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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PACIFIC 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

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 1

OVERVIEW AND SUMMARY

1-i

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

1-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 1 2

OVERVIEW AND SUMMARY 3

A. Introduction 4

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

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

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

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

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

1. General Principles Guiding This Filing 10

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

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

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

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

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

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

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

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

not, misunderstandings likely will ensue. 19

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

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

general principles in mind. 22

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

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

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

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

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

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

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.

1-2

b. Cooperation Among the Parties Will Advance the Industry 1

In the developing area of utility risk management, cooperation 2

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

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

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

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

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

multimedia demonstrations, not the formality of evidentiary hearings. 8

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

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

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

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

manages other important risks, such as environmental and financial 13

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

S-MAP. 15

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

in Others 17

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

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

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

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

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

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

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

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

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

company’s assets, environment and customers. 27

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

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

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

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

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

new proceedings. Such proceedings translate to higher administrative 6

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

Commission and stakeholders. 8

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

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

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

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

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

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

conclude promptly. 15

2. Organization of This Testimony 16

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

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

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

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

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

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

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

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

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

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

presents a risk lexicon developed in conjunction with Southern California 27

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

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

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

1-4

The testimony takes the following structure: 1

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

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

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

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

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

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

October 2017. 7

Although the new risk proceedings instituted through 8

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

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

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

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

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

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

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

Process; affirmatively showing that risk management through integrated 16

planning forms the foundation of the system safety and compliance 17

projects and programs forecast in its 2017 GRC. 18

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

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

1-5

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

Register. 2

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

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

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

Energy Supply and Gas Operations.5 6

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

warranted. 28

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.

1-6

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

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

process. 3 FIGURE 1-1

PACIFIC GAS AND ELECTRIC COMPANY INTEGRATED PLANNING PROCESS

B. Approach to This S-MAP 4

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

the Refined Straw Proposal, which envisioned: 6

the initial S-MAP [would] ‘serve primarily an informational and education 7 function – acquainting parties with the utilities’ models – and provide utilities 8 an opportunity to hear reactions from Commission staff and parties and 9 modify their models as they deem appropriate in response to Staff/parties’ 10 concerns and recommendations.7 11

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

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

S-MAP.8 14

7 D.14-12-025, mimeo, pp. 22-23. 8 D.14-12-025, mimeo, p. 26.

1-7

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

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

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

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

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

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

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

PG&E addresses these three topics below. 8

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

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

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

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

continue in the future or be terminated.”14 13

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

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

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

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

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

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

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

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

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

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

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

would benefit from additional time to mature. 25

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

2. The Role of Workshops 1

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

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

uniform or common standards. These additional workshops or working 4

1-9

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

should consider.”15 2

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

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

topics under consideration. These topics are technical and include 5

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

most easily, explored through workshop discussions, not formal 7

cross-examination. 8

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

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

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

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

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

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

utilities and stakeholders. 15

Benchmarking of Utility Risk Processes – this session would examine 16

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

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

in-depth presentations and discussions concerning the utility risk 19

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

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

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

predictive vs. lagging indicators. 23

Areas for Common Standards – this session would address the 24

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

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

such standards. 27

If the Commission wishes to develop a record concerning these 28

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

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

the workshops. 31

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

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3. Commission and Stakeholder Expertise 1

