SB-1088 - Latest Action - PGandE

Article Source: California State Legislature

Moving through the California State Senate

SB-1088 Safety, reliability, and resiliency planning: general rate case cycle.(2017-2018)

06/21/18

From committee: Do pass and re-refer to Com. on G.O. (Ayes 8. Noes 2.) (June 20). Re-referred to Com. on G.O.

Date of Hearing: June 20, 2018

ASSEMBLY COMMITTEE ON UTILITIES AND ENERGY

Chris Holden, Chair

SB 1088 (Dodd) – As Amended June 12, 2018

SENATE VOTE: 34-2

SUBJECT: Safety, reliability, and resiliency planning: general rate case cycle

SUMMARY: This bill requires each electrical corporation or gas corporation (IOU), to submit a safety, reliability, and resiliency plan to the California Public Utilities Commission (CPUC) every two years, requires the CPUC to approve the submitted plan within 18 months and authorize recovery of the costs of implementing the plan through rates. Additionally, this bill prohibits an electrical IOU from delegating, transferring, or contracting out any of its distribution safety or reliability performance obligations. This bill also requires the Office of Emergency Services (OES) to adopt standards for reducing risks from a major event and requires the office to update the standards at least once every two years. Specifically, this bill:

• Requires OES, on or before September 30, 2019, and every two years thereafter, in consultation with the Department of Forestry and Fire Protection (CAL FIRE), the CPUC, and other appropriate state and local agencies, to adopt or update standards for reducing risk from a major event.
• Establishes the Utility Infrastructure, Safety, Reliability, and Accountability Act which requires each IOU to submit an application to the CPUC by July 2019 to establish a safety, reliability, and resiliency plan (plan) for the distribution system to address fire risks. Starting in 2021, the IOU would file a plan every two years to address routine operations and all major events and every two years thereafter. The plan must include:

• Sufficient information for the public and the CPUC to determine the costs and benefits to ratepayers of the investments proposed;
• All rules, regulations, standards, and practices required by the CPUC and OES with a corresponding program of compliance. and a program to comply with all rules and to manage compliance;
• Wildfire mitigation plan including protocols for disabling re-closers and de-energizing portions of the electrical distribution system that consider the impacts on public safety;
• 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 and not vulnerable to widespread failure during a major event;
• Plans for vegetation management;

• For gas IOUs, a preemptive pipe replacement program to locate, mark and repair leaks, relight pilot lights, and all other activity needed to restore service following a major event;
• For electrical IOUs, 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;
• Disaster and emergency preparedness plans required under current law to also include plants for service restoration and community outreach and public awareness before, during and after a major event;
• Plans for distribution grid operation during a major event, including an incident command system;
• Clear evidence that the utility has an adequately sized and trained workforce;
• 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; and
• Forecasted costs of every element of the plan;

• Requires the CPUC to review and approve the plans of all IOUs in a single consolidated proceeding to be concluded no later than 18 months after filing, accept comment from the public, ensure that cost impacts are just and reasonable, verify compliance with all applicable laws, and authorize recovery of reasonable revenue requirements,
• Requires the IOUs to establish a memorandum account to track the costs of the plan and requires the CPUC to disallow recovery of those costs the commission deems unreasonable.
• Permits the CPUC to extend general rate cases (GRCs) to a four-year cycle from three-year cycles;
• Prohibits an electric IOU from delegating, transferring, or contracting out any “distribution system safety or reliability performance obligation”:

a. Which is defined as including, but is 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;

• But excludes line clearance tree trimming under the supervision of an electric IOU, the purchase of materials or equipment, contracting for construction of infrastructure owned by the electrical IOU, 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; and
• And permits the electric IOU to contract with the owner or operators of

distributed energy resources so long as the owner or operator meets the insurance requirements set by the CPUC to cover direct damages caused by the failure of the resource.

• Requires the CPUC to conduct an annual proceeding starting in 2021 to review IOU compliance with the plans.
• Beginning in 2021, the CPUC shall establish a list of independent evaluators from which the IOUs shall choose to review and assess the IOU’s compliance with its plan and determine whether any revenue authorized to implement the plan was diverted to other purposes.
• Requires the CPUC to assess penalties if a utility fails to substantially comply with its plan and requires the CPUC to consider specific factors.
• If the CPUC finds that the IOU is in substantial compliance with its plan, the CPUC shall find that the IOU’s performance, operations, management, and investments addressed in the plan are reasonable and prudent for purposes of any subsequent commission proceeding.
• Requires, as part of an IOUs general rate case, written notice to customers of the plan, with the regular bill for charges, for the two billing cycles before it submits the plan.
• Requires the CPUC to 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.

EXISTING LAW:

• Requires the CPUC to develop formal procedures to incorporate safety in a rate case application by an electrical corporation or gas corporations. (Public Utilities Code § 750)
• Authorizes the CPUC, after a hearing, to require every public utility to construct, maintain, and operate its line, plant, system, equipment, apparatus, tracks, and premises

in a manner so as to promote and safeguard the health and safety of its employees, passengers, customers, and the public. (Public Utilities Code § 768)

• Requires the CPUC to establish standards for disaster and emergency preparedness plans, as specified, and requires an electrical corporation to develop, adopt, and update an emergency and disaster preparedness plan, as specified. (Public Utilities Code § 768.6)
• Requires each electrical corporation to annually prepare and submit a wildfire mitigation plan for the next compliance period to the CPUC for review, and requires specified elements to be included in the plans. (Public Utilities Code § 8386)
• Establishes the California Emergency Services Act, among other things, establishes the Office of Emergency Services (OES) for the purpose of mitigating the effects of natural, man-made, or war-caused emergencies and makes findings and declarations relating to ensuring that preparation within the state will be adequate to deal with those emergencies. (Government Code § 8550, et seq.)
• Sets for rules for the design, construction, operation, and maintenance of overhead utility facilities such as power lines, communications lines, utility poles, and pole-mounted antennas. (CPUC General Order 95)
• Prescribes inspection cycles for electric IOU distribution facilities. (CPUC General Order 165)
• Requires that every electric IOU annually prepare and submit a plan that sets forth the utility’s anticipated responses to emergencies and major outages. (CPUC General Order 166)

FISCAL EFFECT: According to the Senate Appropriations Committee:

