CA Senate Bill 1088 - CPUC - PG&E

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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.

LEGISLATIVE COUNSEL’S DIGEST

SB 1088, as amended, Dodd. Safety, reliability, and resiliency planning.

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

Corrected 5-26-18—See last page. 95

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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 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 require authorize the commission to find the performance, operations, management, and investment addressed in the plan to be

reasonable and_ prudent. 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.

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.

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— 3 — SB 1088

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

2 floods, mudslides, and wildfires.

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

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

5 (d) Greenhouse gas emissions from wildfires undermine

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

7 2017 wildfires were estimated to be nearly as much as the total

8 2017 emissions from electric generation.

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

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

11 be much more severe.

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

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

14 damage, public health impacts, environmental degradation, and

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

16 electrical and gas transmission and distribution systems.

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

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

19 North Bay and Southern California suffered major economic

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

21 2017 wildfires.

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

23 adversely affect the credit rating of California and local

24 jurisdictions.

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

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

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

28 adaptation strategy by identifying how climate change will affect

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

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

31 state agencies’ planning and investment decisions, and

32 implementing measures under existing agency and departmental

33 authority to reduce greenhouse gas emissions.

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

35 counties address climate adaptation and resilience strategies in

36 local planning.

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

38 Climate Adaptation and Resiliency Program to be administered

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

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

2 impacts of climate change.

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

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

5 every three years to address vulnerabilities to climate change by

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

7 maximize promoting the use of the climate adaptation strategy to

8 inform planning decisions and ensure that state investments

9 consider climate change impacts.

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

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

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

13 infrastructure.

14 (o) Preventing or mitigating property and infrastructure damage

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

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

17 economies, and far less expensive than emergency repair and

18 reconstruction.

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

20 earthquakes, and other major events requires a substantial,

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

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

23 employees to quickly repair and restore utility service to its

24 customers. The Public Utilities Commission should require each

25 electrical and gas corporation to have a sufficiently sized and

26 trained workforce available, including employees of other utilities

27 pursuant to mutual aid agreements and employees of entities that

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

29 major events.

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

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

32 Commission has failed to establish adequate standards to reduce

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

34 electrical and gas corporation equipment more resilient and

35 resistant to damage.

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

37 reduction and mitigation standards, including protocols for

38 disabling reclosers and deenergizing lines. All protocols should

39 meet or exceed industry best practices. Disabling reclosers and

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

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— 5 — SB 1088

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

2 and other critical facilities.

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

4 safety.

5 (t) The Public Utilities Commission should require electrical

6 and gas corporations to harden their systems to reduce damage

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

8 and other major events.

9 (u) The Public Utilities Commission should require electrical

10 t lua IJ

corporations o_______ evat, lI U U t, IJp1 at, aii ii

u iaiiiani evaluate

11 and incorporate technological solutions, including microgrids, so

12 that critical facilities maintain electrical service during and after

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

14 other major events.

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

16 providers of distributed energy resources so long as the providers

'7

- r1 Ican ensure t that tthey have t the financial capacit to pay for damages 18 caused by a failure of distributed energy resources equipment,

9 ll tl-.at___ t1-.

1 such as aspreeadingitUIium 1on Dattery IIree, UI puts HIe safety

20___________________________________________________ and property of members of the public at risk. meet insurance

21 requirements set by the Public Utilities Commission for direct

22 damages caused by the failure of distributed energy resources

23 equipment.

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

25 the Public Utilities Commission safety, reliability, and resiliency

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

27 standards, and practices to prevent and mitigate risk from

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

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

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

31 highest priority in all commission decisions.

32 (x) The Public Utilities Commission should impose penalties

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

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

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

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

37 by shareholders of the electrical corporation or gas corporation.

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

39 proceedings authorized by Chapter 11 (commencing with Section

40 2899) of Part 2 of Division 1 of the Public Utilities Code.

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1 (z) Electrical corporations and gas corporations should notify

2 their customers, including local governments and agencies, of

3 proceedings authorized by the Utility Infrastructure, Safety,

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

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

6 (aa) The commission should encourage public comment at

7 hearings for proceedings authorized by the Utility Infrastructure,

8 Safety, Reliability, and Accountability Act (Chapter 11

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

10 Public Utilities Code).

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

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

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

14 ensure the costs associated with the implementation of Chapter

15 11 (commencing with Section 2899) of Part 2 of Division 1 of the

16 Public Utilities Code are just and reasonable for ratepayers while

17 protecting public safety and the reliability of electric and gas

18 services.

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

20 read:

21 8587.13. (a) For purposes of this section, “major event” means

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

23 that significantly affects the safety and reliability of the electrical

24 or gas distribution system.

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

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

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

28 Utilities Commission, and other appropriate state and local

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

30 major event.

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

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

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

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

35 event.

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

37 gas corporations, local publicly owned electric utilities, local

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

39 of fire during a major event.

