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BAKER 

&

HOSTETLER LLP

ATTORNEYS AT LAW SAN FRANCISCO 

EXHIBIT A

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Application: 15-05-xxx

(U 39 M) 

Exhibit No.: 

Date: May 1, 2015 

Witness(es): Various 

PACIFIC GAS AND ELECTRIC COMPANY 

SAFETY MODEL ASSESSMENT PROCEEDING 

PREPARED TESTIMONY 

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-iPACIFIC GAS AND ELECTRIC COMPANY 

SAFETY MODEL ASSESSMENT PROCEEDING (S-MAP) 

PREPARED TESTIMONY 

TABLE OF CONTENTS 

Chapter Title Witness

1 OVERVIEW AND SUMMARY Shelly J. Sharp 

2 COMPANYWIDE MODELS AND APPROACHES 

FOR ASSESSING RISK

Janaize Markland

3 COMPANYWIDE MODELS AND APPROACHES 

TO RISK INFORMED BUDGET ALLOCATION

Jamie L. Martin

4 ELECTRIC OPERATIONS AND NUCLEAR 

POWER GENERATION

Eric Back

Cary D. Harbor

5 GAS OPERATIONS Christine C. Chapman

6 RISK LEXICON Janaize Markland

Appendix A STATEMENTS OF QUALIFICATIONS Eric Back

Christine C. Chapman

Cary D. Harbor

Janaize Markland

Jamie L. Martin

Shelly J. Sharp

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 1 

OVERVIEW AND SUMMARY 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 1 

OVERVIEW AND SUMMARY 

TABLE OF CONTENTS 

A. Introduction ....................................................................................................... 1-1

1. General Principles Guiding This Filing ....................................................... 1-1

a. PG&E Welcomes a Sharing of Risk Management Practices ............... 1-1

b. Cooperation Among the Parties Will Advance the Industry ................. 1-2

c. PG&E Has Focused on the Management of Safety Risks ................... 1-2

d. Uniform Standards Are Appropriate in Some Areas and 

Inadvisable in Others ........................................................................... 1-2

e. The S-MAP Should Not Be Assumed to Be Open-Ended.................... 1-3

2. Organization of This Testimony ................................................................. 1-3

3. Relationship of This Filing to PG&E’s Upcoming GRC............................... 1-4

4. Risk and PG&E’s Integrated Planning Process .......................................... 1-5

B. Approach to This S-MAP .................................................................................. 1-6

1. Content of This S-MAP and Future Filings ................................................. 1-7

2. The Role of Workshops .............................................................................. 1-8

3. Commission and Stakeholder Expertise .................................................. 1-10

C. Relief Requested ............................................................................................ 1-10

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1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 1 

3 OVERVIEW AND SUMMARY 

4 A. Introduction

5 In this proceeding, Pacific Gas and Electric Company (PG&E) provides an 

6 introduction and overview of its models and methodologies used to prioritize and 

7 mitigate safety risks. This proceeding—known as the Safety Model Assessment 

8 Proceeding (S-MAP)—is submitted in accordance with Decision 14-12-025 of 

9 the California Public Utilities Commission (CPUC or Commission).

10 1. General Principles Guiding This Filing 

11 PG&E has embraced risk-informed decision-making in its planning and 

12 budgeting process and fully supports the Commission’s increased focus in 

13 this area. In the rapidly developing area of risk assessment and mitigation, 

14 utilities will continue to identify areas of improvement for their processes.1 

15 Similarly, the Commission and stakeholders may need to increase their own 

16 technical capabilities for evaluating the risks facing utilities and the proposed 

17 strategies for mitigating those risks. All participants in this new dialogue will 

18 also need to ensure that they share a common understanding of terms. If 

19 not, misunderstandings likely will ensue. 

20 Utilities, the Commission and stakeholders are in this together. 

21 Accordingly, PG&E has approached this proceeding with the following 

22 general principles in mind. 

23 a. PG&E Welcomes a Sharing of Risk Management Practices 

24 PG&E welcomes a sharing of risk management practices—both 

25 formally and informally—among stakeholders in California. In addition 

26 to this proceeding, PG&E has reached out to other participants in the 

27 State and around the country to share lessons learned. This sharing will 

28 continue beyond the issues contemplated for this first S-MAP. 

 

1 While PG&E provides its principal risk models and methodologies in this filing, PG&E 

expects to develop additional tools, models and standards as its risk management 

process matures. 

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1 b. Cooperation Among the Parties Will Advance the Industry 

2 In the developing area of utility risk management, cooperation 

3 among the parties will best serve to advance the industry’s efforts. All of 

4 the S-MAP participants have a common interest in advancing the art 

5 and science of utility risk management. To that end, PG&E aims to 

6 promote a cooperative atmosphere in this proceeding. The topics to be 

7 covered in the S-MAP lend themselves well to workshops and 

8 multimedia demonstrations, not the formality of evidentiary hearings. 

9 c. PG&E Has Focused on the Management of Safety Risks 

10 PG&E expects that the S-MAP—and future Risk Assessment and 

11 Mitigation Proceedings’ (RAMP) and General Rate Cases’ (GRC) 

12 discussion of risks—will focus primarily on key safety risks. PG&E 

13 manages other important risks, such as environmental and financial 

14 risks, although PG&E expects that such risks will not be the focus in the 

15 S-MAP. 

16 d. Uniform Standards Are Appropriate in Some Areas and Inadvisable 

17 in Others 

18 In the decision, the CPUC questions whether or not “uniform or 

19 common standards” is a goal that should be pursued.2 Some areas 

20 lend themselves well to common standards. Others do not. The former 

21 category could include, for example, the development of a risk lexicon; 

22 the application of a common framework—ISO 31000; and the use of a 

23 common process as described in the Cycla Corporation’s (Cycla) 

24 May 16, 2013 report in PG&E’s 2014 GRC.3 The latter category 

25 includes algorithms and programs for addressing risk, which are likely to 

26 differ from company-to-company, based on the characteristics of that 

27 company’s assets, environment and customers. 

 

2 D.14-12-025, mimeo, p. 30 (“The S-MAP decision can also address whether uniform or 

common standards must be used by the energy utilities in the next S-MAP filings, or 

direct the energy utilities to pursue the issue further.”). 

3 Cycla’s 10-step process is presented in Section B.1. below. 

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1 e. The S-MAP Should Not Be Assumed to Be Open-Ended 

2 The decision states that the S-MAP will take place “every 

3 three years...unless directed otherwise by the Commission.”4 At this 

4 juncture, it would be inappropriate to assume that the number of 

5 S-MAPs will be open-ended. One must be cognizant of the impacts of 

6 new proceedings. Such proceedings translate to higher administrative 

7 costs for the utilities and, of course, stress the limited resources of the 

8 Commission and stakeholders. 

9 In addition to our concerns about the number of S-MAPs going 

10 forward, PG&E is equally concerned that the S-MAPs are resolved 

11 timely. The Commission’s Decision 14-12-025 requires that the S-MAP 

12 decision be issued prior to the first RAMP filing in order to improve the 

13 incorporation of risk and safety into utility rate cases. Accordingly, 

14 PG&E would like to see this proceeding move forward efficiently and 

15 conclude promptly. 

16 2. Organization of This Testimony 

17 PG&E’s testimony is comprised of five chapters. The first two chapters 

18 address enterprisewide models. In Chapter 2, PG&E presents its Enterprise 

19 and Operational Risk Management Program (EORM) and Risk Evaluation 

20 Tool (RET), which are used to identify and rank enterprisewide and 

21 operational risks. In Chapter 3, PG&E presents its risk-informed budget 

22 allocation (RIBA) process, which is used to prioritize work in the core lines of 

23 business according to risk scores. Thereafter, PG&E presents line of 

24 business-specific approaches to risk management. Chapter 4 presents 

25 PG&E’s approach in Electric Operations and Nuclear Power Generation. 

26 Chapter 5 presents PG&E’s approach in Gas Operations. Chapter 6 

27 presents a risk lexicon developed in conjunction with Southern California 

28 Edison Company (SCE) and the Sempra utilities (Sempra). The definitions 

29 in Chapter 6 are thus jointly sponsored by SCE, Sempra and PG&E. 

 

4 D.14-12-025, mimeo, p. 55 (Ordering Paragraph 5). 

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1 The testimony takes the following structure: 

TABLE 1-1 

PACIFIC GAS AND ELECTRIC COMPANY 

STRUCTURE OF TESTIMONY

Chapter Title Witness

1 Overview and Summary S. Sharp

2 Companywide Models and 

Approaches for Assessing Risk

J. Markland

3 Companywide Models and 

Approaches to Risk Informed 

Budget Allocation

J. Martin

4 Electric Operations and Nuclear 

Power Generation

E. Back and C. Harbor

5 Gas Operations C. Chapman

6 Risk Lexicon J. Markland

Appendix A Statements of Qualifications All

2 3. Relationship of This Filing to PG&E’s Upcoming GRC 

3 This S-MAP is not a formal precursor to PG&E’s 2017 GRC. (PG&E will 

4 file its 2017 GRC on September 1, 2015.) PG&E’s 2020 GRC will be the 

5 first PG&E GRC to incorporate the results of this S-MAP and to have a 

6 formal RAMP. PG&E expects to submit the RAMP for the 2020 GRC in 

7 October 2017. 

8 Although the new risk proceedings instituted through 

9 Decision 14-12-025 will not be fully incorporated until PG&E’s 2020 GRC, 

10 PG&E will follow the spirit of Decision 14-12-025 in the preparation of its 

11 2017 case. To that end, PG&E will provide more extensive testimony on 

12 safety and risk and PG&E will explain how its forecast relates to safety and 

13 risk priorities. The 2017 GRC testimony will also follow the Commission’s 

14 directive from PG&E’s 2014 GRC, namely: 

15  PG&E will provide additional testimony on its Integrated Planning 

16 Process; affirmatively showing that risk management through integrated 

17 planning forms the foundation of the system safety and compliance 

18 projects and programs forecast in its 2017 GRC. 

19  PG&E will prioritize projects and programs in the 2017 GRC by using 

20 risk-based criteria and will describe how the projects and programs it is 

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1 forecasting mitigate the system safety risks listed on PG&E’s Risk 

2 Register. 

3  PG&E will provide enhanced testimony on its overall risk program from 

4 its Chief Risk Officer as well as line of business-specific risk testimony 

5 from the risk or asset management leads from Electric Operations, 

6 Energy Supply and Gas Operations.5

7 4. Risk and PG&E’s Integrated Planning Process 

8 As described above, PG&E will provide additional testimony on its 

9 Integrated Planning Process in its 2017 GRC. The annual Integrated 

10 Planning Process consists of four primary steps.6 The first step is 

11 establishing “Executive Guidance,” where PG&E sets forth its goals for the 

12 next five years. The second step is Session D—developed from January 

13 through April—which is used to review and discuss progress made to 

14 manage PG&E’s top compliance, enterprise and operational risks. The 

15 third step in the process is Session 1—developed from April through July—

16 which outlines PG&E’s 5-year Operating Plan, including goals and 

17 strategies. The fourth step is Session 2—developed from August through 

18 October—which sets forth PG&E’s 2-year execution plan. The Integrated 

19 Planning Process is an iterative cycle and adjustments can be made to 

20 PG&E’s plan to incorporate emerging information. For example, while 

21 Session D reviews are completed in April, senior management—through 

22 their risk and compliance committees—regularly review the status of risks 

23 and mitigation activities. Additionally, the Risk Policy Committee, which is 

24 chaired by the Chief Executive Officer, conducts a “mid-cycle check in” 

25 where the Committee reviews progress relative to PG&E’s risk profile and 

26 implementation of the EORM program. The leadership team will collectively 

27 make a decision to address newly identified gaps in PG&E’s work plan if 

28 warranted. 

 

5 D.14-08-032, mimeo, p. 12. 

6 PG&E’s Integrated Planning Process also contains an additional step, Session C, for 

the Company’s senior leadership development and succession planning. 

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1 Figure 1-1 below illustrates the Integrated Planning Process cycle and 

2 the key outputs of the process and the tools used in each step of the 

3 process. 

FIGURE 1-1 

PACIFIC GAS AND ELECTRIC COMPANY 

INTEGRATED PLANNING PROCESS 

4 B. Approach to This S-MAP 

5 PG&E has approached this S-MAP in accordance with the expectations of 

6 the Refined Straw Proposal, which envisioned: 

7 the initial S-MAP [would] ‘serve primarily an informational and education 

8 function – acquainting parties with the utilities’ models – and provide utilities 

9 an opportunity to hear reactions from Commission staff and parties and 

10 modify their models as they deem appropriate in response to Staff/parties’ 

11 concerns and recommendations.7

12 PG&E understands that the Commission’s expectations and scope of the 

13 S-MAP will change over time. Not everything can be accomplished in the first 

14 S-MAP.8

 

7 D.14-12-025, mimeo, pp. 22-23. 

8 D.14-12-025, mimeo, p. 26. 

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1 While the Commission considers the longer term goal of evaluating “uniform 

2 and common standards,” the Commission raised three topics for consideration.9 

3 First is “whether the S-MAP should be a recurring proceeding, and if so, how 

4 often should that be.”10 Second is whether workshops or an S-MAP working 

5 group should determine whether common standards can be developed.11 Third 

6 is whether Commission staff and other parties have sufficient expertise to 

7 understand and analyze the S-MAP methods and methodologies.12

8 PG&E addresses these three topics below. 

9 1. Content of This S-MAP and Future Filings 

10 The Commission has concluded that S-MAPs “should be held at least 

11 two times, at an interval of three years.”13 And, “[i]n the second proceeding, 

12 the Commission can decide whether the S-MAP proceedings should 

13 continue in the future or be terminated.”14

14 PG&E has set forth a framework in Table 1-2 for the content of 

15 two S-MAPs. This framework is tied to Cycla’s 10-step process reflecting 

16 the elements of a risk-informed resource allocation process. Cycla 

17 presented this 10-step process in PG&E’s 2014 GRC. As shown in 

18 Table 1-2, PG&E proposes addressing five of the ten steps in this first 

19 S-MAP and deferring two steps to the second S-MAP. (The remaining 

20 three steps are already addressed in the GRC process.) PG&E would defer 

21 those steps (1) pertaining to evaluating risk reduction; and (2) monitoring the 

22 effectiveness of risk control measures. As explained more fully in 

23 Chapter 2, Sections D.2.a. and D.3., quantifying risk reduction is in a 

24 particularly early state of development. S-MAP discussions in this area 

25 would benefit from additional time to mature. 