• The CPUC indicates that it would incur ongoing costs of $2.5 million to $3.5 million (ratepayer funds) to create, adopt, and update standards for reducing risk from fire danger, as well as review and evaluate safety, reliability, and resiliency plans filed by the utilities. These proceedings have the potential to be lengthy and require staff with specific expertise.
• The OES would require up to $500,000 (General Fund) and two new positions to draft initial standards, and at least half a position ongoing to update the standards every two years. OES also indicates that the expertise required for this workload may difficult to find, requiring it to contract out instead.
• A new High Fire-Threat District (“HFTD”) is added to General Order 95 (“GO 95”). 1 The HFTD consists of three areas:
• Amendments to GO 95, Rule 18, to require utilities to (i) prioritize correction of safety hazards based, in part, on whether the safety hazard is located in the HFTD; (ii) correct within six months a Priority Level 2 fire risk that is located in Tier 3 of the HFTD; and (iii) correct within 12 months a Priority Level 2 fire risk that is located in Tier 2 of the HFTD.
• Amendments to GO 95, Rule 35, Table 1, to require utilities to maintain the stricter Case 14 vegetation clearances in the HFTD.
• Amendments to GO 95, Rule 38, to increase the effective minimum clearance between wires for new and reconstructed facilities in Tier 3 of the HFTD.
• Amendments to GO 95, Rule 80.1-A, to require minimum patrol and detailed inspection cycles for overhead communication lines in Tier 2 and Tier 3 of the HFTD. Inspections must be conducted twice as often in Tier 3 compared to Tier 2.
• Amendments to GO 95, Rule 80.1-B, to require a minimum intrusive inspection cycle for overhead communication lines in Tier 3 of the HFTD.
• Amendments to GO 95, Appendix E, to increase the recommended time-of-trim clearances between power lines and vegetation in the HFTD.
• Amendments to GO 165, Table 1, to require annual patrol inspections of overhead electric utility distribution facilities in rural Tier 2 and Tier 3 areas of the HFTD.
• Amendments to GO 166, Standard 1, Part E, to require every electric investor-owned utility (“Electric IOU”) with overhead power lines in the HFTD to prepare a fire-prevention plan.
• Amendments to Electric Tariff Rule 11 to allow Electric IOUs to disconnect electric service to a customer in the HFTD when:
• Required by this bill – a new “Safety, Reliability, and Resiliency Plan” submitted by an IOUs in July 2019. The plans are then consolidated into one proceeding for review and public comment. Much of the detail required by the plans is now managed through other proceedings and the IOU general rate cases (GRCs). The theory appears to be that the work is buried in GRCs that are not sufficiently transparent. The CPUC is mandated to manage and approve costs through this proceeding rather than the GRC requiring the commission to determine whether costs are just and reasonable. Greater standards of evidence and participation are triggered in GRC proceedings than would be required of the plan review. The CPUC is required to “strive to finish” the plan review in 12 months but must finish in 18 months. The Commission is then required to conduct an annual proceeding to determine each IOU’s compliance with its plan and including a factual analysis of any “major events” which is not defined.
• Safety Planning – Emergency Response Plans & Wildfire Mitigation Plans
• Identifying Risk – Safety Modeling Assessment Proceeding (S-MAP)
• Prioritizing Risk – Risk Assessment Mitigation Phase (RAMP)
• Investing to Mitigate Risk – General Rate Cases
• De-energizing Lines– This bill requires the new plan to include “protocols for disabling reclosers and de-energizing 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.” Senate Bill 901 (Dodd) requires an existing mandate for “wildfire mitigation plans” to include factors the IOU uses to determine when it may be necessary to deenergize its electrical lines and deactivate its reclosers, and procedures for notifying customers. Moreover the CPUC has a resolution scheduled for adoption in July that “extends the de-energization reasonableness, public notification, mitigation and reporting requirements” of a prior decision to all IOUs and “adds new requirements.” This critical issue is now addressed in three different directives which may interfere with efficacy of the acts.
• General Order 95 and other Fire Safety Regulations – In a December 2017 the CPUC updated line inspection and vegetation management requirements as well as adopting statewide fire maps against which levels of risk are considered.
• System Control – With limited exceptions, this bill prohibits an IOU from delegating, transferring, or contracting out any distribution system safety or reliability performance obligation. The safety implications of this section are not clear. One of the most obvious impacts is that it appears to preclude a utility, in emergencies, from utilizing personnel from other utilities across the state and nation through established mutual aid agreements which are critical in addressing system outages after storms and disasters.
• Microgrids – The bill requires the IOUs to have a program to incorporate distributed energy resources and microgrids that can be islanded from the distribution grid for critical customers, 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.” The concept appears to go beyond what is necessary for critical safety needs. Microgrids typically still utilize distribution lines within the “island.” As noted by the CPUC’s pending resolution, back-up generation is the critical need to address safety at times of an outage. The concept of microgrids, sound good but the concept still being developed, piloted, and is very expensive.

BACKGROUND:

2007/2017 Wildfires – The 2017 California wildfire season was the most destructive wildfire season on record, and saw multiple wildfires burning across California, including five of the 20 most destructive wildland/urban interface fires in the state's history. Devastating fires raged in Santa Rosa, Los Angeles, and Ventura, and the Thomas Fire proved to be the largest wildfire in

California history. These fires further demonstrated the fire risk in California. As a result of the fires and critical fire weather conditions, both the President of the United States and the

Governor of California issued State of Emergency declarations.

Beginning on October 21, 2007, a fire storm ripped through portions of Southern California. This fire storm, which was comprised of more than a dozen fires, spread over portions of Orange, San Diego, Los Angeles, San Bernardino, Ventura, Santa Barbara, and Riverside counties. The total area burned by these five power-line fires exceeded 334 square miles and caused extensive damage to properties in the region, widespread evacuations, and fatalities. Investigative reports issued in the aftermath of the 2007 wildfires by the California Department of Forestry and Fire Protection (Cal Fire) and the CPUC’s Consumer Protection and Safety Division (CPSD) (now the Safety and Enforcement Division), attributed the ignition of three of these wildfires to San Diego Gas & Electric Company (SDG&E) facilities.