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— 7 — SB 1088

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

2 to read:

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

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

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

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

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

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

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

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

11 changes in revenue allocation, for the services or commodities

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

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

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

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

16 corporation pursuant to an advice letter submitted to the

17 commission in accordance with commission procedures for this

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

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

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

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

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

23 30-day billing cycle, or within 75 days if the corporation operates

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

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

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

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

28 proposed rate change expressed in both dollar and percentage terms

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

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

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

32 commission to which any customer inquiries may be directed

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

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

35 mailing address of the corporation to which any customer inquiries

36 relative to the proposed rate change may be directed.

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

38 electrical or gas corporation pursuant to Section 2899.2, the

39 corporation shall furnish to its customers written notice with the

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

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SB 1088 — 8 —

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

2 site where the plan will be available electronically upon its

3 submission.

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

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

6 estimated rate impacts on the various customer classes of the

7 corporation. The commission may require the corporation to inform

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

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

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

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

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

13 rates and the approved capital projects that will subsequently be

14 executed by way of an advice letter.

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

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

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

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

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

20 consideration thereof. Rules applicable to common carriers may

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

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

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

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

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

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

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

28 the commission.

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

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

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

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

33 officer need not allow repetitive or irrelevant testimony and may

34 conduct the hearing in an efficient manner.

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

36 testify at any hearing or proceeding authorized under the Utility

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

38 11 (commencing with Section 2899) of Part 2), except that the

39 presiding officer need not allow repetitive or irrelevant testimony

40 and may conduct the hearing in an efficient manner.

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— 9 — SB 1088

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

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

3

4 CHAPTER 11. UTILITY INFRASTRUCTURE, SAFETY, RELIABILITY,

5 AND ACCOUNTABILITY

6

7 2899. This chapter shall be known, and may be cited, as the

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

9 2899.1. For purposes of this chapter, the following definitions

10 apply:

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

12 system beginning with equipment that operates at voltages lower

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

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

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

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

17 earthquake, or other occurrence that significantly affects the safety

18 and reliability of the electrical or gas distribution system.

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

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

21 including measures addressing both routine operations and major

22 events.

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

24 2899.2. (a) On or before January 15, 2019, and on or before

25 January 15 every two years thereafter, each utility shall prepare

26 and submit to the commission for review and approval a safety,

27 reliability, and resiliency plan. The plan submitted on or before

28 January 15, 2019, shall be limited to addressing fire risks, with

29 subsequent plans addressing risks associated with routine operation

30 and all major events. The plan shall include sufficient information

31 for the public and the commission to determine the costs and

32 benefits to ratepayers of the investments proposed in the plan.

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

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

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

36 applicable standards adopted or updated by the Office of

37 Emergency Services pursuant to Section 8587.13 of the

38 Government Code.

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

40 regulations, standards, and practices adopted by the commission

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

2 adopted or updated by the Office of Emergency Services pursuant

3 to Section 8587.13 of the Government Code.

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

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

6 checking that the personnel have carried out their assignments,

7 and a system of quality assurance and quality control.

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

9 8386, including protocols for disabling reclosers and deenergizing

10 portions of the electrical distribution system, as well as protocols

11 related to mitigating the impacts of those protocols.

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

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

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

15 during a major event, including hardening and modernizing its

16 infrastructure with improved engineering, system design, standards,

17 equipment, and facilities.

18 (6) Plans for vegetation management.

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

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

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

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

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

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

25 major event.

26 (8) For electrical corporations, a program to evaluate, construct,

27_______________________________________________ operate, and maintain evaluate and incorporate technological

28 solutions, such as distributed energy resources and microgrids that

29 can be islanded from the distribution grid for critical customers,

30 such as schools, hospitals, critical care patients, water pumping

31 and treatment facilities, and government and other facilities that

32 provide public safety or other critical functions.

33 (9) The disaster and emergency preparedness plan prepared

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

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

36 event, including workforce mobilization, and prepositioning

37 equipment and employees.

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

39 during, and after a major event.

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

2 including an incident command system.

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

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

5 taking into account employees of other utilities pursuant to mutual

6 aid agreements and employees of entities that have entered into

7 contracts with the utility.

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

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

e 10 timing, access to utility representatives, emergency

11 communications, and restoration plans.

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

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

14 reliability, or resiliency deemed appropriate by the commission.

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

16 in a single consolidated proceeding. The commission shall verify

17 that the plans comply with all applicable rules, regulations, and

18 standards, including those adopted by the Office of Emergency

19 Services pursuant to the State Assistance for Fire Equipment Act

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

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

22 The commission shall evaluate the reasonableness of the elements

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

24 implement the plan.

25 (2) In reviewing the plans,___ the commission shall make safety

26___________________________________________________ and reliability of electric or gas services the highest priority.

27 consistent with its ratepayer protection duties pursuant to Article

28 1 (commencing with Section 451) of Chapter 3 of Part 1, the

29 commission shall ensure that the cost impacts of the plans are just

30 and reasonable for ratepayers while prioritizing protecting public

31 safety and the reliability of electric and gas services.

