8587.13.

 (a) For purposes of this section, “major event” means a large storm, flood, mudslide, fire, earthquake, or other occurrence that significantly affects the safety and reliability of the electrical or gas distribution system.

(b) On or before September 30, 2019, and on or before September 30 of every 2 two years thereafter, the office, in consultation with the Department of Forestry and Fire Protection, the Public Utilities Commission, and other appropriate state and local agencies, shall adopt or update standards for reducing risk from a major event.

(c) The standards shall include both of the following:

(1) Model policies that may be undertaken by local governments regarding zoning, defensible space, fire-resistant building materials, and other measures applicable to properties at risk during a major event.

(2) Actions that may be undertaken by electrical corporations, gas corporations, local publicly owned electric utilities, local publicly owned gas utilities, and water utilities to reduce the risk of fire during a major event.

454.

 (a) (1) Except as provided in Section 455, a public utility shall not change any rate or so alter any classification, contract, practice, or rule as to result in any new rate, except upon a showing before the commission and a finding by the commission that the new rate is justified. Whenever any electrical, gas, heat, telephone, water, or sewer system corporation files an application to change any rate, other than a change reflecting and passing through to customers only new costs to the corporation that do not result in changes in revenue allocation, for the services or commodities furnished by it, the corporation shall furnish to its customers affected by the proposed rate change notice of its application to the commission for approval of the new rate. This notice requirement does not apply to any rate change proposed by a corporation pursuant to an advice letter submitted to the commission in accordance with commission procedures for this means of submission. The procedures for advice letters may include provision for notice to customers or subscribers on a case-by-case basis, as determined by the commission. The corporation may include the notice with the regular bill for charges transmitted to the customers within 45 days if the corporation operates on a 30-day billing cycle, or within 75 days if the corporation operates on a 60-day billing cycle. If more than one application to change any rate is filed within a single billing cycle, the corporation may combine the notices into a single notice if the applications are separately identified. The notice shall state the amount of the proposed rate change expressed in both dollar and percentage terms for the entire rate change as well as for each customer classification, a brief statement of the reasons the change is required or sought, and the mailing and, if available, email address of the commission to which any customer inquiries may be directed regarding how to participate in, or receive further notices regarding the date, time, or place of, any hearing on the application, and the mailing address of the corporation to which any customer inquiries relative to the proposed rate change may be directed.

(2) For a safety, reliability, and resiliency plan submitted by an electrical or gas corporation pursuant to Section 2899.2, the corporation shall furnish to its customers written notice with the regular bill for charges for the two billing cycles before it submits the plan. The written notice shall include a link to the Internet Web site where the plan will be available electronically upon its submission.

(b) For a water corporation with more than 2,000 service connections, the notice required in subdivision (a) shall include estimated rate impacts on the various customer classes of the corporation. The commission may require the corporation to inform customers in a separate letter or through a bill insert, at the corporation’s discretion, of the outcome of the general rate case, within 60 days if the corporation operates on a 30-day billing cycle, or within 90 days if the corporation operates on a 60-day billing cycle, of the commission’s final decision, including the approved rates and the approved capital projects that will subsequently be executed by way of an advice letter.

(c) The commission may adopt rules it considers reasonable and proper for each class of public utility providing for the nature of the showing required to be made in support of proposed rate changes, the form and manner of the presentation of the showing, with or without a hearing, and the procedure to be followed in the consideration thereof. Rules applicable to common carriers may provide for the publication and filing of any proposed rate change together with a written showing in support thereof, giving notice of the filing and showing in support thereof to the public, granting an opportunity for protests thereto, and to the consideration of, and action on, the showing and any protests filed thereto by the commission, with or without hearing. However, the proposed rate change does not become effective until it has been approved by the commission.

(d) (1) The commission shall permit individual public utility customers and subscribers affected by a proposed rate change, and organizations formed to represent their interests, to testify at any hearing on the proposed rate change, except that the presiding officer need not allow repetitive or irrelevant testimony and may conduct the hearing in an efficient manner.

(2) The commission shall permit any member of the public to testify at any hearing or proceeding authorized under the Utility Infrastructure, Safety, Reliability, and Accountability Act (Chapter 11 (commencing with Section 2899) of Part 2), except that the presiding officer need not allow repetitive or irrelevant testimony and may conduct the hearing in an efficient manner.

2899.

 This chapter shall be known, and may be cited, as the Utility Infrastructure, Safety, Reliability, and Accountability Act.

2899.1.

 For purposes of this chapter, the following definitions apply:

(a) “Distribution system” means the portion of the electric system beginning with equipment that operates at voltages lower than that controlled by the Independent System Operator up to and including the customer’s meter, and that is used to transmit, deliver, store, or furnish electricity, light, heat, or power.

(b) “Major event” means a large storm, flood, mudslide, fire, earthquake, or other occurrence that significantly affects the safety and reliability of the electrical or gas distribution system.

(c) “Plan” means the safety, reliability, and resiliency plan filed by an electrical or gas corporation pursuant to Section 2899.2, including measures addressing both routine operations and major events.