Fire-Safety Regulations – The 2007 Southern California wildfires triggered a several year effort to address fire prevention. Most recently the CPUC focused on the development and adoption of a statewide fire-threat map and also the identification, evaluation, and adoption of fire-safety regulations. Work on this phase was completed in December 2017. The most significant regulations adopted by this Decision were:

• Zone 1 consists of Tier 1 High Hazard Zones (“HHZs”) on the map of Tree Mortality HHZs prepared jointly by the United States Forest Service and the California Department of Forestry and Fire Protection (“CAL FIRE”). Tier 1 HHZs are in direct proximity to communities, roads, and utility lines, and represent a direct threat to public safety.
• Tier 2 consists of areas on the California Public Utilities Commission’s Fire-Threat Map (“CPUC Fire-Threat Map”) where there is an elevated risk for destructive utility-associated wildfires. The CPUC Fire-Threat Map is currently in an advanced stage of development.
• Tier 3 consists of areas on the CPUC Fire-Threat Map where there is an extreme risk for destructive utility-associated wildfires.

• There is a breach of the minimum vegetation clearances required by California Public Resources Code §§ 4292 and 4293 for State Responsibility Areas.
• The Electric IOU has obtained from an arborist a written determination that a dead, rotten, diseased, leaning, or overhanging tree (or parts thereof) poses an imminent or immediate risk for falling onto a power line.
• The CPUC develops and provides guidance, as prescribed in statute, to the electric IOUs to develop Emergency Response Plans and Wildfire Mitigation Plans. The CPUC also approves these plans and ensures compliance with guidance and statute.
• The electric IOUs are tasked with developing Emergency Response Plans and Wildfire Mitigation Plans consistent with CPUC guidance and statute. These plans outline, describe and summarize electric IOU responsibilities, actions and resources to respond to emergencies and mitigate wildfires.
• The CPUC conducts/oversees the S-MAP, with stakeholders, to develop, update and approve a methodology used by the electric IOUs to identify and assess risk to their electric infrastructure.
• The electric IOUs participate in the S-MAP and then utilize the approved methodology to identify and assess risk to their electric infrastructure.
• Based on the S-MAP approved methodology, the CPUC provides
• The electric IOUs develop RAMP filings, which prioritize the risks electric IOU infrastructure is exposed too and propose measures to mitigate these risks based on the S-MAP approved methodology.
• The CPUC provides recommendations within each electric IOU GRC proceeding (overarching proceeding that examines all electric IOU expenses and established electric rates) regarding which mitigation measures each IOU should invest ratepayer monies towards based on their RAMP filings. The CPUC, through a GRC proceeding, and with stakeholder input, determines and approves the risk mitigation measures

COMMENTS:

• Author’s Statement. Investment in reducing the risk of wildfires has a proven cost savings of at least 3:1, but the CPUC has not established adequate standards to reduce the risk of wildfires caused by utility equipment and to make electric and gas utility equipment more resilient and resistant to damage from major events. This bill would require the Office of Emergency Services, along with other agencies, to establish standards for utilities to protect against damage from natural disasters. IOUs will file safety, reliability and resilience plans with the CPUC which provide for hardening the utility infrastructure. The plans would include all costs to implement the safety, reliability and resilience measures. The CPUC would review, modify and approve the plans, including the costs to implement the plans. Establishing a stand-alone rulemaking would require Investor Owned Utilities and the CPUC to give greater attention and care to safety and reliability, and the bill would establish strong accountability requirements.
• Broader Discussion Needed. The issue of safety and electricity is critical and of statewide import. Thus far, however, the consideration of whether the safety planning requirements in this bill are the right standard, in the right venues, with the right priorities has been limited. The regulating agencies have yet to comment and engage on the good work that the author intends as a result of this bill. But the committee has deadlines and the bill must move given the import of the subject. There are threshold issues raised by the bill which are highlighted below and warrant immediate and detailed discussion with the regulating agencies, the Legislature, and the Governor.
• Layered Filings. The IOUs are currently required to make several safety filings and proceedings are underway. More paper and more proceedings do not necessarily equate to improved safety. It is not clear whether the mandates of this bill duplicate,

complement, conflict, or complicate the CPUC’s work and what gaps, if any, are addressed by this bill.

Existing Safety Frameworks:

guidance, reviews, modifies and approves the RAMP filings of the electric IOUs that prioritizes risks electric IOUs infrastructure are exposed too, and the measures they plan to implement to mitigate these prioritized risks.

that should be recovered by ratepayers, balancing electric service safety, reliability and affordability.

o The electric IOUs participate in their GRC proceedings and are required to justify all of their expenses including those expenses related to risk mitigation measures.

4) Distribution Grid Impacts.

• Circumventing General Rate Cases. Many of those opposed to the bill take issue with the attempt by this bill to circumvent the GRC proceeding into a separate proceeding that does not encompass the evidentiary record requirements of GRCs, thereby limiting the ability of parties to thoroughly review the plans. Moreover, those opposed raise concerns about the feasibility of such all-encompassing plans to be reviewed in one proceeding under a year’s time, when GRCs generally take 18 months to two years for each utility. Additionally, many of those opposed believe the end result will be a blank check to benefit utilities and their shareholders at the expense of ratepayers, without the outcome of improved safety. Some of the opposition contends that the new all-encompassing proceeding with a limited under a year timeline will allow utilities to game the process by not providing full and detailed information.
• Ratepayer Vulnerability? The critical provision of this bill, with unknown ratepayer impact, is added Public Utilities Code Section 2899.6 (a) at page 15, lines 11-20. This provision relaxes the standard of review by the CPUC to consider whether a utility’s liability costs should be recovered from ratepayers. This bill would supplant the CPUC’s current review to determine whether a utility acted reasonably, or as a prudent manager, after a fire, for instance, has occurred. Instead the CPUC would base its decision on whether the utility was in “substantial compliance” with its filed and approved safety, reliability, and resiliency plan as established by this bill. The annual review and approval of IOU safety plans would act as a substitute of whether the IOU was prudent in its management. It does not appear that the on-the-ground actions of a utility would be relevant.

There is concern that this section could allow extensive liability costs under inverse condemnation to be passed on to ratepayers. There may be a need to stabilize the utilities and to assist with socializing the costs of extreme events. However, this bill appears to allow extensive costs to be borne by ratepayers with no safety net for those impacts. If the State is in the “new normal” and the IOUs continue to face extreme costs as a result tragic events, the ratepayers of any one IOU may not be able to withstand the costs.

The committee may wish to consider striking this section from the bill at this time.

• Double Referral. Should this bill be approved by this committee, it will be re-referred to the Assembly Governmental Organization.
• Related Legislation.