 

9 D.14-12-025, mimeo, p. 26. 

10 D.14-12-025, mimeo, p. 26. 

11 D.14-12-025, mimeo, p. 26. 

12 D.14-12-025, mimeo, pp. 26-27. 

13 D.14-12-025, mimeo, p. 27. 

14 D.14-12-025, mimeo, p. 27. 

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TABLE 1-2 

PACIFIC GAS AND ELECTRIC COMPANY 

CYCLA’S 10-STEP RISK PROCESS 

Step Cycla Process Model/Method/Process

Proceeding Where 

Process Step Should 

Be Addressed

1 Identify Threats EORM Program

Session D – Risk

RET

This First S-MAP

(Chapters 2, 4, 5)

2 Characterize Sources of 

Risk

EORM Program

Session D – Risk

RET

This First S-MAP

(Chapters 2, 4, 5)

3 Identify Candidate Risk 

Control Measures (RCM)

EORM Program

Session D – Risk

Session 1 – Strategy

Session 2 – Execution Plan

RIBA

This First S-MAP

(Chapters 2, 3, 4, 5)

4 Evaluate the Anticipated 

Risk Reduction for 

Identified RCM

EORM Program

Session D – Risk

Second S-MAP

5 Determine Resource 

Requirements for 

Identified RCMs

EORM Program

Session 1 – Strategy

Session 2 – Execution Plan

RIBA

This First S-MAP

(Chapters 3, 4, 5)

6 Select RCMs 

Considering Resource 

Requirements and 

Anticipated Risk 

Reduction

EORM Program

Session 1 – Strategy

Session 2 – Execution Plan

RIBA

This First S-MAP

(Chapters 3, 4, 5)

7 Determine Total 

Resource Requirement 

for Selected RCMs

EORM Program

Session 1 – Strategy

Session 2 – Execution Plan

RIBA

General Rate Case

8 Adjust the Set of RCMs 

to be presented in GRC 

Considering Resource 

Constraints

EORM Program

Session 1 – Strategy

Session 2 – Execution Plan

RIBA

General Rate Case

9 Adjust RCMs for

Implementation following 

CPUC decision on 

Allowed Resources

EORM Program

Session 2 – Execution Plan

RIBA

General Rate Case

10 Monitor the Effectiveness 

of RCMs

EORM Program

Session D – Risk 

Second S-MAP

1 2. The Role of Workshops 

2 On the topic of how to involve workshops in the S-MAP, the Commission 

3 concluded that they “could be useful toward reaching a consensus about 

4 uniform or common standards. These additional workshops or working 

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1 groups are something the parties and the ALJ in the S-MAP proceedings 

2 should consider.”15

3 PG&E agrees that workshops would be useful. Indeed, PG&E believes 

4 that workshops are likely to be more fruitful than evidentiary hearings for the 

5 topics under consideration. These topics are technical and include 

6 calculations, algorithms, and complex concepts. These issues are best, and 

7 most easily, explored through workshop discussions, not formal 

8 cross-examination. 

9 For these reasons, PG&E proposes a series of workshops in lieu of 

10 evidentiary hearings. These workshops should cover the following topics: 

11  Risk Lexicon – this session would have the parties work together to 

12 develop a risk lexicon based upon that jointly put forward by the utilities. 

13 PG&E envisions that this lexicon would be an educational resource, 

14 maintained by the Commission, that could be used by the Commission, 

15 utilities and stakeholders. 

16  Benchmarking of Utility Risk Processes – this session would examine 

17 the current state of utility risk management outside of California. 

18  Presentation of Utility Risk Models – this session would allow for more 

19 in-depth presentations and discussions concerning the utility risk 

20 models. This session could include live demonstrations of the models. 

21  Data Issues – this session would address data issues such as the 

22 relative value of qualitative and quantitative data, as well as the use of 

23 predictive vs. lagging indicators. 

24  Areas for Common Standards – this session would address the 

25 Commission’s interest in exploring whether common standards would be 

26 useful and have the parties work together to identify possible areas for 

27 such standards. 

28 If the Commission wishes to develop a record concerning these 

29 workshops, PG&E would support videotaping/webcasting the workshops, 

30 working with staff to develop reports, or otherwise formalizing the content of 

31 the workshops. 

 

15 D.14-12-025, mimeo, p. 28.

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1 3. Commission and Stakeholder Expertise 

2 PG&E is not in the best position to assess whether or not the 

3 Commission and stakeholders currently have the requisite expertise to 

4 review the utility models and methodologies. In the past, both Commission 

5 staff and intervenors have expressed concerns about the level of their 

6 expertise. To the extent that additional expertise is required, PG&E 

7 supports the Commission and parties obtaining such expertise through 

8 internal staff (in the long-term) or external consultants (in the short-term). 

9 The more expertise at the table, the more productive this proceeding is likely 

10 to be. In this regard, PG&E supported the hiring of experts by the Safety 

11 and Enforcement Division during PG&E’s 2014 GRC. 

12 C. Relief Requested 

13 PG&E understands the main purpose of this first S-MAP proceeding to be 

14 an informational and educational one.16 Accordingly, the formal relief requested 

15 by PG&E is relatively limited. 

16 PG&E seeks: 

17  The Commission’s development of a risk lexicon based on the definitions 

18 proposed herein. 

19  The Commission’s guidance for the content of the next S-MAP. PG&E 

20 recommends that the next S-MAP focus on:

21 – A methodology for evaluating anticipated risk reduction and monitoring 

22 the effectiveness of identified risk control measures. 

23 – The evaluation of common standards in areas where the Commission in 

24 this S-MAP deems such standards to be advisable. 

 

16 D.14-12-025, mimeo, pp. 22-23. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 2 

COMPANYWIDE MODELS AND APPROACHES FOR 

ASSESSING RISK 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 2 

COMPANYWIDE MODELS AND APPROACHES FOR ASSESSING RISK 

TABLE OF CONTENTS 

A. Introduction ....................................................................................................... 2-1

B. EORM Program Overview ................................................................................ 2-1

1. People and Processes ............................................................................... 2-2

a. Personnel ............................................................................................ 2-2

b. Committees ......................................................................................... 2-2

c. Monitoring and Metrics ........................................................................ 2-3

2. History of the Program ............................................................................... 2-4

3. Integration With PG&E’s Planning Processes ............................................ 2-4

C. The Risk Evaluation Tool .................................................................................. 2-4

1. Purpose ...................................................................................................... 2-4

2. Evolution of the Tool .................................................................................. 2-5

3. RET2.1 ....................................................................................................... 2-6

a. Inputs ................................................................................................... 2-6

1) Risk Score ..................................................................................... 2-6

2) Risk Status .................................................................................... 2-6

b. Output .................................................................................................. 2-7

4. Illustrative Example .................................................................................... 2-8

D. Areas for Focus and Improvement ................................................................. 2-10

1. Where PG&E Is Compared to Our Peers ................................................. 2-10

2. Key Challenges ........................................................................................ 2-11

a. Risk Quantification ............................................................................. 2-11

b. Risk Tolerance ................................................................................... 2-12

3. Areas of Future Activities ......................................................................... 2-13

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1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 2 

3 COMPANYWIDE MODELS AND APPROACHES FOR ASSESSING 

4 RISK 

5 A. Introduction

6 Pacific Gas and Electric Company’s (PG&E) goal is to deliver safe, reliable 

7 and affordable gas and electric service to the millions of homes and businesses 

8 that depend on us. Numerous operational risks affect the provision of gas and 

9 electric service, including natural hazards such as seismic activity and wildfires. 

10 Although risk cannot be eliminated, PG&E is committed to managing these risks 

11 and taking all reasonable measures to provide gas and electric service to our 

12 customers in a way that protects the safety of the public and our employees. 

13 This chapter describes the progress PG&E has made in implementing an 

14 industry-leading Enterprise and Operational Risk Management (EORM) Program 

15 since 2011. It also includes a description of the EORM process, including an 

16 in-depth look at PG&E’s Risk Evaluation Tool (RET) that is used to assess and 

17 rank risks across PG&E. This chapter concludes with an assessment of where 

18 PG&E is compared to other companies in the industry and a look at current 

19 challenges and future areas for improvement. 

20 B. EORM Program Overview 

21 PG&E’s program is based on International Standards Organization-31000 

22 principles and is squarely focused on providing an in-depth analysis of the 

23 enterprise and operational risks inherent in our business, the current state of 

24 controls around those risks, and the options for mitigating them further. 

25 PG&E’s EORM Program includes a robust governance structure, standard 

26 criteria and tools for assessing Company risks, dedicated resources within the 

27 Chief Risk Officer’s (CRO) organization and within all PG&E’s lines of business 

28 (LOB), defined mechanisms for cross-company collaboration, active 

29 management of LOB-specific risk registers, and integration with PG&E’s 

30 Integrated Planning Process. 

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1 1. People and Processes 

2 a. Personnel 

3 PG&E’s Enterprise and Operational Risk Management Department 

4 resides in the Chief Risk Officer Organization and reports to the CRO. 

5 The CRO reports to PG&E’s Chief Financial Officer. Led by the Director 

6 of EORM and Insurance, the EORM Department: 

7  Develops, implements and maintains enterprise-wide risk 

8 management guidance for the business. 

9  Partners with, and coaches, LOB risk managers and other key 

10 individuals to help identify, evaluate and mitigate risks. 

11  Provides process support, advice, and recommendations to ensure 

12 effective risk management within the business. 

13  Evaluates quality and tracks the implementation of mitigation 

14 activities. 

15  Leads the risk components (Session D as previously described in 

16 Chapter 1) of PG&E’s Integrated Planning Process. 

17 Each LOB also employs dedicated staff to implement the EORM 

18 Program standards and procedures within their own LOB. These 

19 employees are responsible for: 

20  Managing the LOB’s risk register. 

21  Leading risk identification and evaluation workshops within the LOB. 

22  Working with subject matter experts (SME) to develop a risk 

23 response strategy, including alternatives analysis. 

24  Ensuring risk mitigation activities are implemented according to an 

25 agreed upon schedule. 

26  Developing metrics to track progress and assess the effectiveness 

27 of mitigations. 

28 b. Committees 

29 Committees serve an important oversight role within the EORM 

30 Program. At the Board of Directors, PG&E’s audit committee is 

31 responsible for overseeing the EORM Program. Oversight of specific 

32 enterprise-level risks are addressed by the various Board committees, 

33 primarily the Nuclear, Operations and Safety Committee. Board 

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1 committees complete in-depth reviews of each enterprise-level risk at 

2 least once every 12 months. 

3 PG&E’s Risk Policy Committee, comprised of PG&E’s most senior 

4 officers, annually reviews progress made by each LOB in implementing 

5 the EORM Program and how PG&E’s risk profile may be changing 

6 over time. 

7 In addition, each LOB has its own Risk and Compliance Committee. 

8 Chaired by the most senior officer of the LOB, these Risk and 

9 Compliance Committees typically meet at least four times per year and 

10 are responsible for overseeing EORM activities within their LOB, 

11 including reviews of risk assessments and progress made in 

12 implementing mitigation activities. 

13 c. Monitoring and Metrics 

14 Once PG&E has identified and evaluated risks, determined which 

15 ones must be mitigated further, and secured the resources to do so, 

16 PG&E’s standards require LOBs to monitor progress. Mitigations are 

17 tracked and reported at regular LOB Risk and Compliance Committee 

18 meetings and, on a quarterly basis, mitigation progress is discussed at 

19 PG&E’s Business Plan Review meeting chaired by the President. If 

20 mitigation plans are delayed, an action plan is created. 

21 PG&E’s EORM standard includes identification of metrics to help 

22 evaluate the results of mitigation plans and to detect if conditions are 

23 changing in a way that would trigger a re-evaluation of the risk. These 

24 metrics can help determine if the risk reduction plan has been 

25 successful, or if the LOB needs to adjust its course. In many cases, 

26 LOBs have developed and are monitoring these metrics. In other cases, 

27 these metrics are under development or are being refined. 

28 Lastly, the EORM team oversees the implementation of risk 

29 response activities, and the LOBs’ implementation of the EORM process 

30 to ensure that standards are adhered to and progress is being made in 

31 implementing the right mitigations to reduce the risk. 

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1 2. History of the Program 

2 After establishing the standards and procedures for implementing 

3 EORM in 2011, PG&E’s Risk and Audit Organization focused on 

4 implementing PG&E’s vision of data-driven, risk-based decision making to 

5 support safe, reliable, and affordable electric and gas service that is 

6 integrated into PG&E’s planning process and becomes the foundation for 

7 our regulatory rate cases. 

8 In 2012, each LOB began working with the standards and procedures 

9 issued by the Chief Risk and Audit Officer and began to build LOB-specific 

10 risk registers. Through this work, PG&E began to use a common risk 

11 language and developed a deeper understanding of the risks PG&E faces 

12 and the drivers behind them. 

13 The development of formal risk registers began in 2012, although at this 

14 time, the risk identification effort took place as a stand-alone process. 

15 3. Integration With PG&E’s Planning Processes 

16 Once risk registers were established in each LOB, the focus shifted to 

17 integrating risk into how PG&E plans and prioritizes work. In 2013, PG&E 

18 held its first annual Session D, which is a senior management discussion of 

19 the top risks and compliance requirements facing PG&E. Session D—which 

20 began as a one-day meeting and has now expanded to two days—remains 

21 an annual event where the senior officers spend time discussing how top 

22 risks are being managed, where collaboration across LOBs is required, and 

23 where additional resources may be needed. 

24 As one of the first steps in PG&E’s Integrated Planning Process, 

25 Session D helps to develop an understanding of the top risks and 

26 compliance requirements and that knowledge informs PG&E’s strategy and 

27 execution plans. As mentioned in Chapter 1, these strategy and execution 

28 plans are called Session 1 and Session 2, respectively, and are informed by 

29 Session D.

30 C. The Risk Evaluation Tool 

31 1. Purpose 

32 Central to PG&E’s EORM Program was the development and use of 

33 PG&E’s RET. The EORM team created RET as a means of facilitating an 

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1 apples-to-apples comparison of risks across LOBs, and to ensure that the 

2 risks that rise to the top of the priority list are those that have the largest 

3 potential of preventing PG&E from achieving its objective of providing safe, 

4 reliable, and affordable service to its customers. RET is used to establish a 

5 risk score for each risk and to establish a relative priority for discussion and 

6 management purposes. The RET score is a product of the potential impact 

7 and the frequency of a risk event. Each risk event is further described as a 

8 SME-proposed Probable Worst Case (P95)1 scenario. 

9 2. Evolution of the Tool 

10 The initial RET Model (referred to as RET1) was modified in 2013 to 

11 produce RET2, and again in 2014 to create what is now referred to as 

12 RET2.1. The RET1 Model used a 3 × 3 matrix of high, medium, and low 

13 impact vs. high, medium, and low frequency. Additionally, the RET1 

14 algorithm was linear in nature and placed more emphasis on frequency than 

15 impact. Given concerns about the inability to correctly predict frequency, 

16 there was less confidence in the RET1 output. RET1 also resulted in 

17 less-than-desired differentiation of risks. That is, many risks were high 

18 impact, low frequency and occupied the same spot on the graphic output, 

19 described below as a “heat map,” limiting its usefulness in identifying areas 

20 of focus. 