(d) “Utility” means an electrical corporation or gas corporation.

2899.2.

 (a) On or before July 1, 2019, and on or before July 1 every two years thereafter, each utility shall prepare and submit to the commission an application for review and approval of a safety, reliability, and resiliency plan. The plan submitted on or before July 1, 2019, shall be limited to addressing fire risks, with subsequent plans addressing risks associated with routine operation and all major events. The plan shall include sufficient information for the public and the commission to determine the costs and benefits to ratepayers of the investments proposed in the plan.

(b)  The plan shall include all of the following elements:

(1) All relevant safety rules, regulations, standards, and practices adopted by the commission and, after January 1, 2021, all applicable standards adopted or updated by the Office of Emergency Services pursuant to Section 8587.13 of the Government Code.

(2) A program to comply with applicable safety rules, regulations, standards, and practices adopted by the commission and, after January 1, 2021, a program to comply with standards adopted or updated by the Office of Emergency Services pursuant to Section 8587.13 of the Government Code.

(3) A program to manage compliance, including, but not limited to, plans for assigning personnel, training, and monitoring and checking that the personnel have carried out their assignments, and a system of quality assurance and quality control.

(4) The wildfire mitigation plan submitted pursuant to Section 8386, including protocols for disabling reclosers and deenergizing portions of the electrical distribution system that consider the impacts on public safety, as well as protocols related to mitigating the public safety impacts of those protocols, including impacts to critical first responders, and to health and communication infrastructure.

(5) Actions the utility will take to ensure that its system will achieve the highest level of safety, reliability, and resiliency, and to ensure that its system is prepared for a major event, including hardening and modernizing its infrastructure with improved engineering, system design, standards, equipment, and facilities.

(6) Plans for vegetation management.

(7) For gas corporations, both of the following:

(A) A program to preemptively replace pipe and other equipment that is aging, brittle, or otherwise vulnerable to damage from a major event, or that could endanger public or employee safety.

(B) A program to locate, mark and repair leaks, relight pilot lights, and all other activity needed to restore service following a major event.

(8) For electrical corporations, a program to evaluate and incorporate technological solutions, such as distributed energy resources and microgrids that can be islanded from the distribution grid for critical customers or critical facilities, such as schools, hospitals, critical care patients, water pumping and treatment facilities, telecommunication infrastructure, and government and other facilities that provide public safety or other critical functions.

(9) The disaster and emergency preparedness plan prepared pursuant to Section 768.6, including both of the following:

(A) Plans to prepare for, and to restore service after, a major event, including workforce mobilization, and prepositioning equipment and employees.

(B) Plans for community outreach and public awareness before, during, and after a major event.

(10) Plans for distribution grid operation during a major event, including an incident command system.

(11) Clear evidence that the utility has an adequately sized and trained workforce to promptly restore service after a major event, taking into account employees of other utilities pursuant to mutual aid agreements and employees of entities that have entered into contracts with the utility.

(12) Activities to support customers during and after a major event, including outage reporting, billing, repair processing and timing, access to utility representatives, emergency communications, and restoration plans.

(13) Forecasted costs of every element of the plan.

(14) Any other element pertaining to electric and gas safety, reliability, or resiliency deemed appropriate by the commission.

(c) (1) The commission shall review the plans of the utilities in a single consolidated proceeding. The commission shall accept comment on the plans from the public and interested parties and verify that the plans comply with all applicable rules, regulations, and standards, including those adopted by the Office of Emergency Services pursuant to the State Assistance for Fire Equipment Act (Article 5.5 (commencing with Section 8589.8) of Chapter 7 of Division 1 of Title 2 of the Government Code), as appropriate. The commission shall evaluate the reasonableness of the elements of the plans considering the risks involved and the costs to implement the plan.

(2) In reviewing the plans, consistent with its ratepayer protection duties pursuant to Article 1 (commencing with Section 451) of Chapter 3 of Part 1, the commission shall ensure that the cost impacts of the plans are just and reasonable for ratepayers while prioritizing protecting public safety and the reliability of electric and gas services.

(3) Notwithstanding Section 1701.5, with or without modification, the commission shall strive to approve the plans within 12 months of, but in no case shall approve the plans more than 18 months after, their submission, unless the commission makes a written determination, including reasons supporting the determination, that the 18-month deadline cannot be met, and issues an order extending the deadline. Each utility’s approved plan shall remain in effect until the commission approves the utility’s subsequent plan.

(4) (A) Consistent with its ratepayer protection duties pursuant to Article 1 (commencing with Section 451) of Chapter 3 of Part 1, the commission shall authorize rate recovery of the reasonable revenue requirements to implement plans approved by the commission in the proceeding reviewing the plans pursuant to paragraph (1).

(B) All forecasted costs not included in the plan or deemed outside the scope of the plan by the commission may be requested and considered in a utility’s general rate case or other appropriate proceeding.

(5) The utilities shall not divert revenues authorized to implement the plan to any activities or investments outside their plans.