SB 819 (Hill, 2017) would prohibit an electrical corporation from recovering a fine or penalty through a rate approved by the CPUC. This bill would also prohibit an electrical corporation or gas corporation from recovering through a rate approved by the CPUC an uninsured expense from damages caused by the utility’s electric facilities or gas facilities, if the CPUC determines that the electrical corporation did not reasonably construct, maintain, manage, control, or operate the facility. Status: Set for hearing in Assembly Utilities & Energy Committee, January 20, 2018.

SB 901 (Dodd, 2017) would require a wildfire mitigation plan prepared by an electrical corporation, and wildfire mitigation measures prepared by a local publicly owned electric utility or electrical cooperative, to include protocols the utility or cooperative may use to determine when it may be necessary to deenergize its electrical lines and deactivate its reclosers. The bill is scheduled to be heard by this committee at this hearing. Set for hearing in Assembly Utilities & Energy

Committee, January 20, 2018.

10) Prior Legislation.

SB 549 (Bradford, Chapter 284, Statutes of 2016) requires an electrical or gas corporation to annually notify the CPUC of each time that capital or expense revenue authorized by the CPUC for maintenance, safety, or reliability was redirected by the electrical or gas corporation to other purposes.

SB 900 (Hill, Chapter 552, Statutes of 2014) requires the CPUC to develop formal procedures, as specified, to consider safety in a rate case application by an electrical corporation or gas corporation.

AB 56 (Hill, Chapter 519, Statutes of 2011) required the CPUC, in any ratemaking proceeding in which the CPUC authorizes a gas corporation to recover expenses for a federal transmission pipeline integrity management program, or for related capital expenditures for the maintenance and repair of transmission pipelines, to require the gas corporation to establish and maintain a balancing account for the recovery of those expenses.

SB 879 (Padilla, Chapter 523, Statutes of 2011) among its provisions, included the same provision related to maintaining a balancing account for gas pipeline safety maintenance and repair as in AB 56.

REGISTERED SUPPORT / OPPOSITION: Support

California State Association of Electrical Workers (Co-Sponsor)

Coalition of California Utility Employees (Co-Sponsor)

California Building Industry Association

California Labor Federation, AFL-CIO

California State Association of Counties

California State Pipe Trades Council

Napa County Legislative Subcommittee

Pacific Gas And Electric Company

San Diego Gas And Electric Company

Santa Barbara County Board of Supervisors

Sierra Business Council

Sonoma County Board of Supervisors

Southern California Edison

State Building And Construction Trades Council

The Engineers and Scientists of California

Opposition

Agricultural Energy Consumers Association

American Pistachio Growers

Asian Pacific Environmental Network

California Cotton Ginners and Growers Association Inc.

California Environmental Justice Alliance

California Farm Bureau Federation

California Fresh Fruit Association

California Large Energy Consumers Association

California League of Food Producers

California Manufacturers & Technology Association

California Natural Gas Producers Association

California Retailers Association

Center for Community Action & Environmental Justice

Central Coast Alliance United For A Sustainable Economy

Communities For A Better Environment

Consumer Federation of California

Far West Equipment Dealers Association

Greenlining Institute; The

Office of Ratepayer Advocates

People Organizing To Demand Environmental & Economic Rights

Physicians For Social Responsibility, Los Angeles

Sonoma Clean Power

The Utility Reform Network

Western Agricultural Processors Association

Western Growers Association

Western States Petroleum Association

Oppose As Amended

Frontier Communications Corporation Southern California Edison

Oppose Unless Amended

California Community Choice Association Sonoma Clean Power

THE BILL - AMENDED IN ASSEMBLY JUNE 12, 2018

AMENDED IN SENATE MAY 25, 2018

AMENDED IN SENATE MAY 2, 2018

AMENDED IN SENATE APRIL 9, 2018

AMENDED IN SENATE MARCH 15, 2018

SENATE BILL No. 1088

Introduced by Senator Dodd

February 12, 2018

An act to add Section 8587.13 to the Government Code, and to amend Section 454 of, and to add Chapter 11 (commencing with Section 2899) to Part 2 of Division 1 of, the Public Utilities Code, relating to disaster preparedness. public utilities.

LEGISLATIVE COUNSEL’S DIGEST

SB 1088, as amended, Dodd. Safety, reliability, and resiliency planning. planning: general rate case cycle.

Under existing law, the Public Utilities Commission has regulatory authority over public utilities, including electrical corporations and gas corporations. Existing law authorizes the commission, after a hearing, to require every public utility to construct, maintain, and operate its line, plant, system, equipment, apparatus, tracks, and premises in a manner so as to promote and safeguard the health and safety of its employees, passengers, customers, and the public. Existing law requires electrical corporations to annually prepare and submit a wildfire mitigation plan to the commission for review. Existing law requires the commission to establish standards for disaster and emergency preparedness plans, as specified, and requires an electrical corporation

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to develop, adopt, and update an emergency and disaster preparedness plan, as specified.

The California Emergency Services Act, among other things, establishes the Office of Emergency Services for the purpose of mitigating the effects of natural, manmade, or war-caused emergencies and makes findings and declarations relating to ensuring that preparation within the state will be adequate to deal with those emergencies.

This bill would require the office, in consultation with specified public entities, by September 30, 2019, to adopt standards for reducing risks from a major event, as defined. The bill would require those standards to include model policies that may be undertaken by local governments regarding, among other things, defensible space, and actions that may be undertaken by an electrical or gas corporation, a local publicly owned electric or gas utility, or a water utility to reduce the risk of fire occurring during a major event. The bill would require the office to update the standards at least once every 2 years.

This bill would require an electrical or gas corporation, on or before July 1, 2019, and every July 1 every two years thereafter, to submit to the commission an application for review and approval of a safety, reliability, and resiliency plan that includes certain elements. The bill would require the commission, no more than 18 months after the submission of the plan, to approve the plan with or without modification. The bill would require the commission to authorize recovery of the costs of implementing the plan through rates, as provided. The bill would require the commission to conduct an annual proceeding to review each electrical corporation’s and gas corporation’s compliance with its plan, as provided. If, after completing the compliance review, the commission determines that an electrical corporation or gas corporation is in substantial compliance with its plan, the bill would authorize the commission to find the performance, operations, management, and investment addressed in the plan to be reasonable and prudent, as specified. The bill would require the commission to assess a penalty on an electrical corporation or gas corporation for noncompliance with its plan. The bill would, except as provided, prohibit an electrical corporation from delegating, transferring, or contracting out any of its distribution system safety or reliability performance obligations, except as specified.