21 RET2 was developed to address these deficiencies. RET2 employed a 

22 7 × 7 matrix with additional specificity included in the criteria definitions. 

23 The algorithm was changed to a logarithmic scale to increase differentiation 

24 between risks and provide a better view of relative priority of risks. One year 

25 after implementing RET2, the EORM team revisited the definitions within the 

26 impact criteria and made adjustments to the descriptions in the “Reliability” 

27 impact category2 to address LOB feedback. Although relative ranking did 

28 not change significantly between RET2 and RET2.1, the descriptions within 

29 Reliability better resonated with the LOBs using the tool. 

 

1 The P95 scenario is based on the concept of plotting a range of outcomes along a 

distribution and choosing the 95th percentile event for the purposes of the risk 

discussion. In practice, for many risks—in the absence of quantitative support—PG&E 

identifies a reasonably probable worst case scenario rather than a range of outcomes. 

2 The six impact categories in the RET model are described in the next section. 

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1 Additionally, RET2.1 included increased flexibility in the frequency 

2 criteria. No longer are risk assessments limited to seven frequency 

3 categories. If there are data to support a specific frequency, e.g., through 

4 the use of probabilistic risk assessments, LOBs may use that data to 

5 calculate the risk score. 

6 3. RET2.1 

7 a. Inputs 

8 1) Risk Score 

9 As mentioned above, the RET2.1 is used to establish a number, 

10 called a risk score for each risk to establish relative priority for 

11 discussion purposes. The RET2.1 score is a calculation based on a 

12 SME discussion of the risk associated with the P95 scenario. 

13 The potential impacts of the scenario across six impact categories 

14 are then scored between 1 and 7 (7 being the greatest impact). 

15 The six impact categories are: Safety, Environmental, Compliance, 

16 Reliability, Trust and Financial. Once the impact is articulated, 

17 a frequency or probability based on data and subject matter 

18 expertise is assigned to each risk scenario. The algorithm 

19 discussed in Attachment A is then applied to create a score 

20 between 1 and 10,000. 

21 2) Risk Status 

22 When a risk is first identified, its status is denoted as “black” 

23 indicating that a risk assessment must be completed to determine a 

24 current residual risk score. During the risk assessment, the risk 

25 owner will gather as much data and expertise on the subject to fully 

26 characterize the risk drivers and controls and to score the risk. 

27 Once the risk assessment is complete, the team determines 

28 what level of control status should be recommended to the LOB 

29 Risk and Compliance Committee. The following statuses are 

30 available: 

31  Red – controls not adequate 

32  Amber – controls need strengthening 

33  Green – controls are adequate 

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1 A risk response plan is created for a risk with Red or Amber 

2 status. The response plan includes a set of mitigations based on an 

3 alternatives analysis to determine the best course of action to 

4 reduce the risk and strengthen controls. 

5 Over time, risk scores tend to be more static than the risk 

6 status. The risk status should change toward green as the 

7 mitigations are implemented and the controls are strengthened to an 

8 adequate level. The risk score will only change if mitigations 

9 fundamentally adjust the impact or frequency levels. In other words, 

10 impact scores may change only if mitigations can physically prevent 

11 or reduce the impact of the P95 scenario. 

12 For example, if the P95 scenario risk is “a car accident which 

13 may result in a death,” a mitigant such as a physical divider between 

14 the lanes could change the worst case probable P95 scenario from 

15 fatality (head-on collision), to “a car accident which may result in a 

16 serious injury (i.e., hitting the divider).” This will drop the impact 

17 score and, likely the frequency as well. However, physical mitigants 

18 are not always possible or practical. More often, mitigations are 

19 more likely to impact the frequency side of the equation. For 

20 instance, if a substation were to fail catastrophically, the impact 

21 always would likely be catastrophic. But it may be possible to make 

22 catastrophic failure less likely to occur by addressing the drivers of 

23 the risk by maintaining, inspecting and replacing equipment, and 

24 installing physical and cyber security measures. 

25 b. Output 

26 The output of RET 2.1 is a risk score for each risk. These scores 

27 can be mapped on a “heat map” that graphically portrays the frequency 

28 and impact scores. An illustrative heat map is shown in Figure 2-1. 

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FIGURE 2-1 

PACIFIC GAS AND ELECTRIC COMPANY 

ILLUSTRATIVE HEAT MAP 

1 The y-axis on the heat map represents the frequency score, while 

2 the x-axis represents the impact score. The upper right hand corner of 

3 the heat map represents the highest risks; the lower left hand corner 

4 represents the lowest risks. 

5 Because each LOB calculates its own risk scores, LOBs participate 

6 in calibration sessions to ensure consistency in scoring. SMEs and risk 

7 managers calibrate risks internal to their LOB and then the EORM team 

8 facilitates cross-LOB calibration sessions to ensure risks from different 

9 parts of the business are evaluated consistently. During each of these 

10 sessions, participants challenge assumptions and other inputs to risk 

11 scores to ensure there is alignment in how risks were evaluated. Once 

12 the calibration is complete, top risks to PG&E are selected for 

13 discussion in PG&E’s Session D meeting. 

14 4. Illustrative Example 

15 An example helps to illustrate how RET 2.1is used to create a risk score 

16 from a risk assessment. Consider the risk of “Failure of Distribution 

17 Overhead Primary Conductor,” defined as: 

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1 The failure of or contact with energized electric distribution primary 

2 conductor may result in public or employee safety issues, significant 

3 environmental damage (fire), prolonged outages, or significant property 

4 damage. Energized wires down events are also considered part of this 

5 risk. 

6 In this case, the P95 scenario is described as: A fatality due to 

7 unintentional third-party tree worker contact with an in place conductor, in 

8 conjunction with an investigation that finds compliance violations such as 

9 lack of signage, or insufficient clearance. 

10 Once defined, the risk assessment team scores the risk by determining 

11 the impacts across the six impact categories (see Attachment B) and the 

12 frequency of such an event, and captures those determinations in the RET. 

13 In this case, the following scores were assigned: 

14  Safety impact: A 6 (Severe) impact captures the potential for a fatality 

15 to occur if contact was made with a distribution conductor. This is based 

16 on industry data and experience. 

17  Environmental impact: Under the scenario, there would be a 

18 1 (Negligible) impact on the environment.

19  Compliance impact: The scenario assumes a compliance violation, 

20 which was rated as a 3 (Moderate) impact by the team based on 

21 industry experience. 

22  Reliability impact: The team reviewed outage history that would occur 

23 relative to the incident and determined that a 3 (Moderate) impact 

24 described the potential impact. 

25  Trust impact: The team determined a 2 (Minor) impact believing that 

26 there may be a single report of the event in a media outlet near the 

27 location of the incident, were it to occur. 

28  Financial impact: Available data supports a 4 (Major) impact. 

29 Finally the team reviewed the scenario, the impact scores, and the data 

30 around the drivers and controls and determined that a frequency level of 5, 

31 or once every one to three years, was appropriate. 

32 The six impact scores and the frequency level are then input into the 

33 tool, producing a final risk score of 408. The results of the scoring of the 

34 Overhead Conductor Risk can be displayed on the heat maps as shown. 

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FIGURE 2-2 

PACIFIC GAS AND ELECTRIC COMPANY 

MAPPED RISK SCORE FOR OVERHEAD CONDUCTOR 

1 D. Areas for Focus and Improvement 

2 1. Where PG&E Is Compared to Our Peers 

3 Informed by industry benchmarking studies, the recommendations of the 

4 Independent Review Panel, and a third-party consultant, PG&E has moved 

5 from having an “industry standard” enterprise risk management program to 

6 having an “industry-leading” EORM Program. PG&E’s EORM Program is 

7 leading as evidenced by the risk-informed process of integrated planning 

8 and the widespread support for risk management in terms of personnel and 

9 management attention. Senior management regularly engages in 

10 discussions about risk, the state of controls and mitigation plans, and has 

11 increased the focus on developing and monitoring key measures that 

12 provide insight into how risks are being managed. 

13 Today, PG&E is in a position where each LOB knows and understands 

14 the risks associated with their business and the relative importance of those 

15 risks with respect to the potential impact they could have on the 

16 achievement of objectives. And the LOBs use this information to inform 

17 strategies and resource allocation. 

18 PG&E is proud of where it is today in terms of risk management. That is 

19 not to say there is no room for improvement. 

Distribution Overhead Conductor Primary

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1 2. Key Challenges 

2 Effective risk management is an iterative process. As new data 

3 becomes available, operating and environmental conditions change, and 

4 technology improves, so does PG&E’s ability to identify, evaluate, prioritize 

5 and mitigate risks. As does PG&E’s ability to dedicate the appropriate 

6 amount of resources to manage our most important risks and to 

7 demonstrate the risk reduction benefits of the investments PG&E is making. 

8 As PG&E identifies and integrates new data sources, it will develop a 

9 deeper, more granular understanding of the risks it faces and will be able to 

10 make better decisions as a result. When new information becomes 

11 available, risk management priorities may shift over time and it is important 

12 that PG&E remains dynamic in its response to that new information. 

13 This means that changes will be made to PG&E’s plans and it will deploy 

14 resources accordingly. PG&E will identify risk mitigations that do not have 

15 the intended effect and will have to change course. PG&E will also identify 

16 new risks. As new information becomes available, risks that PG&E thought 

17 were important, may take a back seat to other, more pressing risks. PG&E’s 

18 focus on data-driven decision making combined with the ability to pivot to 

19 address mitigation needs in a timely manner, will help PG&E operate in a 

20 safer and more efficient manner to the benefit of PG&E’s customers, 

21 employees and the public. 

22 a. Risk Quantification 

23 As PG&E’s EORM process has matured and progress has started to 

24 be documented, there has been an increased focus on data and 

25 quantification of risk to answer two basic questions: (1) Are we making 

26 progress in managing risk; and (2) How do we know? 

27 In 2014, the EORM team in the Risk and Audit Organization 

28 implemented a risk management database to provide better oversight of 

29 risk management activities. Risk managers in each of the LOBs began 

30 identifying data needs and fulfilling them by gathering information from 

31 PG&E and industry sources, and analyzing it to better understand risks. 

32 The outcome of that work has been the development of metrics to track 

33 and manage risks. The availability of relevant data remains a challenge, 

34 however. 

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1 Often, it is not possible to tie mitigations directly to the absence of a 

2 risk event. For example, PG&E has invested in a number of activities to 

3 educate the public about the dangers of contact with energized 

4 conductors—a top public safety risk included on the Electric Operations 

5 Risk Register. It is very difficult to prove that someone did not touch an 

6 energized conductor because they heard an advertisement on the radio, 

7 or paid attention to a mobile pop-up advertisement while they were 

8 shopping at Home Depot, or were already aware of the danger. 

9 In some cases, data can be obtained to confirm that mitigations are 

10 effective, but often PG&E must rely on the fact that it went through a 

11 reasonable process to identify the right things to do and PG&E may not 

12 be able to determine the effectiveness of an individual mitigation. 

13 PG&E’s goal remains to achieve the vision of data-driven, 

14 risk-based decision making to support safe, reliable, and affordable 

15 electric and gas service that is integrated into our planning process and 

16 becomes the foundation for our rate cases. With the core foundational 

17 components of an industry leading EORM program now in place, PG&E 

18 is working on refining its approach and improving the maturity of the 

19 process, with a focus on data and its application within EORM. 

20 b. Risk Tolerance 

21 Risk cannot be completely driven out of PG&E’s—or any—business. 

22 Today, risk tolerance is implicitly defined by the resources allocated to 

23 manage specific risks. For example, PG&E has a robust program to 

24 manage Wildfire Risk that consists of an award-winning vegetation 

25 management program, equipment retrofits in high-risk areas, and 

26 enhanced inspections. As a result, tree-related outages are in the 

27 neighborhood of 17 per 1,000 miles, < 0.02 percent of trees in contact, 

28 and there are a small number of wildfires caused by PG&E equipment 

29 each year. It may be possible to drive tree-related outages to less 

30 than 17 per 1,000 miles, or to have less than 0.02 percent of trees in 

31 contact, but that would require a level of investment greater than what 

32 PG&E is making today. With limited resources—PG&E cannot do 

33 everything and must decide at what point it is okay to not mitigate the 

34 risk further—tradeoff decisions must be made. For example, additional 

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1 investment in managing wildfire risk requires that customers either pay 

2 more, or accept higher risk in another area. PG&E is using the EORM 

3 process to help decide where to dedicate additional resources, and 

4 specifically where it has determined the risk has a current residual risk 

5 that is higher than desired. PG&E’s Risk Informed Budget Allocation 

6 process, described in Chapter 3, also helps direct resources to projects 

7 and programs that have the largest risk reduction impact. 

8 In the 2017 General Rate Case showing, PG&E will illustrate the 

9 projects and programs intended to address key risks in each operational 

10 LOB. By showing how these activities for which PG&E is requesting 

11 funding relate to risk reduction, intervenors and other stakeholders can 

12 see what risks are affected when reductions in specific programs or 

13 elimination of specific projects are recommended. As a result of this 

14 discussion, the Commission, intervenors, and PG&E will together define 

15 risk tolerance for PG&E.

16 3. Areas of Future Activities 

17 PG&E’s EORM focus for the foreseeable future can be broadly 

18 categorized as “Continuous Improvement.” PG&E is focused on refining our 

19 current processes and improving the specific mechanics of risk 

20 management, i.e., how PG&E measures risk, the analysis PG&E does 

21 around alternatives for mitigation, and how PG&E calculates progress in risk 

22 management through the use of effectiveness metrics. 

23 The EORM team also will continue to work with the LOBs to: 

24  Develop data plans for top risks, identifying what data PG&E needs, 

25 what data it has, and how to fill the gaps. 

26  Improve existing guidance and support for alternatives analysis and 

27 documenting decisions related to mitigation activities. 

28  Develop more effectiveness metrics that measure the impact of 

29 mitigation activities on risks or drivers of risk, and those that provide 

30 insight into how a risk is performing over time, i.e., is the risk increasing 

31 or decreasing? 

32 With the basic elements of industry-leading risk management now in 

33 place, PG&E’s focus is on collectively “upping our game” in the area of risk 

34 management. In support of this, the EORM team will continue to sponsor 

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1 expert training on specific risk management topics (annual training that is 

2 provided to all risk managers across PG&E); conduct benchmarking and 

3 share best practices from internal and external sources across LOBs; and 

4 continue to promote a risk-aware culture through the continued inclusion of 

5 risk in our Integrated Planning Process. 

6 In the coming years, PG&E will consider analytical approaches for 

7 quantifying risk reduction (meaning a reduction to the RET risk score). 