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

Commission and stakeholders currently have the requisite expertise to 3

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

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

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

supports the Commission and parties obtaining such expertise through 7

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

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

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

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

C. Relief Requested 12

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

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

by PG&E is relatively limited. 15

PG&E seeks: 16

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

proposed herein. 18

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

recommends that the next S-MAP focus on: 20

– A methodology for evaluating anticipated risk reduction and monitoring 21

the effectiveness of identified risk control measures. 22

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

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

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

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 2

COMPANYWIDE MODELS AND APPROACHES FOR

ASSESSING RISK

2-i

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

2-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 2 2

COMPANYWIDE MODELS AND APPROACHES FOR ASSESSING 3

RISK 4

A. Introduction 5

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

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

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

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

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

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

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

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

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

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

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

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

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

challenges and future areas for improvement. 19

B. EORM Program Overview 20

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

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

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

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

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

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

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

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

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

Integrated Planning Process. 30

2-2

1. People and Processes 1

a. Personnel 2

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

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

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

of EORM and Insurance, the EORM Department: 6

Develops, implements and maintains enterprise-wide risk 7

management guidance for the business. 8

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

individuals to help identify, evaluate and mitigate risks. 10

Provides process support, advice, and recommendations to ensure 11

effective risk management within the business. 12

Evaluates quality and tracks the implementation of mitigation 13

activities. 14

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

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

Each LOB also employs dedicated staff to implement the EORM 17

Program standards and procedures within their own LOB. These 18

employees are responsible for: 19

Managing the LOB’s risk register. 20

Leading risk identification and evaluation workshops within the LOB. 21

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

response strategy, including alternatives analysis. 23

Ensuring risk mitigation activities are implemented according to an 24

agreed upon schedule. 25

Developing metrics to track progress and assess the effectiveness 26

of mitigations. 27

b. Committees 28

Committees serve an important oversight role within the EORM 29

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

responsible for overseeing the EORM Program. Oversight of specific 31

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

primarily the Nuclear, Operations and Safety Committee. Board 33

2-3

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

least once every 12 months. 2

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

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

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

over time. 6

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

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

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

are responsible for overseeing EORM activities within their LOB, 10

including reviews of risk assessments and progress made in 11

implementing mitigation activities. 12

c. Monitoring and Metrics 13

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

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

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

tracked and reported at regular LOB Risk and Compliance Committee 17

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

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

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

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

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

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

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

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

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

these metrics are under development or are being refined. 27

Lastly, the EORM team oversees the implementation of risk 28

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

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

implementing the right mitigations to reduce the risk. 31

2-4

2. History of the Program 1

After establishing the standards and procedures for implementing 2

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

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

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

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

our regulatory rate cases. 7

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

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

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

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

and the drivers behind them. 12

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

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

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

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

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

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

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

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

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

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

where additional resources may be needed. 23

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

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

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

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

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

Session D. 29

C. The Risk Evaluation Tool 30

1. Purpose 31

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

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

2-5

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

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

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

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

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

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

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

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

2. Evolution of the Tool 9

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

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

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

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

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

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

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

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

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

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

of focus. 20

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

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

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

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

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

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

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

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

Reliability better resonated with the LOBs using the tool. 29

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.

2-6

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

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

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

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

calculate the risk score. 5

3. RET2.1 6

a. Inputs 7

1) Risk Score 8

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

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

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

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

The potential impacts of the scenario across six impact categories 13

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

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

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

a frequency or probability based on data and subject matter 17

expertise is assigned to each risk scenario. The algorithm 18

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

between 1 and 10,000. 20

2) Risk Status 21

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

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

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

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

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

Once the risk assessment is complete, the team determines 27

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

Risk and Compliance Committee. The following statuses are 29

available: 30

Red – controls not adequate 31

Amber – controls need strengthening 32

Green – controls are adequate 33

2-7

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

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

alternatives analysis to determine the best course of action to 3

reduce the risk and strengthen controls. 4

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

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

mitigations are implemented and the controls are strengthened to an 7

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

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

impact scores may change only if mitigations can physically prevent 10

or reduce the impact of the P95 scenario. 11

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

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

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

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

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

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

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

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

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

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

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

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

installing physical and cyber security measures. 24

b. Output 25

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

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

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

2-8

FIGURE 2-1 PACIFIC GAS AND ELECTRIC COMPANY

ILLUSTRATIVE HEAT MAP

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

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

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

represents the lowest risks. 4

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

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

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

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

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

sessions, participants challenge assumptions and other inputs to risk 10

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

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

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

4. Illustrative Example 14

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

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

Overhead Primary Conductor,” defined as: 17

2-9

The failure of or contact with energized electric distribution primary 1 conductor may result in public or employee safety issues, significant 2 environmental damage (fire), prolonged outages, or significant property 3 damage. Energized wires down events are also considered part of this 4 risk. 5