Existing law authorizes the commission to fix the rates and charges for public utilities, including electrical or gas corporations, and requires the rates and charges to be just and reasonable. Under its existing

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regulatory authority, the commission uses a general rate case to address the costs of operating and maintaining the systems of public utilities and the allocation of those cost among the public utilities’ customer classes. The commission has used a 3-year general rate case cycle, in which electrical or gas corporations file a general rate case application with the commission every 36 months.

This bill would explicitly authorize the commission to extend the general rate case cycle to 4 years.

Vote: majority. Appropriation: no. Fiscal committee: yes. State-mandated local program: no.

The people of the State of California do enact as follows:

1 SECTION 1. The Legislature finds and declares as follows:

2 (a) The effects of climate change are happening now and will

3 continue to increase both around the world and in California.

4 (b) There will be more frequent and increasingly severe storms,

5 floods, mudslides, and wildfires.

6 (c) Eight of the 20 most destructive fires in California’s history

7 have occurred since 2015, with five occurring in 2017 alone.

8 (d) Greenhouse gas emissions from wildfires undermine

9 California’s plans to reduce emissions. The emissions from the

10 2017 wildfires were estimated to be nearly as much as the total

11 2017 emissions from electric generation.

12 (e) The electric and gas transmission and distribution systems

13 can be the cause of fires, which, because of climate change, can

14 be much more severe.

15 (f) Catastrophic storms, floods, mudslides, fires, earthquakes,

16 and other major events cause loss of life, tremendous property

17 damage, public health impacts, environmental degradation, and

18 damage to local economies. These events can also adversely impact

19 electrical and gas transmission and distribution systems.

20 (g) California is overdue for a major earthquake.

21 (h) Natural disasters can cause vast economic damage. The

22 North Bay and Southern California suffered major economic

23 impacts to businesses and many jobs were lost as a result of the

24 2017 wildfires.

25 (i) Failure to prepare for the effects of climate change would

26 adversely affect the credit rating of California and local

27 jurisdictions.

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1 (j) Executive Order B-30-15 addresses the need for climate

2 adaptation by incorporating climate change impacts into the state’s

3 Five-Year Infrastructure Plan, updating the state’s climate

4 adaptation strategy by identifying how climate change will affect

5 infrastructure and industry and what actions can be taken to reduce

6 the risks posed by climate change, factoring climate change into

7 state agencies’ planning and investment decisions, and

8 implementing measures under existing agency and departmental

9 authority to reduce greenhouse gas emissions.

10 (k) Chapter 608 of the Statutes of 2015 requires that cities and

11 counties address climate adaptation and resilience strategies in

12 local planning.

13 (1) Chapter 606 of the Statutes of 2015 establishes the Integrated

14 Climate Adaptation and Resiliency Program to be administered

15 by the Office of Planning and Research to coordinate regional and

16 local efforts with state climate adaptation strategies to adapt to the

17 impacts of climate change.

18 (m) Chapter 603 of the Statutes of 2015 requires the Natural

19 Resources Agency to update the state’s climate adaptation strategy

20 every three years to address vulnerabilities to climate change by

21 sector, including the energy sector, and requires state agencies to

22 maximize promoting the use of the climate adaptation strategy to

23 inform planning decisions and ensure that state investments

24 consider climate change impacts.

25 (n) Chapter 580 of the Statutes of 2016 requires state agencies

26 to take into account the impacts of climate change when planning,

27 designing, building, operating, maintaining, and investing in state

28 infrastructure.

29 (o) Preventing or mitigating property and infrastructure damage

30 and injury from catastrophic storms, floods, mudslides, fires,

31 earthquakes, and other major events is much safer, better for local

32 economies, and far less expensive than emergency repair and

33 reconstruction.

34 (p) Responding to catastrophic storms, floods, mudslides, fires,

35 earthquakes, and other major events requires a substantial,

36 well-trained local utility workforce. After the 2017 North Bay

37 wildfires, the Pacific Gas and Electric Company utilized 4,300

38 employees to quickly repair and restore utility service to its

39 customers. The Public Utilities Commission should require each

40 electrical and gas corporation to have a sufficiently sized and

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1 trained workforce available, including employees of other utilities

2 pursuant to mutual aid agreements and employees of entities that

3 have entered into contracts with utilities, to quickly respond to

4 major events.

5 (q) Investment in reducing the risk of wildfires has a proven

6 cost savings ratio of at least three to one, but the Public Utilities

7 Commission has failed to establish adequate standards to reduce

8 the risk of wildfires caused by utility equipment and to make

9 electrical and gas corporation equipment more resilient and

10 resistant to damage.

11 (r) The Public Utilities Commission should establish fire risk

12 reduction and mitigation standards, including protocols for

13 disabling reclosers and deenergizing lines. All protocols should

14 meet or exceed industry best practices. Disabling reclosers and

15 deenergizing lines can cause impacts to fire and police response,

16 the availability of water, hospitals, schools, evacuation centers,

17 and other critical facilities.

18 (s) Electric and gas reliability is a critical component of public

19 safety.

20 (t) The Public Utilities Commission should require electrical

21 and gas corporations to harden their systems to reduce damage

22 from catastrophic storms, floods, mudslides, fires, earthquakes,

23 and other major events.

24 (u) The Public Utilities Commission should require electrical

25 corporations to evaluate and incorporate technological solutions,

26 including microgrids, so that critical facilities maintain electrical

27 service during and after catastrophic storms, floods, mudslides,

28 fires, earthquakes, and other major events.

29 (v) Electrical corporations should be allowed to contract with

30 providers of distributed energy resources so long as the providers

31 meet insurance requirements set by the Public Utilities Commission

32 for direct damages caused by the failure of distributed energy

33 resources equipment.

34 (w) Electrical corporations and gas corporations should file with

35 the Public Utilities Commission safety, reliability, and resiliency

36 plans, which should address all relevant rules, regulations,

37 standards, and practices to prevent and mitigate risk from

38 catastrophic storms, floods, mudslides, fires, earthquakes, and

39 other major events that affect the safety and reliability of the

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1 electrical and gas system. Safety and reliability should be the

2 highest priority in all commission decisions.

3 (x) The Public Utilities Commission should impose penalties

4 on an electrical corporation or gas corporation that fails to comply

5 with an approved plan. The amount of the penalty should be

6 correlated with the nature and severity of the failure to comply

7 with the approved plan. Any penalties should be paid exclusively

8 by shareholders of the electrical corporation or gas corporation.