32 (3) Notwithstanding Section 1701.5, with or without

33 modification, the commission shall strive to approve the plans

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

35 than 18 months after, their submission. submission, unless the

36 commission makes a written determination, including reasons

37 supporting the determination, that the 18-month deadline cannot

38 be met, and issues an order extending the deadline.

39 (4) (A) The___ Consistent with its ratepayer protection duties

40 pursuant to Article 1 (commencing with Section 451) of Chapter

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1 3 of Part 1, the commission shall authorize rate recovery of the

2 reasonable revenue requirements to implement plans approved by

3 the commission in the proceeding reviewing the plans pursuant to

4 paragraph (1). Except as provided in subparagraph (B), authorized

5 revenue shall not be reviewed, adjusted, or authorized in a utility’s

6 general rate case.

7 (B) Forecasted costs deemed outside the scope of the plan by

8 the commission may be requested and considered in a utility’s

9 general rate case or other appropriate proceeding.

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

11 implement the plan to any activities or investments outside their

12 plans.

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

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

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

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

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

18 costs in the memorandum accounts and disallow recovery of those

19 costs the commission deems unreasonable.

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

21 Mitigation Phase filing shall exclude risks addressed in the plan

22 required pursuant to subdivision (b).

23 2899.3. (a) For purposes of this section, “distribution system

24 safety or reliability performance obligations” of an electrical

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

26 operating, managing, maintaining, planning, engineering,

27 designing, investing in, and constructing the distribution system

28 in its service territory, distribution system reliability, emergency

29 response and restoration, vegetation management, service

30 connections, service turnons and turnoffs, and service inquiries

31 relating to the operation of the distribution system.

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

33 contract out any distribution system safety or reliability

34 performance obligation.

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

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

37 resource if the contract is approved by the commission and requires

38 the owner or operator of that resource to do both of the following:

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

40 meets the insurance requirements set by the commission to cover

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1 direct damages caused by the failure of the distributed energy

2 resources to comply with the terms of the contract.

3 (A) Indemnify the electrical corporation for direct damages to

4 the electrical corporation, and direct, indirect, and consequential

5 loss or damages to a person or other entity that is not a party to

6 the contract, caused by the distributed energy resource equipment

7 or_______ the failure of that equipment to operate as required by the

8 contract.

9 (B) Maintain the financial capacity to pay the damages specified

10 in subparagraph (A).

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

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

13 supervision of the electrical corporation, the purchase of materials

14 or equipment, contracting for construction of infrastructure owned

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

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

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

18 or contracting for information technology services.

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

20 television corporation or telephone corporation from contracting

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

22 to poles that also support equipment owned by an electrical

23 corporation.

24 2899.4. The commission shall conduct an annual proceeding

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

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

27 (a) Beginning March 1, 2020, and each March 1 thereafter, each

28 utility shall file with the commission a report addressing

29 compliance with the plan during the prior calendar year.

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

31 thereafter, the commission shall make available a list of qualified

32 independent evaluators with experience in assessing electric and

33 gas operations.

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

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

36 compliance with its plan. The independent evaluator shall consult

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

38 Enforcement Division of the commission. The independent

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

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

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SB 1088 — 14 —

1 independent evaluator’s report, the independent evaluator shall

2 determine whether any revenue authorized to implement the plan

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

4 commission shall strive to complete its compliance review within

5 12 months of, but in no case shall it that review be completed more

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

7 report.

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

9 the costs of the independent evaluation.

10 (4) The commission shall have exclusive jurisdiction over

11 compliance by a utility with the standards adopted pursuant to

12 Section 8587.13 of the Government Code.

13 2899.5. The commission shall assess penalties if a utility fails

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

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

16 following:

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

18 including whether the noncompliance resulted in harm.

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

20 complied with its plans in prior years.

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

22 constituting noncompliance.

23 (d) Whether the utility implemented corrective actions with

24 respect to the noncompliance.

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

26 constituting noncompliance.

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

28 similar nature that caused significant property damage or injury.

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

30 rulemaking proceeding, consistent with purposes of this section.

31 2899.6. (a) After completing the review pursuant to Section

32 2899.4, if if, either at the time the plan is reviewed and approved

33 or subsequent to its review and approval, the commission

34 determines that a utility was in substantial compliance with its

35 approved plan, the commission shall commission, to the extent the

36 commission finds it is consistent with the ratepayer protection

37 duties established pursuant to Article 1 (commencing with Section

38 451) of Chapter 3 of Part 1, shall find that the utility’s

39 performance, operations, management, and investments addressed

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1 in the plan are reasonable and prudent for purposes of any

2 subsequent commission proceeding.

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

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

5 under Section 451.

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

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

8 plan.

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

10 shall impact the admissibility of evidence otherwise permitted by

11 law or rule of court.

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

13 is approved for a particular utility.

14

15

16 CORRECTIONS:

17 Text—Page 14.

18

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