short title was expanded from 'Gas Transition Responsibility and Electrification Act' to 'Gas Transition Responsibility and Electrification Act. Natural Gas Ratepayer Protection Act,' reframing the emphasis toward ratepayer protection.

Capital investment review threshold doubled from $5,000,000 to $10,000,000, meaning gas corporations can make larger investments without triggering the commission's greenhouse gas consistency determination.

Stranded asset risk standard softened from a flat prohibition ('will not create stranded asset risk within a 20-year planning horizon') to a flexible consideration requirement ('appropriately considers potential stranded asset risk over the expected useful life of the asset').

Investment approval rule changed from an outright prohibition on approving investments when a cheaper nonpipeline alternative exists, to a prioritization requirement with an added exception allowing approval when necessary for safety, reliability, or legal compliance.

Added new Section 451(e) stating that nothing in the section shall be interpreted to compromise the safety or reliability of the natural gas system, providing a general safety carve-out.

Removed the hard floor requiring at least 50 percent of unrecovered net book value from retired infrastructure to be borne by shareholders. Replaced with a requirement that the commission 'consider mechanisms to allocate' costs between shareholders and ratepayers in a just and reasonable manner that minimizes ratepayer impacts.

New gas service extension surcharge (effective January 1, 2030) expanded from covering only the expected cost of future decommissioning to covering all costs that would otherwise be borne by existing ratepayers, as determined by the commission.

Definition of avoidable natural gas leakage costs now includes the qualifier 'as determined by the commission based on prudent utility practices and existing safety standards,' giving the commission discretion in what qualifies as avoidable.

The amendment to Section 892 (regarding the Gas Consumption Surcharge Fund and Treasurer deposit requirements) was dropped entirely from the bill.

Legislative findings expanded to include a reference to the commission's active long-term gas planning rulemaking (R.24-09-012), and the intent statement now includes 'ensure a just transition for workers.'

Fiscal committee review and state-mandated local program designation both changed from 'no' to 'yes,' indicating the bill now triggers additional legislative process requirements.

The bill was renamed the Gas Transition Responsibility and Electrification Act and expanded from a single-section typo fix to a multi-article framework adding Article 2 (Sections 329-329.6) to Chapter 2.2 of Part 1 of Division 1 of the Public Utilities Code, plus amendments to Sections 451 and 977.

State-mandated local program designation changed from 'no' to 'yes' because violations of commission actions implementing the bill's requirements would constitute crimes under the Public Utilities Act. Fiscal committee review also changed from 'no' to 'yes.'

Gas corporations must obtain commission approval for any capital investment in natural gas distribution infrastructure exceeding $5 million, demonstrating that electrification alternatives are infeasible or more costly over the project life cycle, a nonpipeline alternative was evaluated, no stranded asset risk exists within 20 years, and the investment is consistent with state climate policy.

The commission must develop a framework for orderly transition of the natural gas distribution system, including identification of electrification priority zones, a retirement process for infrastructure in those zones, and a minimum five-year notice period before service discontinuation.

The commission cannot approve ratepayer recovery of hydrogen blending costs unless it makes a written finding that blending is more cost effective than electrification, achieves greater life-cycle GHG reductions, results in just and reasonable rates, and meets safety standards. Hydrogen blending cannot be used to justify extending asset useful life, approving new investments, avoiding accelerated depreciation, or recovering stranded asset costs.

Section 451 is amended so that a gas corporation's obligation to furnish service must be interpreted consistent with state greenhouse gas emission reduction mandates and building electrification policies. The commission may authorize retirement or discontinuation of gas infrastructure where continued operation is inconsistent with the public interest.

At least 50 percent of unrecovered net book value from infrastructure retired due to load decline or climate policy compliance must be borne by gas corporation shareholders. Default remaining useful life for natural gas distribution assets is reduced to 10-15 years unless the utility demonstrates otherwise.

Each gas corporation must establish a Gas Infrastructure Decommissioning Trust funded exclusively through shareholder contributions (not ratepayers) for decommissioning, environmental remediation, and workforce transition programs.

Section 977 is amended to require that costs associated with avoidable natural gas leakage (including methane emissions from inadequate maintenance or replacement delays) are not recovered from ratepayers. Beginning January 1, 2030, the commission cannot allow recovery of any natural gas lost to the atmosphere from facilities under the utility's control, with an exception for acts of God.

Beginning January 1, 2030, gas corporations must annually file climate transition risk reports including long-term demand forecasts, scenario analysis assuming up to 90 percent demand reduction by 2045, and estimated stranded asset exposure. The commission must use these reports when determining authorized rates of return.

The commission must initiate a rulemaking to implement the new Article 2 provisions on or before July 1, 2029.

Beginning January 1, 2030, gas corporations are prohibited from extending new natural gas service to residential or mixed-use developments unless the applicant pays the full cost of extension, including a surcharge reflecting expected future decommissioning costs.

The capital investment threshold triggering commission review was raised from $5,000,000 to $10,000,000, meaning fewer gas infrastructure projects would require the new climate consistency determination.

The entire hydrogen blending section (former Section 329.2) was deleted. This had prohibited ratepayer recovery of hydrogen blending costs unless specific conditions were met, barred using hydrogen blending to justify extending asset life or approving new investments, and prevented it from qualifying as a nonpipeline alternative.

The stranded asset risk requirement was softened from a prohibition ('will not create stranded asset risk within a 20-year planning horizon') to a weaker standard ('appropriately considers potential stranded asset risk over the expected useful life of the asset').

The specific default remaining useful life assumption of 10 to 15 years for natural gas distribution assets was removed. The commission now only needs to evaluate depreciation practices reflecting updated demand forecasts.

The requirement that at least 50% of unrecovered net book value from retired infrastructure be borne by shareholders was removed and replaced with a directive that the commission 'consider mechanisms to allocate' costs between shareholders and ratepayers in a just and reasonable manner.

The requirement that new gas service extensions include a specific 'surcharge reflecting the expected cost of future decommissioning' was removed, replaced with the broader language 'all costs that would otherwise be borne by existing ratepayers.'

The annual report required from gas corporations beginning January 1, 2030 was renamed from 'climate transition risk report' to 'transition report.'