9 (y) The Office of the Safety Advocate should participate in all

10 proceedings authorized by Chapter 11 (commencing with Section

11 2899) of Part 2 of Division 1 of the Public Utilities Code.

12 (z) Electrical corporations and gas corporations should notify

13 their customers, including local governments and agencies, of

14 proceedings authorized by the Utility Infrastructure, Safety,

15 Reliability, and Accountability Act (Chapter 11 (commencing with

16 Section 2899) of Part 2 of Division 1 of the Public Utilities Code).

17 (aa) The commission should encourage public comment at

18 hearings for proceedings authorized by the Utility Infrastructure,

19 Safety, Reliability, and Accountability Act (Chapter 11

20 (commencing with Section 2899) of Part 2 of Division 1 of the

21 Public Utilities Code).

22 (ab) Consistent with its ratepayer protection duties pursuant to

23 Article 1 (commencing with Section 451) of Chapter 3 of Part 1

24 of Division 1 of the Public Utilities Code, the commission should

25 ensure the costs associated with the implementation of Chapter 11

26 (commencing with Section 2899) of Part 2 of Division 1 of the

27 Public Utilities Code are just and reasonable for ratepayers while

28 protecting public safety and the reliability of electric and gas

29 services.

30 SEC. 2. Section 8587.13 is added to the Government Code, to

31 read:

32 8587.13. (a) For purposes of this section, “major event” means

33 a large storm, flood, mudslide, fire, earthquake, or other occurrence

34 that significantly affects the safety and reliability of the electrical

35 or gas distribution system.

36 (b) On or before September 30, 2019, and on or before

37 September 30 of every 2 years thereafter, the office, in consultation

38 with the Department of Forestry and Fire Protection, the Public

39 Utilities Commission, and other appropriate state and local

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1 agencies, shall adopt or update standards for reducing risk from a

2 major event.

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

4 (1) Model policies that may be undertaken by local governments

5 regarding zoning, defensible space, fire-resistant building materials,

6 and other measures applicable to properties at risk during a major

7 event.

8 (2) Actions that may be undertaken by electrical corporations,

9 gas corporations, local publicly owned electric utilities, local

10 publicly owned gas utilities, and water utilities to reduce the risk

11 of fire during a major event.

12 SEC. 3. Section 454 of the Public Utilities Code is amended

13 to read:

14 454. (a) (1) Except as provided in Section 455, a public utility

15 shall not change any rate or so alter any classification, contract,

16 practice, or rule as to result in any new rate, except upon a showing

17 before the commission and a finding by the commission that the

18 new rate is justified. Whenever any electrical, gas, heat, telephone,

19 water, or sewer system corporation files an application to change

20 any rate, other than a change reflecting and passing through to

21 customers only new costs to the corporation that do not result in

22 changes in revenue allocation, for the services or commodities

23 furnished by it, the corporation shall furnish to its customers

24 affected by the proposed rate change notice of its application to

25 the commission for approval of the new rate. This notice

26 requirement does not apply to any rate change proposed by a

27 corporation pursuant to an advice letter submitted to the

28 commission in accordance with commission procedures for this

29 means of submission. The procedures for advice letters may include

30 provision for notice to customers or subscribers on a case-by-case

31 basis, as determined by the commission. The corporation may

32 include the notice with the regular bill for charges transmitted to

33 the customers within 45 days if the corporation operates on a

34 30-day billing cycle, or within 75 days if the corporation operates

35 on a 60-day billing cycle. If more than one application to change

36 any rate is filed within a single billing cycle, the corporation may

37 combine the notices into a single notice if the applications are

38 separately identified. The notice shall state the amount of the

39 proposed rate change expressed in both dollar and percentage terms

40 for the entire rate change as well as for each customer

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SB 1088 — 8 —

1 classification, a brief statement of the reasons the change is required

2 or sought, and the mailing and, if available, email address of the

3 commission to which any customer inquiries may be directed

4 regarding how to participate in, or receive further notices regarding

5 the date, time, or place of, any hearing on the application, and the

6 mailing address of the corporation to which any customer inquiries

7 relative to the proposed rate change may be directed.

8 (2) For a safety, reliability, and resiliency plan submitted by an

9 electrical or gas corporation pursuant to Section 2899.2, the

10 corporation shall furnish to its customers written notice with the

11 regular bill for charges for the two billing cycles before it submits

12 the plan. The written notice shall include a link to the Internet Web

13 site where the plan will be available electronically upon its

14 submission.

15 (b) For a water corporation with more than 2,000 service

16 connections, the notice required in subdivision (a) shall include

17 estimated rate impacts on the various customer classes of the

18 corporation. The commission may require the corporation to inform

19 customers in a separate letter or through a bill insert, at the

20 corporation’s discretion, of the outcome of the general rate case,

21 within 60 days if the corporation operates on a 30-day billing cycle,

22 or within 90 days if the corporation operates on a 60-day billing

23 cycle, of the commission’s final decision, including the approved

24 rates and the approved capital projects that will subsequently be

25 executed by way of an advice letter.

26 (c) The commission may adopt rules it considers reasonable

27 and proper for each class of public utility providing for the nature

28 of the showing required to be made in support of proposed rate

29 changes, the form and manner of the presentation of the showing,

30 with or without a hearing, and the procedure to be followed in the

31 consideration thereof. Rules applicable to common carriers may

32 provide for the publication and filing of any proposed rate change

33 together with a written showing in support thereof, giving notice

34 of the filing and showing in support thereof to the public, granting

35 an opportunity for protests thereto, and to the consideration of,

36 and action on, the showing and any protests filed thereto by the

37 commission, with or without hearing. However, the proposed rate

38 change does not become effective until it has been approved by

39 the commission.

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1 (d) (1) The commission shall permit individual public utility

2 customers and subscribers affected by a proposed rate change, and

3 organizations formed to represent their interests, to testify at any

4 hearing on the proposed rate change, except that the presiding

5 officer need not allow repetitive or irrelevant testimony and may

6 conduct the hearing in an efficient manner.

7 (2) The commission shall permit any member of the public to

8 testify at any hearing or proceeding authorized under the Utility

9 Infrastructure, Safety, Reliability, and Accountability Act (Chapter

10 11 (commencing with Section 2899) of Part 2), except that the

11 presiding officer need not allow repetitive or irrelevant testimony

12 and may conduct the hearing in an efficient manner.