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

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

conjunction with an investigation that finds compliance violations such as 8

lack of signage, or insufficient clearance. 9

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

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

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

In this case, the following scores were assigned: 13

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

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

on industry data and experience. 16

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

1 (Negligible) impact on the environment. 18

Compliance impact: The scenario assumes a compliance violation, 19

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

industry experience. 21

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

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

described the potential impact. 24

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

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

location of the incident, were it to occur. 27

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

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

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

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

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

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

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

2-10

FIGURE 2-2 PACIFIC GAS AND ELECTRIC COMPANY

MAPPED RISK SCORE FOR OVERHEAD CONDUCTOR

D. Areas for Focus and Improvement 1

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

Informed by industry benchmarking studies, the recommendations of the 3

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

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

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

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

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

management attention. Senior management regularly engages in 9

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

increased the focus on developing and monitoring key measures that 11

provide insight into how risks are being managed. 12

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

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

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

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

strategies and resource allocation. 17

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

not to say there is no room for improvement. 19

Distribution Overhead Conductor Primary

2-11

2. Key Challenges 1

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

becomes available, operating and environmental conditions change, and 3

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

employees and the public. 21

a. Risk Quantification 22

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

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

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

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

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

implemented a risk management database to provide better oversight of 28

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

identifying data needs and fulfilling them by gathering information from 30

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

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

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

however. 34

2-12

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

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

educate the public about the dangers of contact with energized 3

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

b. Risk Tolerance 20

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2-13

investment in managing wildfire risk requires that customers either pay 1

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

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

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

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

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

and programs that have the largest risk reduction impact. 7

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

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

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

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

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

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

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

risk tolerance for PG&E. 15

3. Areas of Future Activities 16

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

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

current processes and improving the specific mechanics of risk 19

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

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

management through the use of effectiveness metrics. 22

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

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

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

Improve existing guidance and support for alternatives analysis and 26

documenting decisions related to mitigation activities. 27

Develop more effectiveness metrics that measure the impact of 28

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

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

or decreasing? 31

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

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

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

2-14

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

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

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

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

risk in our Integrated Planning Process. 5

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

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

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

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

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

identify and implement techniques for quantifying risk reduction and their 11

applicability to specific risks. 12

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 2

ATTACHMENT A

RISK EVALUATION TOOL (RET) ALGORITHM

2-AtchA-1

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)

]

2-AtchA-2

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 ( )

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 2

ATTACHMENT B

RISK ASSESSMENT CATEGORIES

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.

2-AtchB-1

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.

2-AtchB-2

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.

2-AtchB-3

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

2-AtchB-4

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.

2-AtchB-5

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

2-AtchB-6

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.

2-AtchB-7

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.

2-AtchB-8

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

COMPANYWIDE MODELS AND APPROACHES TO RISK

INFORMED BUDGET ALLOCATION

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

3-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 3 2

COMPANYWIDE MODELS AND APPROACHES TO RISK 3

INFORMED BUDGET ALLOCATION 4

A. Overview 5

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

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

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

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

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

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

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

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

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

year when budget tradeoff decisions are required due to changing 15

circumstances. 16

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

1. Purpose 18

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

budget decisions by risk scoring and categorizing proposed projects and 20

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

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

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

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

within and across the LOBs. 25

2. Approach and Methodologies 26

a. Personnel 27

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

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

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

3-2

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

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

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

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

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

b. Committees 6

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

representatives from Finance, Risk Management, Electric Operations, 8

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

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

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

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

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

Management (EORM) Program discussed in Chapter 2. 14

c. Processes and Timing 15

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

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

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

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

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

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

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

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

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

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

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

across the participating LOBs. These calibration sessions are attended 27

by representatives from Finance, Risk Management, and the 28

participating LOBs. 29

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

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

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

3-3

information about projects and programs are submitted to Finance in 1

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

these prioritization discussions when resource and other constraints 3

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

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

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

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

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

the upcoming year. RIBA scores and categorizations are used 9

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

changing circumstances. 11

FIGURE 3-1 PACIFIC GAS AND ELECTRIC COMPANY

PLANNING TIMELINE

3. The Model 12

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

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

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

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

compliance requirements, commitments and other considerations such as 17

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

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.

3-4

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

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

a. Inputs 3

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

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

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

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

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

with 1 being negligible impact and 7 being catastrophic: 9

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.

The process is as follows: 10

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

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

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

support the chosen score. 14

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

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

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

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

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

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

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

These flags provide additional information that informs budget 22

3-5

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

work.4 2

b. Outputs 3

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

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

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

presented to management graphically. A simulated graph for illustrative 7

purposes is shown below. 8

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.

3-6

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

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

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

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

Commitment flags are mutually exclusive and designed to capture all 5

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

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

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

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

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

means. 11

4. Illustrative Examples 12

The following projects illustrate the RIBA data and scoring of 13

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

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

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

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

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

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

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

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

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

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

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

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

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

assumptions provide an overall Safety Risk Score of 178. 27

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

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

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

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

3-7

school. These assumptions provide an overall Environmental Risk Score 1

of 1. 2

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

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

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

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

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

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

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

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

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

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

overall risk score of 357. 13

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

Aluminum Conductor Steel Reinforced overhead conductor with Aluminum 15

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

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

reduce the likelihood of a wire-down event. 18

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

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

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

of 178. 22

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

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

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

an overall Environmental Risk Score of 1. 26

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

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

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

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

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

3-8

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

overall Reliability Risk Score of 23. 2

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

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

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

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

overall risk score of 202. 7

C. Areas of Focus and Improvement 8

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

possible improvement for the RIBA process. 10

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

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

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

appropriate. The RIBA team will work closely with the EORM team to assure 14

that improvements made in the EORM program are incorporated into RIBA. 15

These types of improvements would include topics such as risk quantification 16

and risk tolerance. 17

Second, the RIBA team is working with PG&E’s Information Technology 18

Department to incorporate RIBA into SAP Project Portfolio Management (PPM), 19

which PG&E is currently implementing across the enterprise. PPM is an 20

end-to-end solution that will enable PG&E to plan and manage its portfolio of 21

work more effectively, efficiently and in a consistent manner across the entire 22