8 To do so will require appropriate data, perhaps over an extended period of 

9 time. This data will need to address (or avoid) the causation challenges 

10 described above. Based on the outcome of this effort, PG&E hopes to 

11 identify and implement techniques for quantifying risk reduction and their 

12 applicability to specific risks. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 2 

ATTACHMENT A 

RISK EVALUATION TOOL (RET) ALGORITHM 

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CHAPTER 2 

ATTACHMENT A 

RISK EVALUATION TOOL (RET) ALGORITHM 

The algorithm used to calculate the risk score for each P95 risk scenario is 

divided into two parts. The first part assesses how often a risk event occurs 

(frequency). The second part assesses the significance of the overall impact of 

each risk event. The overall impact is the log of the resulting product of the 

weighted impact scores in the six categories: Safety; Environmental; 

Compliance; Reliability; Trust; and Financial. 

The risk score is expressed by the following equation in the figure below, 

where f(Event) represents the frequency component of the algorithm 

and I(Event) represents the impact component: 

RISK SCORE ALGORITHM 

The risk score calculation enables risk managers to calculate the “net risk 

impact” over a range of potential outcomes that occur at different frequencies. 

For example, gas leaks of various grades occur at various frequencies, and 

some of those leaks – if left unaddressed – could cause a range of impacts 

ranging from negligible to potentially catastrophic. The calculation enables risk 

managers to take that data and generate a risk score that contemplates the 

probable worst case, or a 95th percentile event. 

“k” is a scalar used to calibrate the risk scores to cover a range of 1 

to 10,000 to create adequate separation between risks for the purposes of 

facilitating a management discussion. 

Where f is the number of occurrences expected over a one-year time horizon

And I is the weighted impact of the event

And k is the scalar and is a fixed value of 3.16 (the square root of 10)

And 0.5 s a standard factor used to calculate the variance of the aggregate impact of 

uncorrelated events. 

RS

(Event)

= k 

[0.5 Log (f

(Event)) + I(Event) ]

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PG&E has mapped the six categories to our goals of safe, reliable and 

affordable service, and weighted them, as follows: 

GOAL MAPPING TO RET IMPACT CATEGORIES 

Company Goal

Company Goal 

Weight (%)

RET Impact 

Categories

RET Category 

Weight (%)

Safe 40%

Safety 30%

Environmental 5

Compliance 5

Reliable 30

Reliability 25

Trust 5

Affordable 30 Financial 30

Total 100% 100%

The weighting shown above places more importance on certain objectives 

over others. To balance the importance of the weighting and the magnitude of 

the impact, the weightings are applied at the magnitude level (10 I) of the impact 

groups. Therefore, I(Event) can be expressed as shown in the figure below: 

IMPACT WEIGHTING 

Where

Ij (Safety, Environmental, Reliability, Financial, Reputation, Compliance) is the impact level of 

an impact group of an event

And

Wj (Safety, Environmental, Reliability, Financial, Reputation, Compliance) is the weight 

applied to the impact group of an event

I

(Event)

= Log ( ) 

 

 

 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 2 

ATTACHMENT B 

RISK ASSESSMENT CATEGORIES 

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CHAPTER 2 

ATTACHMENT B 

RISK ASSESSMENT CATEGORIES 

FREQUENCY DESCRIPTIONS

Frequency Level Frequency Description Frequency per Year

Common

(7)

> 10 times per year F = > 10

Regular

(6)

1-10 times per year F = 1 – 10

Frequent

(5)

Once every 1-3 years F = 1 - 0.3

Occasional 

(4)

Once every 3-10 years F = 0.3 - 0.1

Infrequent

(3)

Once every 10-30 years F = 0.1 - 0.033

Rare

(2)

Once every 30-100 years F = 0.033 - 0.01

Remote

(1)

Once every 100 + years F = <0.01

SAFETY IMPACT DESCRIPTIONS 

Impact Level Description

Catastrophic 

(7)

Fatalities: Many fatalities and life threatening injuries to 

the public or employees.

Severe

(6)

Fatalities: Few fatalities and life threatening injuries to the 

public or employees.

Extensive

(5)

Permanent/Serious Injuries or Illnesses: Many serious 

injuries or illnesses to the public or employees.

Major

(4)

Permanent/Serious Injuries or Illnesses: Few serious 

injuries or illnesses to the public or employees.

Moderate

(3)

Minor Injuries or illnesses: Minor injuries or illnesses to

many public members or employees.

Minor

(2)

Minor Injuries or illnesses: Minor injuries or illnesses to 

few public members or employees.

Negligible

(1)

No injury or illness or up to an un-reported negligible injury.

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ENVIORNMENTAL IMPACT DESCRIPTIONS 

Impact Level Description

Catastrophic

(7)

Duration: Permanent or long-term damage greater than 100 years; or

Hazard Level/Toxicity: Release of toxic material with immediate, acute and 

irreversible impacts to surrounding environment; or

Location: Event causes destruction of a place of international cultural 

significance; or

Size: Event results in extinction of a species.

Severe

(6)

Duration: Long-term damage between 11 years and 100 years; or

Hazard Level/Toxicity: Release of toxic material with acute and long-term 

impacts to surrounding environment; or

Location: Event causes destruction of a place of national cultural significance; or

Size: Event results in elimination of a significant population of a protected species.

Extensive

(5)

Duration: Medium-term damage between 2 and 10 years; or

Hazard Level/Toxicity: Release of toxic material with a significant threat to the 

environment and/or release with medium-term reversible impact; or

Location: Event causes destruction of a place of regional cultural significance; or

Size: Event results in harm to multiple individuals of a protected species.

Major

(4)

Duration: Short-term damage of up to 2 years; or

Hazard Level/Toxicity: Release of material with a significant threat to the 

environment and/or release with short-term reversible impact; or

Location: Event causes destruction of an individual cultural site; or

Size: Event results in harm to a single individual of a protected species.

Moderate

(3)

Duration: Short-term damage of a few months; or

Hazard Level/Toxicity: Release of material with a moderate threat to the 

environment and/or release with short-term reversible impact; or

Location: Event causes damage to an individual cultural site; or

Size: Event results in damage to the known habitat of a protected species.

Minor

(2)

Duration: Immediately correctable; or contained within a small area.

Negligible

(1)

Negligible to no damage to the environment.

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COMPLIANCE IMPACT DESCRIPTIONS 

Impact Level Description

Catastrophic

(7)

Adverse Regulatory Actions: Action resulting in closure, split, or sale of 

PG&E.

Severe

(6)

Adverse Regulatory Actions: Cease and desist orders are delivered by 

regulators. Critical assets and facilities are forced by regulators to be 

shutdown.

Extensive

(5)

Adverse Regulatory Actions: Governmental, regulator investigations, 

and enforcement actions, lasting longer than a year. Violations that result 

in multiple large non-financial sanctions; or

Increased Regulatory Oversight: Regulators force the removal and 

replacement of management positions. Regulators begin Company 

monitoring activities.

Major

(4)

Adverse Regulatory Actions: Violations that result in significant fines or 

penalties above and beyond what is codified or a regulator enforces 

non-financial sanctions; or

Expanded Regulations: Significant new and updated regulations are 

enacted as a result of an event

Moderate

(3)

Adverse Regulatory Actions: Violations that result in fines or penalties

Minor

(2)

Adverse Regulatory Actions: Self-reported or regulator identified 

violations with no fines or penalties.

Negligible

(1)

No compliance impact up to an administrative impact.

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RELIABILITY IMPACT DESCRPTIONS 

Impact Level Description

Catastrophic

(7)

Location: Impacts an entire metropolitan area, including critical customers, or is 

systemwide; and

Duration: Disruption of service of more than a year due to a permanent loss to a 

nuclear facility, hydro facility, critical gas or electric asset; or

Customer Impact: Unplanned outage (net of replacement) impacts more than 

1 million customers; or

EO: 14 million total customer hours, or more than 1 million mega-watt hours (MWh) 

total load

GO: 10 million total customer hours, or reduction of capacity greater than or equal to 

2.1 Bcf/d for seven months

ES: 40 percent of utility-owned generating fleet unavailable for one year

Severe

(6)

Location: Impacts multiple critical locations and critical customers; or

Duration: Substantial disruption of service greater than 100 days; or

Customer Impact: Unplanned outage (net of replacement) impacts more than 100k 

customers; or

EO: 1.2 million total customer hours, or more than 100 thousand MWh total load

GO: one million total customer hours, or reduction of capacity greater than 1.2 billion 

cubic feet per day (Bcf/d), but less than for seven months

ES: 20 percent of utility-owned generating fleet unavailable for one year

Extensive

(5)

Location: Impacts multiple critical locations or customers; or

Duration: Disruption of service greater than 10 days; or

Customer Impact: Unplanned outage (net of replacement) impacts more than 10k 

customers; or

EO: 100 thousand total customer hours, or more than 10 thousand MWh total load;

GO: 100 thousand total customer hours, or reduction of capacity greater than or 

equal to 0.6 Bcf/d for seven months

ES: 10 percent of utility-owned generating fleet unavailable for one year

Major

(4)

Location: Impacts a single critical location; or

Duration: Disruption of service greater than one day; or

Customer Impact: Unplanned outage (net of replacement) impacts more than 

one thousand customers; or

EO: 8 thousand total customer hours, or more than one thousand MWh total load

GO: 10 thousand total customer hours, or reduction of capacity greater than or equal 

to 0.3 Bcf/d for seven months

ES: 2 percent of utility-owned generating fleet unavailable for one year

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RELIABILITY IMPACT DESCRIPTIONS 

(CONTINUED) 

Moderate

(3)

Location: Impacts a small area with no disruption of service to critical locations; or

Duration: Disruption of service of up to one full day; or

Customer Impact: Unplanned outage (net of replacement) impacts more than 

100 customers; or

EO: 600 total customer hours, or more than 100 MWh total load

GO: one thousand total customer hours, or reduction of capacity greater than or 

equal to 0.1 Bcf/d for seven months

ES: one percent of utility-owned generating fleet unavailable for one year

Minor

(2)

Location: Impacts a small localized area with no disruption of service to critical 

locations; or

Duration: Disruption of up to three hours; or

Customer Impact: Unplanned outage (net of replacement) impacts less than 

100 customers; or

EO: Less than 600 total customer hours, or less than 100 MWh total load;

GO: Less than one thousand total customer hours, or reduction of capacity greater 

than or equal to 0.01 Bcf/d for seven months

ES: 0.1 percent of utility-owned generating fleet unavailable for one year

Negligible

(1)

No reliability to negligible impacts.

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TRUST IMPACT DESCRIPTIONS 

Impact Level Description

Catastrophic

(7)

Duration: Ongoing impacts for more than 10 years; and

Media: Event is heavily reported from local through international media outlets and 

social media channels, with influential third parties dominating media coverage; 

various inaccurate information is widely reported; or 

Political: Devastating nationwide broad-based political pressure demanding intense 

long term outreach to policymakers and key stakeholders; or

Customer Satisfaction: Greater than 50 percent loss of customer satisfaction 

through survey results; or

Company Brand: Relationships are severed and trust is completely lost

Severe

(6)

Duration: Ongoing impacts between 1 and 10 years; and

Media: Event is heavily reported from local through national media outlets and social 

media channels, with influential third parties dominating media coverage, and various 

inaccurate information is widely reported; or

Political: Extreme statewide broad-based political pressure demanding concentrated 

outreach to policymakers and key stakeholders; or

Customer Satisfaction: 21-50 percent loss of customer satisfaction through survey 

results; or

Company Brand: Event creates outrage and trust can't be fully recovered

Extensive

(5)

Duration: Ongoing impacts between one quarter and one year; or

Media: Event is widely reported in national media outlets and social media channels, 

with influential third parties dominating media coverage, and inaccurate information is 

reported; or

Political: Severe territory wide political pressure demanding extensive outreach to 

policymakers and key stakeholders; or

Customer Satisfaction: 4-20 percent loss of customer satisfaction through survey 

results; or

Company Brand: Event creates serious concerns of company management while 

trust is severely diminished

Major

(4)

Duration: Ongoing impacts between one week and one quarter; or

Media: Event is heavily reported in local through national media outlets and social 

media channels, with influential third parties dominating media coverage, and 

inaccurate information is reported; or

Political: Major territory wide political pressure demanding major outreach to 

policymakers and key stakeholders; or

Customer Satisfaction: one to three percent loss of customer satisfaction through 

survey results; or

Company Brand: Management is questioned and trust is diminished

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TRUST IMPACT DESCRIPTIONS 

(CONTINUED) 

Moderate

(3)

Duration: Short term coverage for up to one week.

Media: Event is reported in multiple local media outlets and/or social media 

channels, with limited exposure beyond the coverage area; or

Political: Moderate county level political pressure demanding moderate outreach to 

policymakers and key stakeholders; or

Customer Satisfaction: Less than one percent loss of customer satisfaction through 

survey results; or

Company Brand: Event isn’t anticipated and trust is impacted; or

Minor

(2)

Duration: Single report of the event.

Media: Event is reported in a single local media outlet in the location where the event 

took place; or

Political: Minimal political pressure demanding minimal outreach to policymakers 

and key stakeholders; or

Negligible

(1)

No known reputation impact reported to a non-featured report.

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FINANCIAL IMPACT DESCRIPTIONS 

Impact Level Description

Catastrophic

(7)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact > $5 billion in costs; or

Capital/Liquidity: Ability to raise capital significantly impacted. Dramatic decrease 

in stock price of more than 50 percent for more than one year; or

Bankruptcy: Risk of bankruptcy is imminent.

Severe

(6)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact between $500 million and 

$5 billion in costs; or

Capital/Liquidity: Ability to raise capital is challenged. Dramatic decrease in stock 

price of more than 25 percent for more than one year.

Extensive

(5)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact between $50 million and 

$500 million in costs; or

Capital/Liquidity: Ability to raise capital is hindered. Dramatic decrease in stock 

price of more than 10 percent for up to one year.

Major

(4)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact between $5 million and 

$50 million in costs.

Moderate

(3)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact between $500 thousand and 

$5 million in costs.

Minor

(2)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact between $50 thousand and 

$500 thousand in costs.

Negligible

(1)

Financial Costs: Damage to third-party properties, loss of assets and facilities, fines, 

lawsuits, restitution, remediation, restoration, cost of replacement energy, 

redistributed customer costs, amounting to a total impact of less than $50 thousand in 

costs.