13 SEC. 4. Chapter 11 (commencing with Section 2899) is added

14 to Part 2 of Division 1 of the Public Utilities Code, to read:

15

16 CHAPTER 11. UTILITY INFRASTRUCTURE, SAFETY, RELIABILITY,

17 AND ACCOUNTABILITY

18

19 2899. This chapter shall be known, and may be cited, as the

20 Utility Infrastructure, Safety, Reliability, and Accountability Act.

21 2899.1. For purposes of this chapter, the following definitions

22 apply:

23 (a) “Distribution system” means the portion of the electric

24 system beginning with equipment that operates at voltages lower

25 than that controlled by the Independent System Operator up to and

26 including the customer’s meter, and that is used to transmit, deliver,

27 store, or furnish electricity, light, heat, or power.

28 (b) “Major event” means a large storm, flood, mudslide, fire,

29 earthquake, or other occurrence that significantly affects the safety

30 and reliability of the electrical or gas distribution system.

31 (c) “Plan” means the safety, reliability, and resiliency plan filed

32 by an electrical or gas corporation pursuant to Section 2899.2,

33 including measures addressing both routine operations and major

34 events.

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

36 2899.2. (a) On or before_ January 15, July 1, 2019, and on or

37 before January 15 July 1 every two years thereafter, each utility

38 shall prepare and submit to the commission an application for

39 review and approval of a safety, reliability, and resiliency plan.

40 The plan submitted on or before January 15, July 1, 2019, shall be

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SB 1088 — 10 —

1 limited to addressing fire risks, with subsequent plans addressing

2 risks associated with routine operation and all major events. The

3 plan shall include sufficient information for the public and the

4 commission to determine the costs and benefits to ratepayers of

5 the investments proposed in the plan.

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

7 (1) All relevant safety rules, regulations, standards, and practices

8 adopted by the commission and, after January 1, 2021, all

9 applicable standards adopted or updated by the Office of

10 Emergency Services pursuant to Section 8587.13 of the

11 Government Code.

12 (2) A program to comply with applicable safety rules,

13 regulations, standards, and practices adopted by the commission

14 and, after January 1, 2021, a program to comply with standards

15 adopted or updated by the Office of Emergency Services pursuant

16 to Section 8587.13 of the Government Code.

17 (3) A program to manage compliance, including, but not limited

18 to, plans for assigning personnel, training, and monitoring and

19 checking that the personnel have carried out their assignments,

20 and a system of quality assurance and quality control.

21 (4) The wildfire mitigation plan submitted pursuant to Section

22 8386, including protocols for disabling reclosers and deenergizing

23 portions of the electrical distribution system, system that consider

24 the impacts on public safety, as well as protocols related to

25 mitigating the public safety impacts of those protocols. protocols,

26 including impacts to critical first responders, and to health and

27 communication infrastructure.

28 (5) Actions the utility will take to ensure that its system will

29 achieve the highest level of safety, reliability, and resiliency, and

30 to ensure that its system is not vulnerable to widespread failure

31 during prepared for a major event, including hardening and

32 modernizing its infrastructure with improved engineering, system

33 design, standards, equipment, and facilities.

34 (6) Plans for vegetation management.

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

36 (A) A program to preemptively replace pipe and other equipment

37 that is aging, brittle, or otherwise vulnerable to damage from a

38 major event, or that could endanger public or employee safety.

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1 (B) A program to locate, mark and repair leaks, relight pilot

2 lights, and all other activity needed to restore service following a

3 major event.

4 (8) For electrical corporations, a program to evaluate and

5 incorporate technological solutions, such as distributed energy

6 resources and microgrids that can be islanded from the distribution

7 grid for critical customers, customers or critical facilities, such as

8 schools, hospitals, critical care patients, water pumping and

9 treatment facilities, telecommunication infrastructure, and

10 government and other facilities that provide public safety or other

11 critical functions.

12 (9) The disaster and emergency preparedness plan prepared

13 pursuant to Section 768.6, including both of the following:

14 (A) Plans to prepare for, and to restore service after, a major

15 event, including workforce mobilization, and prepositioning

16 equipment and employees.

17 (B) Plans for community outreach and public awareness before,

18 during, and after a major event.

19 (10) Plans for distribution grid operation during a major event,

20 including an incident command system.

21 (11) Clear evidence that the utility has an adequately sized and

22 trained workforce to promptly restore service after a major event,

23 taking into account employees of other utilities pursuant to mutual

24 aid agreements and employees of entities that have entered into

25 contracts with the utility.

26 (12) Activities to support customers during and after a major

27 event, including outage reporting, billing, repair processing and

e 28 timing, access to utility representatives, emergency

29 communications, and restoration plans.

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

31 (14) Any other element pertaining to electric and gas safety,

32 reliability, or resiliency deemed appropriate by the commission.

33 (c) (1) The commission shall review the plans of the utilities

34 in a single consolidated proceeding. The commission shall accept

35 comment on the plans from the public and interested parties and

36 verify that the plans comply with all applicable rules, regulations,

37 and standards, including those adopted by the Office of Emergency

38 Services pursuant to the State Assistance for Fire Equipment Act

39 (Article 5.5 (commencing with Section 8589.8) of Chapter 7 of

40 Division 1 of Title 2 of the Government Code), as appropriate.

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1 The commission shall evaluate the reasonableness of the elements

2 of the plans considering the risks involved and the costs to

3 implement the plan.

4 (2) In reviewing the plans, consistent with its ratepayer

5 protection duties pursuant to Article 1 (commencing with Section

6 451) of Chapter 3 of Part 1, the commission shall ensure that the

7 cost impacts of the plans are just and reasonable for ratepayers

8 while prioritizing protecting public safety and the reliability of

9 electric and gas services.

10 (3) Notwithstanding Section 1701.5, with or without

11 modification, the commission shall strive to approve the plans

12 within 12 months of, but in no case shall approve the plans more

13 than 18 months after, their submission, unless the commission

14 makes a written determination, including reasons supporting the

15 determination, that the 18-month deadline cannot be met, and

16 issues an order extending the deadline. Each utility’s approved

17 plan shall remain in effect until the commission approves the

18 utility’s subsequent plan.

19 (4) (A) Consistent with its ratepayer protection duties pursuant

20 to Article 1 (commencing with Section 451) of Chapter 3 of Part

21 1, the commission shall authorize rate recovery of the reasonable

22 revenue requirements to implement plans approved by the

23 commission in the proceeding reviewing the plans pursuant to

24 paragraph (1).