(6) Each utility shall establish a memorandum account to track costs incurred for fire risk mitigation from January 1, 2019, until the commission’s approval of the utility’s plan submitted on or before January 15, 2019, that are not otherwise covered in the utility’s revenue requirements. The commission shall review the costs in the memorandum accounts and disallow recovery of those costs the commission deems unreasonable.

(d) On or after January 1, 2019, each utility’s Risk Assessment Mitigation Phase filing shall exclude risks addressed in the plan required pursuant to subdivision (b).

(e) The commission may extend the three-year general rate case cycle to a four-year general rate case cycle.

2899.3.

 (a) For purposes of this section, “distribution system safety or reliability performance obligations” of an electrical corporation include, but are not limited to, owning, controlling, operating, managing, maintaining, planning, engineering, designing, investing in, and constructing the distribution system in its service territory, distribution system reliability, emergency response and restoration, vegetation management, service connections, service turnons and turnoffs, and service inquiries relating to the operation of the distribution system.

(b) (1) An electrical corporation shall not delegate, transfer, or contract out any distribution system safety or reliability performance obligation.

(2) Notwithstanding paragraph (1), an electrical corporation may contract with the owner or operator of a distributed energy resource so long as the owner or operator of the distributed energy resource meets the insurance requirements set by the commission to cover direct damages caused by the failure of the distributed energy resources to comply with the terms of the contract.

(c) The prohibition specified in paragraph (1) of subdivision (b) does not apply to line clearance tree trimming under the supervision of the electrical corporation, the purchase of materials or equipment, contracting for construction of infrastructure owned by the electrical corporation, contracting for pole test and treat services, contracting for bulk electricity capacity, energy, or storage that is not for purposes of distribution system safety and reliability, or contracting for information technology services.

(d) Paragraph (1) of subdivision (b) does not prohibit a cable television corporation or telephone corporation from contracting for make-ready work or performing work on its equipment attached to poles that also support equipment owned by an electrical corporation.

(e) When performing the planning, engineering, and design described in subdivision (a), the electrical corporation shall consider both of the following:

(1) The current and future load.

(2) The current and future distributed energy resources owned by the electrical corporation, community choice aggregators, or any other person or entity.

2899.4.

 The commission shall conduct an annual proceeding to review each utility’s compliance with its plan, including a factual analysis of any major events that occurred, as follows:

(a) Beginning March 1, 2021, and each March 1 thereafter, each utility shall file with the commission a report addressing compliance with the plan during the prior calendar year.

(b) (1) Prior to March 1, 2021, and prior to each March 1 thereafter, the commission shall make available a list of qualified independent evaluators with experience in assessing electric and gas operations.

(2) Each utility shall engage an independent evaluator listed pursuant to paragraph (1) to review and assess the utility’s compliance with its plan. The independent evaluator shall consult with, and operate under the direction of, the Safety and Enforcement Division of the commission. The independent evaluator shall issue a report on July 1 of each year in which a report required by subdivision (a) is filed. As a part of the independent evaluator’s report, the independent evaluator shall determine whether any revenue authorized to implement the plan was diverted to any activities or investments outside the plan. The commission shall strive to complete its compliance review within 12 months of, but in no case shall that review be completed more than 18 months after, the submission of a utility’s compliance report.

(3) The commission shall authorize the utility to recover in rates the costs of the independent evaluation.

(4) The commission shall have exclusive jurisdiction over compliance by a utility with the standards adopted pursuant to Section 8587.13 of the Government Code.

2899.5.

 The commission shall assess penalties if a utility fails to substantially comply with its plan. In determining an appropriate amount of the penalty, the commission shall consider all of the following:

(a) The nature and severity of any noncompliance with the plan, including whether the noncompliance resulted in harm.

(b) The extent to which the commission has found that the utility complied with its plans in prior years.

(c) Whether the utility self-reported the circumstances constituting noncompliance.

(d) Whether the utility implemented corrective actions with respect to the noncompliance.

(e) Whether the utility had advance notice of the circumstances constituting noncompliance.

(f) Whether the utility had previously engaged in conduct of a similar nature that caused significant property damage or injury.

(g) Any other factors established by the commission in a rulemaking proceeding, consistent with purposes of this section.

2899.6.

 (a) After completing the review pursuant to Section 2899.4, if, either at the time the plan is reviewed and approved or subsequent to its review and approval, the commission determines that a utility was in substantial compliance with its approved plan, the commission, to the extent the commission finds it is consistent with the ratepayer protection duties established pursuant to Article 1 (commencing with Section 451) of Chapter 3 of Part 1, shall find that the utility’s performance, operations, management, and investments addressed in the plan are reasonable and prudent for purposes of any subsequent commission proceeding.

(b) Any findings made pursuant to Section 2899.4:

(1) Shall be used by the commission to carry out its obligations under Section 451.

(2) Shall not apply to performance, operations, management, or investment not addressed or outside the scope of the approved plan.

(3) Shall not affect any civil action. Nothing in this paragraph shall impact the admissibility of evidence otherwise permitted by law or rule of court.

(4) Shall not apply to events that occurred before the first plan is approved for a particular utility.