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 3 

COMPANYWIDE MODELS AND APPROACHES TO RISK 

INFORMED BUDGET ALLOCATION 

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3-i 

PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 3 

COMPANYWIDE MODELS AND APPROACHES TO RISK 

INFORMED BUDGET ALLOCATION 

TABLE OF CONTENTS 

A. Overview .......................................................................................................... 3-1

B. PG&E’s Risk Informed Budget Allocation Process ........................................... 3-1

1. Purpose ...................................................................................................... 3-1

2. Approach and Methodologies .................................................................... 3-1

a. Personnel ............................................................................................ 3-1

b. Committees ......................................................................................... 3-2

c. Processes and Timing ......................................................................... 3-2

3. The Model .................................................................................................. 3-3

a. Inputs ................................................................................................... 3-4

b. Outputs ................................................................................................ 3-5

4. Illustrative Examples .................................................................................. 3-6

C. Areas of Focus and Improvement..................................................................... 3-8

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3-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 3 

3 COMPANYWIDE MODELS AND APPROACHES TO RISK 

4 INFORMED BUDGET ALLOCATION 

5 A. Overview 

6 Pacific Gas and Electric Company (PG&E) uses a Risk Informed Budget 

7 Allocation (RIBA) process to inform the prioritization of budget for risk mitigation 

8 measures and other work in its portfolio. More specifically, the RIBA process 

9 provides scores for projects and programs by evaluating the worst reasonable 

10 direct impact (WRDI) of not performing the work. The RIBA process is used for 

11 capital and expense projects and programs in Electric Transmission, Electric 

12 Distribution, Power Generation, Gas Operations, and Diablo Canyon Power 

13 Plant, and is not currently used in other parts of the company. RIBA is an 

14 integral part of the Integrated Planning Process, and is also used throughout the 

15 year when budget tradeoff decisions are required due to changing 

16 circumstances. 

17 B. PG&E’s Risk Informed Budget Allocation Process 

18 1. Purpose 

19 RIBA’s purpose is to provide a framework for making risk-informed 

20 budget decisions by risk scoring and categorizing proposed projects and 

21 programs in the operational lines of business (LOBs) capital and expense 

22 portfolios. These scores and categories provide data that are used in 

23 PG&E’s Integrated Planning Process described in Chapter 1. The outputs 

24 of the process, the RIBA graphs,1 are used during prioritization discussions 

25 within and across the LOBs. 

26 2. Approach and Methodologies 

27 a. Personnel 

28 PG&E’s Finance Department is responsible for: (i) maintaining the 

29 RIBA scoring model; (ii) leading the RIBA working group (discussed 

 

1 PG&E has included an illustrative RIBA graph in Section B.3.b. of this chapter. 

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3-2 

1 below); (iii) promoting consistent use of the RIBA process across the 

2 LOBs; and (iv) incorporating the RIBA output into PG&E’s Integrated 

3 Planning Process. The personnel within PG&E’s Finance Department 

4 responsible for the RIBA process report to the Director of Economic and 

5 Project Analysis, who reports to the Vice President of Finance. 

6 b. Committees 

7 The RIBA team leads a RIBA working group that is comprised of 

8 representatives from Finance, Risk Management, Electric Operations, 

9 Gas Operations, and Nuclear Power Generation. The working group 

10 has a variety of responsibilities. It defines the scoring methodology and

11 the risk and categorization flag taxonomies.2 It resolves issues relating 

12 to consistency across the participating LOBs. The RIBA team also 

13 works closely with PG&E’s Enterprise and Operational Risk 

14 Management (EORM) Program discussed in Chapter 2.

15 c. Processes and Timing

16 The RIBA cycle begins around April of each year after the 

17 conclusion of Session D in PG&E’s Integrated Planning Process. At that 

18 point, investment planning teams within the LOBs develop a list of 

19 proposed projects and programs to meet the Company’s strategies and 

20 goals. These projects and programs will include the risk control 

21 measures and mitigations identified in Session D. New projects and 

22 programs are risk scored by asset owners, engineers, project and 

23 program managers, and other subject matter experts (SME), and 

24 existing scores are reviewed to ensure they reflect current conditions. 

25 After the projects are scored, the RIBA team holds calibration sessions 

26 to promote consistent use of the risk criteria and categorization flags 

27 across the participating LOBs. These calibration sessions are attended 

28 by representatives from Finance, Risk Management, and the 

29 participating LOBs. 

30 The calibration sessions are typically held in June prior to submittal

31 of the LOB Session 1 material. RIBA stacked graphs and detailed risk 

 

2 Categorization flags are described in Section 3.a. below and Attachment B. 

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1 information about projects and programs are submitted to Finance in 

2 late July, to support Session 1 prioritization discussions. It is during 

3 these prioritization discussions when resource and other constraints 

4 may drive adjustments to the proposed work portfolios of the LOBs. 

5 Additional calibration sessions—if required—would be held in August, 

6 and updated RIBA output would be submitted to Finance prior to 

7 Session 2 prioritization discussions, which are held in early October. 

8 Final budget letters3 are usually sent to the LOBs in late November for 

9 the upcoming year. RIBA scores and categorizations are used 

10 throughout the year when budget trade-off decisions are required by 

11 changing circumstances. 

FIGURE 3-1 

PACIFIC GAS AND ELECTRIC COMPANY 

PLANNING TIMELINE 

12 3. The Model 

13 RIBA scores are calculated in an Excel model. The template for the 

14 model is maintained by PG&E’s Finance Department. Capital and expense 

15 projects and programs are risk scored based on the impact of the work on 

16 safety, reliability, and the environment. Work is also categorized based on 

17 compliance requirements, commitments and other considerations such as 

18 whether a project is in flight or is related to another project. For example, 

 

3 Budget letters are formal notifications to each of the LOBs, typically distributed in 

November, that set expense and capital targets for the following year. 

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1 related projects may be flagged together if it is prudent to complete such 

2 projects during the same plant outage or electric transmission clearance. 

3 a. Inputs 

4 The first step in risk scoring is to determine the WRDI of not 

5 performing the work. As in the RET2.1 model, the risk scores are based 

6 on the impact and likelihood of occurrence. The safety, environmental, 

7 and reliability impact and frequency scores are assigned based on the 

8 scoring taxonomy shown in Attachment A, and are summarized below, 

9 with 1 being negligible impact and 7 being catastrophic: 

Range Summary

Safety 7. Many fatalities and life threatening injuries to the public or 

employees.

1. No injury or illness or up to an un-reported negligible injury.

Environmental 7. Permanent or long-term damage greater than 100 years.

1. Negligible to no damage to the environment.

Reliability 7. Impacts an entire metropolitan area, including critical customers, or 

is systemwide.

1. Negligible to no reliability impacts.

Frequency 7. Imminent or already failed.

1. Once every 100+ years.

10 The process is as follows: 

11 1. Use the prescribed 1-7 scoring scale to determine the WRDI on 

12 safety, reliability, and the environment of not doing the work; the 

13 model provides fields to enter each score and fields to enter notes to 

14 support the chosen score. 

15 2. Use the prescribed 1-7 scoring scale to estimate the timing or 

16 frequency of these WRDI; enter the score and notes in the model. 

17 3. Review and flag each proposed work item to reflect other non-risk 

18 drivers of the work. Required work categories are Mandatory, 

19 Compliance, Work Requested by Others (WRO), or Commitment. 

20 Additionally, all work may be flagged as In-Flight, Financial Benefits, 

21 Capacity, Inter-Relationship with other projects, and/or Support. 

22 These flags provide additional information that informs budget 

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3-5 

1 decisions, as they identify key business reasons for performing the 

2 work.4

3 b. Outputs 

4 Using the algorithm discussed in Attachment C, the output of the 

5 RIBA process is a risk scored portfolio that can be sorted in multiple 

6 ways (by flag, risk score, safety score, etc.) The results are also 

7 presented to management graphically. A simulated graph for illustrative 

8 purposes is shown below. 

FIGURE 3-3 

PACIFIC GAS AND ELECTRIC COMPANY 

ILLUSTRATIVE RIBA GRAPH 

 

4 See Attachment B, Flag Taxonomy, for a complete definition of the work categorization 

flags. 

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1 Dollars are shown on the x-axis and the RIBA score is shown on the 

2 y-axis, thus the width of the bar represents the proposed budget, and its 

3 height represents the RIBA score. The color of each bar represents the 

4 categorization of the work. The Mandatory, WRO, Compliance, and 

5 Commitment flags are mutually exclusive and designed to capture all 

6 required work. Any work assigned one of those flags would be graphed 

7 as such. The other flags are not mutually exclusive, and multiple flags 

8 may be assigned to non-required work. The LOBs can choose which 

9 flags to identify for purposes of generating a RIBA graph. Similar 

10 graphs can be generated that are sorted by risk score, program, or other 

11 means. 

12 4. Illustrative Examples 

13 The following projects illustrate the RIBA data and scoring of 

14 two projects associated with overhead conductor risk mitigation. The text is 

15 paraphrased from a RIBA scoring template submitted to Finance by Electric 

16 Operations. The scoring was done by SMEs in Electric Operations. 

17 The purpose of the first project is to reconductor 1,440 circuit feet of 

18 copper conductor due to the number of splices on the line.5

19 Safety: This project received a Safety Impact Score of 6 and a Safety 

20 Frequency Score of 1. This was based on the possibility of a fatality as a 

21 result of the public contacting down overhead primary conductor. The 

22 conductor is located across the street from a public school. Historical data 

23 indicates 0.79 fatalities per year associated with the public contacting a 

24 down overhead primary conductor. PG&E estimates that 2,700 wire-down 

25 events will occur annually. The frequency of a fatal event is therefore 

26 0.0003 (0.79/2,700) which translates to a frequency score of 1. These 

27 assumptions provide an overall Safety Risk Score of 178. 

28 Environment: This project received an Environmental Impact Score of 1 

29 and an Environmental Frequency Score of 1. This was based on the 

30 location of the line in an urban neighborhood, across the street from a public 

 

5 Internally, the project is called “MADERA 1104 ‒ RECONDUCTOR SUNSET AVE.”

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1 school. These assumptions provide an overall Environmental Risk Score 

2 of 1.

3 Reliability: This project received a Reliability Impact Score of 4 and a 

4 Reliability Frequency Score of 6. This was because these broken wires 

5 would lead to 3,161 Customers Experiencing a Sustained Outage (CESO) 

6 (CESO = 3,161, duration 6 + hours), impacts a middle school, and there 

7 have been four wires down outages on this line in the last three years. 

8 These assumptions provide an overall Reliability Risk Score of 178. 

9 Total Risk Score: Summing the Safety, Environmental and Reliability 

10 Risk Scores gives a Total Risk Score for this Project of 357. 

11 In terms of “flags,” this project is not a required project, so in a RIBA 

12 graph it would appear within the discretionary work as No Flag showing an 

13 overall risk score of 357. 

14 The purpose of the second project is to reconductor 200 circuit feet of 

15 Aluminum Conductor Steel Reinforced overhead conductor with Aluminum 

16 conductor and install two overhead cutouts.6 This work will provide higher 

17 reliability and operational flexibility on the Tidewater 2107 circuit and will 

18 reduce the likelihood of a wire-down event. 

19 Safety: This project received a Safety Impact Score of 6 and a Safety 

20 Frequency Score of 1, using the same scoring assumptions described for 

21 the first project. These assumptions provide an overall Safety Risk Score 

22 of 178. 

23 Environment: This project received an Environmental Impact Score of 1 

24 and an Environmental Frequency Score of 1. This was based on the 

25 location of the line in an urban neighborhood. These assumptions provide 

26 an overall Environmental Risk Score of 1.

27 Reliability: This project received a Reliability Impact Score of 3 and a 

28 Reliability Frequency Score of 5. This was because these broken wires 

29 would lead to 43 customers experiencing a sustained outage (CESO) 

30 (CESO = 43, duration 10 hours) and there have been two wires down 

 

6 Internally, the project is called “RECON 1 SPAN LINE SIDE FU 1829 TW 2107.”

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1 outages on this line in the last three years. These assumptions provide an 

2 overall Reliability Risk Score of 23. 

3 Total Risk Score: Combining the Safety, Environmental and Reliability 

4 Risk Scores gives a Total Risk Score for this Project of 202. 

5 In terms of “flags,” this project is not a required project, so in a RIBA 

6 graph it would appear within the discretionary work as No Flag showing an 

7 overall risk score of 202. 

8 C. Areas of Focus and Improvement 

9 Over the next three years, PG&E expects to work on the following areas of 

10 possible improvement for the RIBA process. 

11 First, the RIBA team, the EORM team, and the LOBs will evaluate current 

12 differences in the weighting algorithms between RIBA and RET. PG&E intends 

13 to work toward alignment wherever possible, and validate differences where 

14 appropriate. The RIBA team will work closely with the EORM team to assure 

15 that improvements made in the EORM program are incorporated into RIBA. 

16 These types of improvements would include topics such as risk quantification 

17 and risk tolerance. 

18 Second, the RIBA team is working with PG&E’s Information Technology 

19 Department to incorporate RIBA into SAP Project Portfolio Management (PPM), 

20 which PG&E is currently implementing across the enterprise. PPM is an 

21 end-to-end solution that will enable PG&E to plan and manage its portfolio of 

22 work more effectively, efficiently and in a consistent manner across the entire 

23 company. PPM will allow standardized planning and management of work at the 

24 portfolio and program levels and will integrate the RIBA scoring model with other 

25 work attributes such as cost, schedule, approval status, resource availability, 

26 and accounting information. PPM will be integrated with SAP to facilitate rate 

27 case, Session 1 and Session 2 planning and reporting. 

28 Third, PG&E is exploring the practicality of extending the RIBA process to 

29 other LOBs within PG&E. RIBA’s initial focus was asset based, and focused on 

30 the core operational LOBs. The RIBA team is working with the investment 

31 planning and risk teams in the other LOBs to develop a risk-informed 

32 prioritization process that will improve the decision-making process in those 

33 organizations. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 3 

ATTACHMENT A 

SCORING TAXONOMY 

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3-AtchA-1 

CHAPTER 3 

ATTACHMENT A 

SCORING TAXONOMY 

The entire scoring taxonomy is presented here for completeness. The Safety 

and Environmental taxonomies are exactly the same as those used in RET2.1. 

There are some minor differences between RET2.1 and RIBA in the Reliability and 

Frequency taxonomies. 

Impact

Level Safety

Catastrophic

(7)

o Fatalities: Many fatalities and life threatening injuries 

to the public or employees.

Severe

(6)

o Fatalities: Few fatalities and life threatening injuries to 

the public or employees.

Extensive

(5)

o Permanent/Serious Injuries or Illnesses: Many serious 

injuries or illnesses to the public or employees.

Major

(4)

o Permanent/Serious Injuries or Illnesses: 

Few serious injuries or illnesses to the public or 

employees.

Moderate

(3)

o Minor Injuries or illnesses: Minor injuries or illnesses 

to many public members or employees.

Minor

(2)

o Minor Injuries or illnesses: Minor injuries or illnesses 

to few public members or employees.

Negligible

(1)

o No injury or illness or up to an un-reported negligible 

injury.

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Impact

Level Environmental

Catastrophic

(7)

Duration: Permanent or long-term damage greater than 100 years; 

or

Hazard Level/Toxicity: Release of toxic material with immediate, 

acute and irreversible impacts to surrounding environment; or

Location: Event causes destruction of a place of international 

cultural significance; or

Size: Event results in extinction of a species.

Severe

(6)

Duration: Long-term damage between 11 years and 100 years; or

Hazard Level/Toxicity: Release of toxic material with acute and longterm impacts to surrounding environment; or

Location: Event causes destruction of a place of national cultural 

significance; or

Size: Event results in elimination of a significant population of a 

protected species.