25 (B) Forecasted__ costs All forecasted costs not included in the

26 plan or deemed outside the scope of the plan by the commission

27 may be requested and considered in a utility’s general rate case or

28 other appropriate proceeding.

29 (5) The utilities shall not divert revenues authorized to

30 implement the plan to any activities or investments outside their

31 plans.

32 (6) Each utility shall establish a memorandum account to track

33 costs incurred for fire risk mitigation from January 1, 2019, until

34 the commission’s approval of the utility’s plan submitted on or

35 before January 15, 2019, that are not otherwise covered in the

36 utility’s revenue requirements. The commission shall review the

37 costs in the memorandum accounts and disallow recovery of those

38 costs the commission deems unreasonable.

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1 (d) On or after January 1, 2019, each utility’s Risk Assessment

2 Mitigation Phase filing shall exclude risks addressed in the plan

3 required pursuant to subdivision (b).

4 (e) The commission may extend the three-year general rate case

5 cycle to a four-year general rate case cycle.

6 2899.3. (a) For purposes of this section, “distribution system

7 safety or reliability performance obligations” of an electrical

8 corporation include, but are not limited to, owning, controlling,

9 operating, managing, maintaining, planning, engineering,

10 designing, investing in, and constructing the distribution system

11 in its service territory, distribution system reliability, emergency

12 response and restoration, vegetation management, service

13 connections, service turnons and turnoffs, and service inquiries

14 relating to the operation of the distribution system.

15 (b) (1) An electrical corporation shall not delegate, transfer, or

16 contract out any distribution system safety or reliability

17 performance obligation.

18 (2) Notwithstanding paragraph (1), an electrical corporation

19 may contract with the owner or operator of a distributed energy

20 resource so long as the owner or operator of the distributed energy

21 resource meets the insurance requirements set by the commission

22 to cover direct damages caused by the failure of the distributed

23 energy resources to comply with the terms of the contract.

24 (c) The prohibition specified in paragraph (1) of subdivision

25 (b) does not apply to line clearance tree trimming under the

26 supervision of the electrical corporation, the purchase of materials

27 or equipment, contracting for construction of infrastructure owned

28 by the electrical corporation, contracting for pole test and treat

29 services, contracting for bulk electricity capacity, energy, or storage

30 that is not for purposes of distribution system safety and reliability,

31 or contracting for information technology services.

32 (d) Paragraph (1) of subdivision (b) does not prohibit a cable

33 television corporation or telephone corporation from contracting

34 for make-ready work or performing work on its equipment attached

35 to poles that also support equipment owned by an electrical

36 corporation.

37 (e) When performing the planning, engineering, and design

38 described in subdivision (a), the electrical corporation shall

39 consider both of the following:

40 (1) The current and future load.

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SB 1088 — 14 —

1 (2) The current and future distributed energy resources owned

2 by the electrical corporation, community choice aggregators, or

3 any other person or entity.

4 2899.4. The commission shall conduct an annual proceeding

5 to review each utility’s compliance with its plan, including a factual

6 analysis of any major events that occurred, as follows:

7 (a) Beginning March 1, 2020, 2021, and each March 1 thereafter,

8 each utility shall file with the commission a report addressing

9 compliance with the plan during the prior calendar year.

10 (b) (1) Prior to March 1, 2020, 2021, and prior to each March

11 1 thereafter, the commission shall make available a list of qualified

12 independent evaluators with experience in assessing electric and

13 gas operations.

14 (2) Each utility shall engage an independent evaluator listed

15 pursuant to paragraph (1) to review and assess the utility’s

16 compliance with its plan. The independent evaluator shall consult

17 with, and operate under the direction of, the Safety and

18 Enforcement Division of the commission. The independent

19 evaluator shall issue a report on July 1 of each year in which a

20 report required by subdivision (a) is filed. As a part of the

21 independent evaluator’s report, the independent evaluator shall

22 determine whether any revenue authorized to implement the plan

23 was diverted to any activities or investments outside the plan. The

24 commission shall strive to complete its compliance review within

25 12 months of, but in no case shall that review be completed more

26 than 18 months after, the submission of a utility’s compliance

27 report.

28 (3) The commission shall authorize the utility to recover in rates

29 the costs of the independent evaluation.

30 (4) The commission shall have exclusive jurisdiction over

31 compliance by a utility with the standards adopted pursuant to

32 Section 8587.13 of the Government Code.

33 2899.5. The commission shall assess penalties if a utility fails

34 to substantially comply with its plan. In determining an appropriate

35 amount of the penalty, the commission shall consider all of the

36 following:

37 (a) The nature and severity of any noncompliance with the plan,

38 including whether the noncompliance resulted in harm.

39 (b) The extent to which the commission has found that the utility

40 complied with its plans in prior years.

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1 (c) Whether the utility self-reported the circumstances

2 constituting noncompliance.

3 (d) Whether the utility implemented corrective actions with

4 respect to the noncompliance.

5 (e) Whether the utility had advance notice of the circumstances

6 constituting noncompliance.

7 (f) Whether the utility had previously engaged in conduct of a

8 similar nature that caused significant property damage or injury.

9 (g) Any other factors established by the commission in a

10 rulemaking proceeding, consistent with purposes of this section.

11 2899.6. (a) After completing the review pursuant to Section

12 2899.4, if, either at the time the plan is reviewed and approved or

13 subsequent to its review and approval, the commission determines

14 that a utility was in substantial compliance with its approved plan,

15 the commission, to the extent the commission finds it is consistent

16 with the ratepayer protection duties established pursuant to Article

17 1 (commencing with Section 451) of Chapter 3 of Part 1, shall find

18 that the utility’s performance, operations, management, and

19 investments addressed in the plan are reasonable and prudent for

20 purposes of any subsequent commission proceeding.

21 (b) Any findings made pursuant to Section 2899.4:

22 (1) Shall be used by the commission to carry out its obligations

23 under Section 451.

24 (2) Shall not apply to performance, operations, management,

25 or investment not addressed or outside the scope of the approved

26 plan.

27 (3) Shall not affect any civil action. Nothing in this paragraph

28 shall impact the admissibility of evidence otherwise permitted by

29 law or rule of court.

30 (4) Shall not apply to events that occurred before the first plan

31 is approved for a particular utility.

O

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