Extensive

(5)

Duration: Medium-term damage between 2 and 10 years; or

Hazard Level/Toxicity: Release of toxic material with a significant 

threat to the environment and/or release with medium-term 

reversible impact; or

Location: Event causes destruction of a place of regional cultural 

significance; or

Size: Event results in harm to multiple individuals of a protected 

species.

Major

(4)

Duration: Short-term damage of up to 2 years; or

Hazard Level/Toxicity: Release of material with a significant threat 

to the environment and/or release with short-term reversible 

impact; or

Location: Event causes destruction of an individual cultural site; or

Size: Event results in harm to a single individual of a protected 

species.

Moderate

(3)

Duration: Short-term damage of a few months; or

Hazard Level/Toxicity: Release of material with a moderate threat to 

the environment and/or release with short-term reversible impact; 

or

Location: Event causes damage to an individual cultural site; or

Size: Event results in damage to the known habitat of a protected 

species.

Minor

(2)

Duration: Immediately correctable; or contained within a small area.

Negligible

(1)

Negligible to no damage to the environment.

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Impact

Level Reliability

Catastrophic

(7)

Location: Impacts an entire metropolitan area, including critical 

customers, or is system-wide; and

Duration: Disruption of service of more than a year due to a 

permanent loss to a nuclear facility, hydro facility, critical gas or 

electric asset; or

Customer Impact: Unplanned outage (net of replacement) impacts 

more than 1 million customers; or

EO: 50 million total customer hours, or more than 1 million mwh total 

load; 

GO: 10 million total customer hours, or reduction of capacity greater 

than or equal to 2.1 Bcf/d for 7 months 

DCPP: 4,000% miss of equivalent forced outage factor and/or 

availability target

PG: 40% or more of utility-owned generating fleet unavailable for 1 

year

Severe

(6)

Location: Impacts multiple critical locations and critical customers; or

Duration: Substantial disruption of service greater than 100 days; or

Customer Impact: Unplanned outage (net of replacement) impacts 

more than 100k customers; or

EO: 5 million total customer hours, or more than 100k mwh total load; 

GO: 1 million total customer hours, or reduction of capacity greater 

than or equal to 1.2 Bcf/d for 7 months;

DCPP: 2,000% miss of equivalent forced outage factor and/or 

availability target

PG: 10% or more of utility-owned generating fleet unavailable for 1 

year

Extensive

(5)

Location: Impacts multiple critical locations or customers; or

Duration: Disruption of service greater than 10 days; or

Customer Impact: Unplanned outage (net of replacement) impacts 

more than 10k customers; or

EO: 500k total customer hours, or more than 10k mwh total load; 

GO: 100k total customer hours, or reduction of capacity greater than 

or equal to 0.6 Bcf/d for 7 months;

DCPP: 500% miss of equivalent forced outage factor and/or availability 

target

PG: 2.75% or more of utility-owned generating fleet unavailable for 1 

year

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Major

(4)

Location: Impacts a single critical location; or

Duration: Disruption of service greater than 1 day; or

Customer Impact: Unplanned outage (net of replacement) impacts 

more than 1k customers; or

EO: 50k total customer hours, or more than 1k mwh total load; 

GO: 10k total customer hours, or reduction of capacity greater than or 

equal to 0.3 Bcf/d for 7 months;

DCPP: 100% miss of equivalent forced outage factor and/or availability 

target

PG: 0.75% or more of utility-owned generating fleet unavailable for 1 

year

Moderate

(3)

Location: Impacts a small area with no disruption of service to critical 

locations; or

Duration: Disruption of service of up to 1 full day; or

Customer Impact: Unplanned outage (net of replacement) impacts 

more than 100 customers; or

EO: 5k total customer hours, or more than 100 mwh total load; 

GO: 1k total customer hours, or reduction of capacity greater than or 

equal to 0.1 Bcf/d for 7 months;

DCPP: 50% miss of ES equivalent forced outage factor and/or 

availability target

PG: 0.20% or more of utility-owned generating fleet unavailable for 1 

year

Minor

(2)

Location: Impacts a small localized area with no disruption of service 

to critical locations; or

Duration: Disruption of up to 3 hours; or

Customer Impact: Unplanned outage (net of replacement) impacts 

less than 100 customers; or

EO: Less than 5k total customer hours, or less than 100 mwh total 

load; 

GO: Less than 1k total customer hours, or reduction of capacity greater 

than or equal to 0.01 Bcf/d for 7 months;

DCPP: 5% miss of ES equivalent forced outage factor and/or availability 

target

PG: 0.05% or more of utility-owned generating fleet unavailable for 1 

year

Negligible

(1)

o No reliability to negligible impacts.

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Frequency Taxonomy

Level Description Frequency Description Frequency per year

7 Imminent or 

Already failed > 10 times per year F = 10 - 100

6 Within 1 year 1 - 10 times per year F = 1 - 10

5 Within 3 years Once every 1-3 years F = 0.3 -1.0

4.5 Within 5 years Once every 3 - 5 years F= 0.2 -0.3

4 Within 10 years Once every 5-10 years F = 0.1 -0.2

3 Within 30 years Once every 10 - 30 years F = 0.033 - 0.1

2 Within 100 years Once every 30 - 100 years F = 0.01 - 0.033

1 100+ years Once every 100 + years F = 0.001 - 0.01 

RIBA Scoring Matrix

Impact Levels 

Negligible Minor Moderate Major Extensive Severe Catastrophic

Frequency 

Level 1 2 3 4 5 6 7

Common

(7) 10 32 100 316 1,000 3,162 10,000

Regular

(6) 6 18 56 178 562 1,778 5,623

Frequent

(5) 2 7 23 74 234 740 2,340

Often

(4.5) 2 7 21 67 211 668 2,113

Occasional

(4) 2 6 18 56 178 562 1,778

Infrequent

(3) 1 4 14 43 135 427 1,351

Rare

(2) 1 3 10 32 100 316 1,000

Remote

(1) 1 2 6 18 56 178 562

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 3 

ATTACHMENT B 

FLAG TAXONOMY 

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3-AtchB-1 

CHAPTER 3 

ATTACHMENT B 

FLAG TAXONOMY 

Commitments and requirements (Choose one of the following, or None)

Mandatory  Must be conducted in the budget or forecast year to 

comply with a regulation

Regulatory

Compliance

 Work that is required to comply with a regulation, but 

that does not meet the definition of ‘Mandatory’

Commitment  The company has made a specific commitment to 

completing the proposed work in a public forum or to 

regulators. Includes Rule 20A work

WRO  Work requested by others spans agricultural-related 

requests, and new business (customer connections)

Other Considerations (Select YES OR NO for each of the following)

In-flight  Under construction or 50% of total expected cost 

committed as of the beginning of the budget year 

(e.g., if in 2014 planning for 2015, then as of 1/1/2015).

Applies to project work that has a defined scope. For a 

complete definition of a project refer to the Project 

approval Procedure, Utility Procedure: PM-1001P-01.

Interrelationships 

with other

projects

 Used to indicate that the proposed work either must, or 

should, be done in conjunction with other work 

(e.g., opportunity created by a planned outage or 

having a trench open).

Capacity  Work meant to meet changes in system demand or 

load growth in the future

Support  IT Apps & Infrastructure; Tools & Equipment; Fleet; 

Buildings, Roads and Physical Infrastructure; Training

Financial Impact (Select Hard, Soft, or None)

Hard financial 

benefits

 Any sustainable net cost reduction (measured in 

dollars) from an established point of reference.

Soft financial 

benefits

 Any productivity or business improvement from an 

established business standard.

None  If there are no financial benefits.

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 3 

ATTACHMENT C 

RISK-INFORMED BUDGET ALLOCATION TOOL ALGORITHM 

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CHAPTER 3 

ATTACHMENT C 

RISK-INFORMED BUDGET ALLOCATION TOOL ALGORITHM 

The equation for each risk score is the same equation in RET2.1 and is: 

RS = k(0.5 Log ( f ) + I)

Log (f) is determined from the following table 

Frequency Level 1 2 3 4 4.5 5 6 7

Log (f) -3.0 -2.0 -1.5 -1.0 -0.7 -0.5 1.0 2.0

Just as in RET2.1 the RIBA algorithm also allows for a direct input of the 

frequency by the scorer. The RIBA algorithm also allows a Frequency Level of 4.5. 

This option was added because SMEs performing the RIBA scoring felt that in many 

cases they had sufficient knowledge and data to make the distinction between a 

failure every three to five years and a failure every three to ten years. The resulting 

scores are shown below. 

RIBA SCORING MATRIX 

Impact Levels

Negligible Minor Moderate Major Extensive Severe Catastrophic

Frequency 

Level 1 2 3 4 5 6 7

Common

(7) 10 32 100 316 1,000 3,162 10,000

Regular

(6) 6 18 56 178 562 1,778 5,623

Frequent

(5) 2 7 23 74 234 740 2,340

Often

(4.5) 2 7 21 67 211 668 2,113

Occasional

(4) 2 6 18 56 178 562 1,778

Infrequent

(3) 1 4 14 43 135 427 1,351

Rare

(2) 1 3 10 32 100 316 1,000

Remote

(1) 1 2 6 18 56 178 562

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3-AtchC-2 

The total risk score is the sum of the Safety, Environmental, and Reliability 

scores (therefore all three are weighted equally). The component scores are 

available to reviewers in order to provide a more detailed view into the work portfolio. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 4 

ELECTRIC OPERATIONS AND NUCLEAR POWER 

GENERATION 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 4 

ELECTRIC OPERATIONS AND NUCLEAR POWER GENERATION 

TABLE OF CONTENTS 

A. Introduction ....................................................................................................... 4-1

B. General Processes ........................................................................................... 4-1

1. Electric Operations ..................................................................................... 4-1

a. Organizational Structure ...................................................................... 4-3

b. Risk Register ....................................................................................... 4-3

c. Risk Evaluation .................................................................................... 4-4

d. Risk Management Software Applications ............................................ 4-8

1) System Tool for Asset Risk ........................................................... 4-9

2) Generation Risk Information Tool ................................................ 4-12

e. Risk Informed Budget Allocation ........................................................ 4-13

2. Nuclear Power Generation ....................................................................... 4-13

C. Areas of Focus and Improvement................................................................... 4-14

1. Electric Operations ................................................................................... 4-14

2. Nuclear Power Generation ....................................................................... 4-15

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4-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 4 

3 ELECTRIC OPERATIONS AND NUCLEAR POWER GENERATION 

4 A. Introduction

5 This chapter describes how Pacific Gas and Electric Company’s (PG&E) 

6 Electric Operations (EO) organization is using the Enterprise and Operational 

7 Risk Management (EORM) Program to manage electric system risks. This 

8 portion is sponsored by Eric Back, Director, Compliance and Risk Management 

9 for Electric Operations. EO is responsible for the electric transmission and 

10 distribution (T&D) systems, fossil, hydro, and other non-nuclear generating 

11 facilities and energy procurement. 

12 This chapter also describes how PG&E’s Nuclear Power Generation 

13 organization is managing risks associated with PG&E’s nuclear facilities. 

14 The nuclear portion is sponsored by Cary D. Harbor, Director, Compliance 

15 Alliance and Risk for Nuclear Power Generation. 

16 B. General Processes 

17 1. Electric Operations 

18 EO is implementing the EORM Program described in Chapter 2, 

19 “Companywide Models and Approaches for Assessing Risk,” to manage 

20 electric system risks. This program requires EO to identify, evaluate, 

21 mitigate, and monitor risks. The process provides a repeatable and 

22 consistent method of managing risks and is an important element of PG&E’s 

23 Integrated Planning Process. Figure 4-1, is a high-level illustration of the 

24 risk management framework. 

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4-2 

FIGURE 4-1 

PACIFIC GAS AND ELECTRIC COMPANY 

RISK MANAGEMENT FRAMEWORK 

1 The remainder of this EO section is organized as follows: 

2  Organizational Structure – Describes EO risk management personnel 

3 and committees. 

4  Risk Register – Describes the codification of identified risks. 

5  Risk Evaluation – Describes the tools EO uses to score items on the 

6 Risk Register. 

7  Risk Management Software Applications – Describes software 

8 applications that PG&E is developing to assist with risk management 

9 activities. 

10  Risk Informed Budget Allocation (RIBA) – As generally described in 

11 Chapter 3, the process EO uses to “risk score” projects and programs to 

12 inform budgeting decisions. 

13 In addition to the models described in Chapters 2 (Risk Evaluation Tool) 

14 and 3 (RIBA), EO also uses a variety of tools (e.g., spreadsheets and 

15 databases) that provide information regarding asset condition and in some 

16 instances potential replacement priority. In some cases the information from 

17 these tools is used to inform the models described in Chapters 2 and 3 and 

18 is also used in analysis by subject matter experts (SME) during the risk 

19 assessment process. 

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1 a. Organizational Structure 

2 Chapter 2 describes how each line of business (LOB) has resources 

3 dedicated to coordinating risk management activities within the LOB; 

4 and collaborating on risk management activities across the LOBs. The 

5 risk management organization within EO is the System Safety and Risk 

6 team and consists of a senior manager and several full-time risk 

7 analysts. This team reports to the Director for Compliance and Risk 

8 Management, who reports to the Vice President for Electric Operations 

9 Asset Management. 

10 The System Safety and Risk team is responsible for implementing 

11 the EORM Program for the following areas: 

12  Electric Transmission Lines 

13  Electric Transmission and Distribution Substations 

14  Electric Distribution Lines 

15  Non-Nuclear Power Generation Facilities 

16  Energy Procurement 

17 Items in the Risk Register (described in the next section) are 

18 assigned to a risk owner (typically a director) who is responsible for 

19 ensuring the accuracy of a risk’s evaluation and implementing risk 

20 response plans and mitigations. SMEs working within EO assist the risk 

21 owners and the EO System Safety and Risk team when evaluating risks 

22 and creating risk response plans. 

23 Also, EO has a Risk and Compliance Committee (RCC). The RCC 

24 is chaired by EO’s Executive Vice President and is comprised of her 

25 executive leadership team. This committee meets monthly to review 

26 current risk-related topics and approve various items such as risk 

27 assessments, risk mitigation measures, and changes to the 

28 Risk Register. 

29 b. Risk Register 

30 PG&E uses risk registers to log and classify risks. The EO Risk 

31 Register currently includes 72 risks.1 The risks are categorized as 

 

1 For a full list of all risks sorted by score and category, see Attachment A of this chapter. 

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4-4 

1 enterprise risks, asset risks, process risks, or energy policy risks. These 

2 different types of risk are defined below. 

3 Enterprise Risks (5): Enterprise risks are risks that could have a 

4 catastrophic impact on PG&E if they were to occur. 

5 Asset Risks (43): Risks that have consequences associated with 

6 component failure or malfunction. These are further divided into: 

7  Transmission Overhead Risks 

8  Distribution Overhead Risks 

9  Transmission and Distribution Underground Risks 

10  Substation Risks 

11  Power Generation Risks 

12 Process Risks (14): Process-based risks have consequences 

13 associated with business processes, programs, PG&E personnel, etc. 

14 Energy Policy Risks (10): These risks are generally financial risks 

15 related to bulk power operations, energy markets, portfolio 

16 management, etc. 

17 Examples of key public safety risks from the EO Risk Register 

18 include wildfire, hydro system safety, and asset-related risks associated 

19 with the electric T&D system. Energy policy and the majority of process 

20 risks are not considered key public safety risks. 

21 c. Risk Evaluation 

22 EO uses two tools to evaluate items on the Risk Register: 

23  The Risk Evaluation Tool (RET) 

24  Risk Assessments 

25 1) Application of RET to Electric Operations 

26 EO uses RET, described in Chapter 2, Section C, to establish a 

27 risk score for each risk in the Risk Register. For the majority of 

28 uses, EO uses the RET as directed by the EORM Program and no 

29 modifications are made to the algorithm, frequency scales, or impact 

30 group weightings. While EO does not modify the RET model itself, 

31 a variety of data and judgment are inherent when applying the 

32 frequency and impact scales of the model and in the formulation of 

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4-5 

1 the P95 scoring scenarios.2 How the RET is used in EO’s risk 

2 assessment process is described more fully in the next section. 

3 It is important to note that there are distinctions between (i) Risk 

4 Register scores, (ii) program/project risk scores (which are 

5 discussed later in the Risk Informed Budget Allocation section of this 

6 chapter), and (iii) an individual asset risk score which is discussed in 

7 the System Tool for Asset Risk (STAR) and Generation Risk 

8 Information Tool (GRIT) sections, later in this chapter. 

9 2) Risk Assessments 

10 The purpose of a risk assessment is to identify potential hazards 

11 and analyze what might happen if a hazard event occurs. Within 

12 EO, risk assessments are used to provide a systematic 

13 understanding of the items on the Risk Register. 

14 EO uses a common framework to perform risk assessments and 

15 upon completion, the assessments are presented to the EO RCC for 

16 review and approval of the Risk Register scores and recommended 

17 mitigations. 

18 The components of a risk assessment include: 

19  Risk definition and scope 

20  A scoring scenario (the “P95” scenario) and the application of the 

21 RET to determine a Risk Register score 

22  Identification of risk drivers and consequences 

23  Identification and assessment of risk controls 

24  Identification of current gaps and potential mitigations 

25 Assessments typically take 60 to 90 days to complete, and are 

26 performed by a team of SMEs led by a risk analyst from the System 

27 Safety and Risk Management team. The team compiles and analyzes 

28 data from a variety of sources (e.g., asset condition data, event reports, 

29 reliability data, etc.) to perform the assessment. 

30 The team also identifies and assesses existing controls and 

31 identifies potential new mitigations (or strengthening of existing controls) 

32 during the assessment. Periodic reviews with the risk owner are 

 

2 See Chapter 2, Section C for a definition. 

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1 conducted during the assessment. Decisions regarding what mitigations 

2 to recommend to the RCC are often made during these sessions. After 

3 the RCC approves a risk assessment, the approved mitigations are 

4 tracked to ensure completion. 

5 EO is currently working to complete a formal risk assessment for all 

6 items on the Risk Register. When all the risk assessments are 

7 completed, EO will have established a common basis for relative risk 

8 scores for assets, processes, and events that rely on a common 

9 framework, particularly with respect to the application of the RET for 

10 scoring. 

11 Illustrative Example: The example below—on overhead conductor 

12 risk—demonstrates aspects of the EO risk assessment process. This 

13 information is taken from the distribution primary overhead conductor 

14 risk assessment, which was presented to the EO RCC on November 14, 

15 2013.3

16 Risk Name: Distribution Primary Overhead Conductor.

17 Risk Definition: Failure of or contact with, energized electric 

18 distribution primary conductor may result in public or employee safety 

19 issues, significant environmental damage (fire), prolonged outages, or 

20 significant property damage. 

21 Scenario Evaluated (P95): A fatality due to unintentional contact, 

22 such as by a third-party tree worker, with an in-place conductor, 

23 partnered with an investigation that finds a compliance violation such as 

24 lack of signage, or insufficient clearance. Energized wire-down events 

25 are also considered as part of this risk. 

26 As part of the risk assessment, the team identified types of events 

27 that could occur: (1) contact with intact wire (or conductor situated in 

28 proper operating position); or (2) contact with a wire that has fallen 

29 down. Figure 4-2 displays the list of controls identified during this risk 

30 assessment sorted by the type of conductor contact that could occur. 

 

3 Attachment B of this chapter contains excerpts from the risk assessment for primary 

overhead conductor. 

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4-7 

FIGURE 4-2 

PACIFIC GAS AND ELECTRIC COMPANY 

ELECTRIC OPERATIONS PRIMARY OVERHEAD CONDUCTOR RISK CONTROLS 

Control

Type of Contact

Intact

Wire 

Down

Vegetation Management

Routine trimming and removal x x

Work at historic outage locations x x

Pilot analyzing failure characteristics of otherwise healthy trees in wildfire areas x x

Design, Construction and Operating Requirements

Clearance requirements x

Warning signs x

Bulletins addressing the use of 6 Cu and automatic splices x

Expanding corrosion area boundaries x

Review of minimum wire sizes x

Review of splices per span and application of shunt splices x

Public Awareness Programs

Wire Down awareness x

Tree Trimmers awareness x

Need awareness program for specific third parties such as painters, roofers, 

cable, crane operators

x

Other

Overhead conductor replacement program x

Infrared and splice inventory program x

System protection x

Overhead line maintenance program x x

911 response x

1 Figure 4-3 contains a list of additional mitigations approved as a 

2 result of this risk assessment. These mitigations are also sorted by the 

3 type of conductor contact that could occur. 

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4-8 

FIGURE 4-3 

PACIFIC GAS AND ELECTRIC COMPANY 

ELECTRIC OPERATIONS DISTRIBUTION OVERHEAD CONDUCTOR PRIMARY RISK 

ASSESSMENT MITIGATIONS

Control

Type of Contact

Intact

Wire 

Down

Expand public safety outreach program to (1) focus on specific third parties such 

as painters, roofers, cable, crane operators beyond veg; (2) expanded metrics 

and reporting to ensure efforts are effective.

x x

Review tree trimming practices to explore opportunities to focus on historical wire 

down locations.

x x

Revise STAR Tool to assign additional risk to small and copper wires and 

locations with higher failure rates.

x

Develop a plan, including quantities and schedules, to replace certain small wire 

(such as 4 Cu, 6 Cu and ACSR) in wild fire areas, urban areas and high 

corrosion areas.

x

Electric distribution standards to issue guidelines for threshold limit on maximum 

number of in-line connectors on existing lines as well as criteria/driver for 

nominating OH wire for replacement.

x

Revisit existing distribution protection practices and explore potential application 

of new technology options to reduce likelihood of a down primary wire remaining 

energized. Prepare a report summarizing the findings and recommendations.

x

1 These controls and mitigations represent the work that PG&E 

2 performs to address PG&E’s distribution overhead conductor primary 

3 risk. Other ongoing work such as line patrols and the daily operations of 

4 vegetation management also contributes to the mitigation of this risk. 

5 d. Risk Management Software Applications 

6 PG&E’s electric system is extensive, including: 142,000 miles of 

7 distribution lines; 18,600 miles of transmission lines; 855 substations; 

8 107 hydro generating units at 67 powerhouses; 170 dams; 

9 approximately 368 miles of conveyance facilities (including canals, 

10 flumes, tunnels, pipes, and natural waterways); 93 total penstocks; and 

11 3 fossil generating stations. 

12 Within these systems and facilities there are millions of individual 

13 assets with a variety of processes and analytical methodologies to 

14 manage risk. While risk management processes and methods are 

15 becoming more uniform, a more systematic and consistent approach 

16 that integrates the concepts of probability and severity for asset failures

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1 is needed. Towards this end, PG&E is developing software applications

2 that will serve as platforms to drive consistency and improve risk 

3 management within and across asset classes. 

4 1) System Tool for Asset Risk 

5 The software that PG&E is developing to address transmission 

6 and distribution assets is the System Tool for Asset Risk (STAR). 

7 When fully developed, the STAR application is envisioned to be the 

8 source system for risk elements (e.g., asset health indices, risk 

9 impact factors and resultant risk scores)4 for asset classes 

10 (e.g., poles, transformers, and conductors) that can have a 

11 significant impact on safety, reliability, and the environment. The 

12 STAR platform will: 

13  Calculate asset health indices and risk scores 

14  Represent the indices and scores geospatially and graphically

15  Facilitate risk analysis at an asset and system level 

16 STAR will accomplish this by automating the collection of data 

17 from a variety of sources (e.g., geospatial information systems, 

18 financial and asset management systems, equipment condition 

19 databases) to standardize and facilitate the risk calculations across 

20 the EO T&D asset base. The system will be flexible and enable an 

21 evolutionary process in both risk calculations and new data sources 

22 as they are identified. Ultimately, the application would be an 

23 integral part of the risk management process within EO. 

24 Since STAR will draw data from existing sources, PG&E 

25 anticipates that information gathering methods related to asset 

26 characteristics and condition will generally remain the same. 

27 Examples include: 

28 Substation Assets – Dissolved gas analysis tests, equipment 

29 test results, loading history, substation inspection results, input from 

 

4 Asset health indices reflect the condition of an asset. Risk impact factors include 

elements such as safety, reliability, financial, etc. and the effect a risk can have on 

those elements. A risk score is the product of: (1) probability of failure; and 

(2) consequence of failure. It’s currently envisioned that STAR will use the RET scoring 

framework. 

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1 substation maintenance personnel and asset characteristics such as 

2 equipment manufacturer, year installed, etc. 

3 Transmission and Distribution Line Assets – Pole test and 

4 treat programs, General Order 165 patrol and inspection programs, 

5 equipment inspection results, load flow programs, transformer 

6 loading programs, vegetation management information, and asset 

7 characteristics such as equipment size and type, manufacturer, year 

8 installed, etc.

9 To support the STAR effort, PG&E has used Electric Program 

10 Investment Charge (EPIC)5 funding to create a prototype of the 

11 application. The STAR prototype calculates and visually displays 

12 risk scores at an individual asset level for electric distribution wood 

13 poles, overhead primary conductor line sections, distribution circuit 

14 breakers and distribution substation transformers for a portion of 

15 PG&E’s territory. By creating a prototype of STAR as part of the 

16 EPIC Program, it has been possible to research, develop, and 

17 demonstrate risk scoring processes and algorithms. Figure 4-4 

18 shows sample screenshots from the STAR prototype. 

 

5 EPIC funding provides public interest investments in the areas of applied research and 

development and technology demonstration and deployment. 

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FIGURE 4-4 

PACIFIC GAS AND ELECTRIC COMPANY 

STAR SAMPLE SCREENSHOTS 

Overhead conductor from Rio Bravo Substation. Pop-up boxes displaying 

substation risk scores and single line diagram give additional information. 

Geospatial visualization of transformers in the Central Valley. 

Health vs. Age and Duval triangle show fleet characteristics. 

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1 STAR will take several years to implement across all of EO 

2 T&D. The implementation will likely face challenges in the areas of 

3 data availability and consistency, interfacing with existing 

4 applications, and the creation of algorithms. When complete, the 

5 STAR tool will provide risk scores for EO T&D facilities that asset 

6 management personnel will use to identify work and develop asset 

7 strategies. PG&E anticipates that, as improvements in data quality 

8 and analytic capabilities occur, the algorithms for asset health 

9 indices and risk scores will also evolve. 

10 2) Generation Risk Information Tool 

11 The software application being developed for PG&E’s fossil, 

12 hydro, and other non-nuclear generating facilities is the Generation 

13 Risk Information Tool (GRIT). GRIT is an integrated asset 

14 management application which provides data centralization, 

15 standardization of asset management scoring, asset risk trending, 

16 improved reporting, and analytics. GRIT interfaces with SAP Work 

17 Management and is designed for logging, planning, and reporting on 

18 assessments (tests, inspections, reviews, calculations, etc.), asset 

19 condition indicators, and asset health and consequence scores. 

20 Consequence scores are in line with the RET,6 as described earlier 

21 in Section B of this chapter. Lastly, GRIT also tracks risk mitigation 

22 activities, including projects, maintenance, and operational changes. 

23 The GRIT application organizes and displays condition and 

24 consequence data on equipment within major hydro areas. These 

25 equipment records are categorized by program and geography. The 

26 GRIT prototype became operational in 2014, and has 15 hydro 

27 asset types in the tool today, with more expected soon. 

 

6 PG&E notes that the current version of GRIT uses RET frequency and impact scores 

and guidance as directed by the EORM Program. However, GRIT still uses the linear 

RET1 Model algorithm detailed in Chapter 2, Section C.

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1 e. Risk Informed Budget Allocation 

2 Chapter 3 describes PG&E’s Risk Informed Budget Allocation 

3 (RIBA) process. EO uses RIBA as part of PG&E’s Integrated Planning 

4 Process. 

5 EO generally uses RIBA as directed by PG&E’s Finance 

6 organization (i.e., no modifications to the frequency scales or the impact 

7 groups of safety, reliability or environment). 

8 2. Nuclear Power Generation

9 Risk is managed for Nuclear Power Generation by the Compliance and 

10 Risk Department. The director of this department reports directly to the 

11 Senior Vice President, Chief Nuclear Officer. Within the Compliance and 

12 Risk Department, approximately two full time employees are focused on risk 

13 issues. Their responsibilities include coordination of policies and 

14 procedures developed to identify, quantify and mitigate or manage risk. Like 

15 EO, Nuclear Power Generation maintains its own Risk Register, and 

16 prepares Session D risk analyses as part of the Integrated Planning Process 

17 previously described. 

18 The tools used by Nuclear Power Generation to manage risk include the 

19 RET and RIBA processes discussed above and in Chapters 2 and 3 of this 

20 testimony. In addition, Nuclear Power Generation implements a number of 

21 additional risk management tools specific to nuclear generation. These 

22 tools are often prescribed by the Nuclear Regulatory Commission (NRC), 

23 which provides extensive oversight of a broad range of plant activities.7

24 Some of the key additional procedures and risk tools used specifically at 

25 the Diablo Canyon Power Plant (DCPP) include: 

26 1) Probabilistic Risk Assessment. This tool is used to assess 

27 vulnerabilities to a wide range of events and to risk-inform decisions and 

28 changes, including priority, type, and controls applied to such activities. 

29 2) A robust risk-informed work management program provides appropriate 

30 priorities for performing maintenance on permanent plant equipment and 

31 requires detailed instructions to assure the proper performance of 

 

7 These tools are subject to the jurisdiction of the NRC and are provided here for 

informational purposes. 

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4-14

1 maintenance, including specification of in-process and post2 maintenance quality checks, proper specification of materials to be 

3 used, and post-maintenance testing to confirm functionality of 

4 equipment following maintenance.

5 3) The NRC maintenance rule (10 Code of Federal Regulations 

6 (CFR) 50.65) requires the reliability of permanent plant equipment 

7 critical to mitigation of upset conditions or whose failure could cause 

8 plant transients to be monitored, and actions initiated (such as increased 

9 preventive maintenance or testing) to meet minimum reliability 

10 standards. 

11 4) DCPP maintains a robust corrective action program as required by 

12 10 CFR 50 Attachment B to assure that performance shortcomings are 

13 identified, captured, and evaluated for corrective action. 

14 5) Diablo Canyon procedure ER1-DC1, “Component Classification,” 

15 requires items whose failure could result in a plant trip, loss of 

16 generation, or other plant level important function, to be flagged and 

17 requires high levels of preventive maintenance to ensure equipment 

18 reliability. 

19 C. Areas of Focus and Improvement 

20 1. Electric Operations 

21 Though much progress has been made thus far, EO anticipates future 

22 refinement of our risk management program. Potential areas of future focus 

23 include: 

24  Improving Quantitative Rigor Associated With Likelihood of Asset 

25 Failure. To the extent possible, EO believes it is better to develop and 

26 rely on leading rather than lagging asset failure indicators. This will 

27 allow EO to predict and address failures before they occur and therefore 

28 reduce the need for emergency replacement activity. Steps that can aid 

29 in facilitating this goal include: (1) improving the collection and tracking 

30 of asset health metrics; and (2) collaborating across the utility industry to 

31 establish models that better predict asset failure. A continued focus on 

32 strengthening the collection and tracking of metrics related to asset 

33 health will improve process integrity, while EO works to establish 

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4-15

1 predictive indicators. Collaboration across the industry will be important 

2 to setting the stage for validating new predictive indicators. 

3  Implement STAR. STAR’s analytics-centered asset management 

4 approach is designed to continuously update risk scores based on 

5 regular updates to source data systems. STAR will: (1) allow EO to 

6 incrementally update asset-level, and ultimately system-level, risk 

7 scores; (2) facilitate the use of asset analytics to drive proactive asset 

8 replacement; and (3) create a platform to better collect and track asset 

9 health metrics. The continuous incremental updating of asset risk 

10 scoring through the use of STAR can be used to strengthen financial 

11 planning. This will be done by linking STAR to RIBA directly, thus 

12 allowing STAR to inform financial planning through the Integrated 

13 Planning Process. 

14  Enhance GRIT. In future phases, data from additional sources will be 

15 linked to GRIT to aid Power Generation users in making informed 

16 decisions about equipment replacement and project costs. New 

17 functionality (including a dashboard) will be built and GRIT will be further 

18 integrated with other systems. Lastly, three to five more asset types will 

19 be added to the system. 

20  Further Develop and Refine the EO Risk Register to Address 

21 Interactive Threats. To date, the EO risk assessment process has 

22 focused primarily on an in-depth examination of individual risks and 

23 individual risk drivers or threats. This method does not account for the 

24 interaction between multiple risks and threats. With this in mind, EO will 

25 consider ways to better understand the relationship between multiple 

26 risks and/or multiple threats. 

27  Improving the Relationship Between Risks and Expenditures. 

28 Establishing a link between risks and expenditures for controls and 

29 mitigations will help EO to better communicate how its expenditure 

30 portfolios align with the Risk Register. 

31 2. Nuclear Power Generation 

32 Though much progress has been made thus far, Nuclear Power 

33 Generation anticipates future expansion and refinement of our risk 

34 management program. Potential areas of future focus may include: 

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4-16

1  Further Develop and Refine the Nuclear Power Generation Risk 

2 Register to Expand the Population for Review. To date, the Nuclear 

3 Power Generation risk assessment process has focused primarily on 

4 major projects. Approximately 140 in-flight projects and major projects 

5 in the long-term plan have been risk assessed. An additional 

6 71 projects have been identified for risk assessment to be completed 

7 over the next several months. Procedures for project review have been 

8 modified to require all new projects to complete this risk assessment 

9 before funds are committed beyond initial project scoping efforts. 

10 Training materials for project managers and project leadership are also 

11 being developed to ensure appropriate impact criteria are considered 

12 and scoring is consistently applied. 

13  Improving the Relationship Between Risks and Expenditures. 

14 Establishing a stronger link between risks and required project 

15 contingency will help Nuclear Power Generation better communicate 

16 risks associated with the expenditure portfolio. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 4 

ATTACHMENT A 

ELECTRIC OPERATIONS RISK REGISTER 

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Electric Operations Risk Register (1/2) 

As of April 7, 2015 

# Risk Name 

Current 

Residual 

Risk Score 

1 Wildfire 626

2 Changing GHG Regulations 417

3 Distribution Overhead Conductor Primary 408

4 Failure of Substation (Catastrophic) 401

5 Hydro System Safety - Dams 349

6 Cybersecurity 327

7 Above-Market Stranded Costs 311

8 Distribution Overhead Conductor Secondary 310

9 Transmission Overhead Conductors 310

10 Portfolio Mix 308

11 Safety Standards for PPAs 308

12 Loss of Customer Load 298

13 Electric Grid Restoration 283

14

Emergency Preparedness and Response to 

Catastrophic Events 

280

15 Distribution Underground Cable 245

16 Encroachment on EO Assets 237

17 Network Components (In Urban/High Density Areas) 237

18 Records Management 236

19 Transmission Overhead Wood Support Structures 235

20 Substation Switches 215

# Risk Name 

21 System Integrity Protection 

22 Voltage Planning and Opera

23 Distribution Overhead Supp

24 Failure of Generation Facilit

25 Critical Equipment Procurem

26 Transmission Underground 

27 Substation Transformers an

28 Unit Substations 

29 Distribution Underground Li

30 Hydro Public Access 

31 Hydro Support Infrastructur

32 Hydro Turbine – Generator 

33 Seismic Resiliency 

34 Control Room Operational A

35

Substation Protective Relays

Transformers & Station Batt

36 Bulk Power Operations 

37 Transmission Overhead Stee

38

Lack of Real-time Operation

of Critical Systems 

39 New Policy & Market Deisgn 

40 Hydro Pressure Integrity Sys

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Electric Operations Risk Register (2/2) 

As of April 7, 2015 

# Risk Name 

Current 

Residual 

Risk Score 

41 Fossil Fuel Systems 103

42 Significant Natural Gas Price Increase 99

43 Fossil Chemical Systems 98

44 Fossil Turbine – Generator Systems 98

45 AB 32 / Cap-and-Trade 97

46 Risk of Non-Compliance 82

47 Employee Qualifications 81

48 Workforce Planning 81

49 Market Flaws / Manipulation 76

50 Loss of Transmission Corridor 73

51 Substation Bus Structures 69

52 Cover-up/ Fraud 61

53 Lack of Transmission Project Delivery 54

54 Substation Circuit Breakers and Switchgear 53

55 Hydro In-stream Flow Release (IFR) Valve and Bypass 42

56 Hydro Protection and Control Systems 37

57 Fossil High Energy Systems 33

58 Substation Voltage and Flow Control Equipment 32

59 Transmission Overhead Switches 32

60 Distributed Generation 31

# Risk Name 

61

Distribution Underground S

Mount Transformers 

62 Fossil Protection and Contro

63 Distribution Overhead Stree

64 Distribution Overhead Line 

65 Fossil Balance of Plant 

66 Hydro Balance of Plant 

67

Distribution Overhead Line 

Regulators, Boosters, and C

68 Distribution Overhead Tran

69 Fuel Cell Systems 

70 Photovoltaic Systems 

71 Substation Grounding Syste

72 Hydro Material Release into 

Note: The Electric Operations Ris

Risks and risk scores can change. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 4 

ATTACHMENT B 

RISK ASSESSMENT EXAMPLE 

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Risk Assessment Ex

Primary Overhead Con

The following document contains excerpts from PG&E’s ris

Primary Overhead Conductors conducted in Novemb

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System Safety – Overhead Primary Conductors 

November 2013 

• Define

o Risk Definition and Scope

• Measure

o Asset Overview

• Analyze

o Bow Tie Analysis

o Overhead Primary Events

o Contact with “Intact” Energized

Conductors

o Vegetation

o Contact with Wires Down

o Current Control Mitigations

o Current Controls Assessment

• Improve

o Recommendations

o Assessment of Proposed Controls

• Appendix

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Risk Definition and Scope 

Risk Definition: 

Failure of or contact with, energized electric 

distribution primary conductor results in public or 

employee safety issues, significant environmental 

damage, prolonged outages, or significant 

property damage 

In Scope 

• All 2.4kV to 21kV distribution overhead conductors

including splices, connectors and jumpers

• Events involving in-place assets operating asdesigned and failure or wire down

• Event consequences in terms of injury/fatalities and

property damage, including non-catastrophic fires

Out of Scope 

• Support structures

• Transmission and secondary overhead conductors

• System protection

• Ignition of catastrophic wild fire

Im

Probability 

Risk Priori

0

90

80

70

60

50

40

30

20

10

100

0 1 2 

Residual R

Analysis in progres

Current controls no

Current controls no

being implemented 

Current controls are 

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Asset Overview 

Conductor Size 

(small to large)

Number of 

Circuit Miles

Percent of 

Total

6 Cu 22,157 20%

4 Cu 6,310 6%

4 ACSR 47,555 42%

2 ACSR 9,836 9%

2 Cu 3,826 3%

1/0 ACSR 1,791 2%

1/0 Cu 2,105 2%

4/0 Al 5,081 4%

397 Al 5,435 5%

715 Al 4,970 4%

Other Sizes 4,381 4%

Total 113,447 100%

• 113,500 overhead circuit miles

• ACSR -- 53%

• Copper -- 31%

• Aluminum -- 13%

• 91,000 circuit miles smaller than 1/0

• 27% of conductors older than 50 yrs

“Other Sizes” include approximately 250 miles of copperweld 

conductor and very small sizes (i.e., 8 Cu) – This is likely very old 

conductor. 

Wood Pole Age as a Proxy fo

33%

18%

19%

5%

0%

35%

30%

25%

20%

15%

10%

> 50 yrs 40-50 yrs 30-40 yrs 

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Bow Tie Analysis 

Third party: 

• Foreign object

• Construction Equipment

• Non PG&E Worker

Intact 

Conductor 

Event 

PG&E Employee: 

• WPE

Vegetation: 

• Compliant trees

• Noncompliant trees

Equipment Failure: 

• Conductor/splice

• Corrosion

Third party: 

• Vegetation

• Non PG&E Worker

Wire Down 

Conductor 

Event 

Animal 

PG&E Employee: 

• WPE

Drivers 

Vegetation: 

• Compliant trees

• Noncompliant trees

Animal 

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OH Primary Conductors is Second Leading 

Cause of Injury/Fatality Events (car pole is 1

st

)

• 86 injury/fatality and property

damage events in the past eight

years involved overhead primary

conductors

o 62 intact facilities

o 24 wire down

• Of the 86 events, there were 29

fatalities

• 20 property damage (>$50k) events

o 14 caused by wires down, five by 3

rd

party and one by PG&E contractor

Injury/Fatality and Third 

OH Primary Condu

Category 2005 2006 2007 2008 2009 2010 2011 2

Third Party Injury/Fatality 14 8 6 7 5 5 6 

PG&E Injury/Fatality 1 2 0 2 1 1 1 

Third Party Property Damage 2 4 3 3 4 2 1 

Total 17 14 9 12 10 8 8 

Injury/Fatality and Property Damage Events 

Involving OH Primary Conductor -- 2005 to 2012 

50

5 

8

3

0

80

60

40

20

Third Party

Injury/Fatality

Event

PG&E

Injury/Fatality

Event

Intact W

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Contact with “Intact” Energized Primary 

Conductor in its Normal State 

• Third party: 50 events over 8 years; 22 fatalities, 29 injuries

• PG&E Employees: 5 events over 8 years; 2 fatalities, 3 injurie

o 3 events – 1 direct contact, 2 while installing/replacing fac

o 2 events with digger derrick booms

Foreign 

Vehicles 

constru

contacti

pipes, a

pipes, s

gutters/

Theft and Others: 6 Events 

Attempted wire theft or 

unauthorized climbing 

Non-PG&E Personnel: 12 Events 

Tree trimmers and communication 

workers 

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Location of 3

rd Party Contact with Conductor 

OH Primary Third 

Events 

2005 

County

Santa Clara 

Madera 

San Luis Obispo 

Santa Cruz 

Contra Costa 

El Dorado 

Fresno 

Monterey 

San Mateo 

Sutter 

Subtotal of 10 Coun

13 Counties with 1 o

25 Counties with zero 

System Total 

• PG&E covers 48 counties

o 38 events in 10 counties

o 20 events in 13 other counties

o No event in 25 counties

• No strong relationship between event causes

and location

• Santa Clara, Madera, San Luis Obispo and

Santa Cruz are the counties with the most

events:

• Non-PG&E worker accounted for half of

the Santa Clara events

• Foreign objects are the major cause in

Madera, San Luis Obispo and Santa Cruz

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Wire Down Conductor Event -- Drivers 

Four Basic Causes of Wire Down 

• Equipment failure

o Conductors, splices, connectors, jumpers

• “Compliant” vegetation still create wires down

o 90% of vegetation-related wire down involve a

tree, tree-branch, or tree bark falling on the line

from outside the required clearance distance

o < 5% due to tree growing into line or PG&E

contractor trimming

• Third-party-initiated

o Vehicle/pole (72%)

o Balloons (9%)

o 3

rd

 party contact (4%)

o Gun shot (4%)

o Other (11%) spread over seven sub-categories

• Animal initiated

o Bird (78%)

o Squirrel (12%)

o Other (10%)

Third pa

, 14%

Vegetation 

, 43%

2008-2012 Wire Dow

2008 2009 

Vegetation 746 80

Equipment Failure 743 62

Third party 174 19

Animal 74 7

Company Initiated 7 

Unknown cause 9 

Totals 1,753 1,70

• 2012 outage reporting enhancem

the number of outages and accu

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Wire Down - Injury/Fatality & Property Damage 

 

3

rd

 Party Fatality/Injury PG&E Employee 

Fatality/Injury 

Pro

8 events 

4 fatalities, 5 injuries 

3 events 

1 fatality, 2 injuries 

• 3 vegetation

• 1 bird

• 1 structure fire (firefighter)

• 1 snow storm

• 1 wild land fire (firefighter)

• 1 conductor contacting guywire

(communication worker)

• 1 tree fell on conductor (injury,

January 2006).

• 1 conductor contacting x-arm

(fatality, January 2008)

• 1 guy wire wrapped with

primary conductor following car

hitting down guy (injury,

December 2008)

• 5 cond

• 4 vege

• 2 pole 

• 1 bird

• 1 equip

• 1 pole 

2005 to 2012 

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