company. PPM will allow standardized planning and management of work at the 23

portfolio and program levels and will integrate the RIBA scoring model with other 24

work attributes such as cost, schedule, approval status, resource availability, 25

and accounting information. PPM will be integrated with SAP to facilitate rate 26

case, Session 1 and Session 2 planning and reporting. 27

Third, PG&E is exploring the practicality of extending the RIBA process to 28

other LOBs within PG&E. RIBA’s initial focus was asset based, and focused on 29

the core operational LOBs. The RIBA team is working with the investment 30

planning and risk teams in the other LOBs to develop a risk-informed 31

prioritization process that will improve the decision-making process in those 32

organizations. 33

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

ATTACHMENT A

SCORING TAXONOMY

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.

3-AtchA-2

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 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.

3-AtchA-3

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

3-AtchA-4

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.

3-AtchA-5

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

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

ATTACHMENT B

FLAG TAXONOMY

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.

Inter-relationships 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.

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 3

ATTACHMENT C

RISK-INFORMED BUDGET ALLOCATION TOOL ALGORITHM

3-AtchC-1

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

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.

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 4

ELECTRIC OPERATIONS AND NUCLEAR POWER

GENERATION

4-i

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

4-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 4 2

ELECTRIC OPERATIONS AND NUCLEAR POWER GENERATION 3

A. Introduction 4

This chapter describes how Pacific Gas and Electric Company’s (PG&E) 5

Electric Operations (EO) organization is using the Enterprise and Operational 6

Risk Management (EORM) Program to manage electric system risks. This 7

portion is sponsored by Eric Back, Director, Compliance and Risk Management 8

for Electric Operations. EO is responsible for the electric transmission and 9

distribution (T&D) systems, fossil, hydro, and other non-nuclear generating 10

facilities and energy procurement. 11

This chapter also describes how PG&E’s Nuclear Power Generation 12

organization is managing risks associated with PG&E’s nuclear facilities. 13

The nuclear portion is sponsored by Cary D. Harbor, Director, Compliance 14

Alliance and Risk for Nuclear Power Generation. 15

B. General Processes 16

1. Electric Operations 17

EO is implementing the EORM Program described in Chapter 2, 18

“Companywide Models and Approaches for Assessing Risk,” to manage 19

electric system risks. This program requires EO to identify, evaluate, 20

mitigate, and monitor risks. The process provides a repeatable and 21

consistent method of managing risks and is an important element of PG&E’s 22

Integrated Planning Process. Figure 4-1, is a high-level illustration of the 23

risk management framework. 24

4-2

FIGURE 4-1 PACIFIC GAS AND ELECTRIC COMPANY

RISK MANAGEMENT FRAMEWORK

The remainder of this EO section is organized as follows: 1

Organizational Structure – Describes EO risk management personnel 2

and committees. 3

Risk Register – Describes the codification of identified risks. 4

Risk Evaluation – Describes the tools EO uses to score items on the 5

Risk Register. 6

Risk Management Software Applications – Describes software 7

applications that PG&E is developing to assist with risk management 8

activities. 9

Risk Informed Budget Allocation (RIBA) – As generally described in 10

Chapter 3, the process EO uses to “risk score” projects and programs to 11

inform budgeting decisions. 12

In addition to the models described in Chapters 2 (Risk Evaluation Tool) 13

and 3 (RIBA), EO also uses a variety of tools (e.g., spreadsheets and 14

databases) that provide information regarding asset condition and in some 15

instances potential replacement priority. In some cases the information from 16

these tools is used to inform the models described in Chapters 2 and 3 and 17

is also used in analysis by subject matter experts (SME) during the risk 18

assessment process. 19

4-3

a. Organizational Structure 1

Chapter 2 describes how each line of business (LOB) has resources 2

dedicated to coordinating risk management activities within the LOB; 3

and collaborating on risk management activities across the LOBs. The 4

risk management organization within EO is the System Safety and Risk 5

team and consists of a senior manager and several full-time risk 6

analysts. This team reports to the Director for Compliance and Risk 7

Management, who reports to the Vice President for Electric Operations 8

Asset Management. 9

The System Safety and Risk team is responsible for implementing 10

the EORM Program for the following areas: 11

Electric Transmission Lines 12

Electric Transmission and Distribution Substations 13

Electric Distribution Lines 14

Non-Nuclear Power Generation Facilities 15

Energy Procurement 16

Items in the Risk Register (described in the next section) are 17

assigned to a risk owner (typically a director) who is responsible for 18

ensuring the accuracy of a risk’s evaluation and implementing risk 19

response plans and mitigations. SMEs working within EO assist the risk 20

owners and the EO System Safety and Risk team when evaluating risks 21

and creating risk response plans. 22

Also, EO has a Risk and Compliance Committee (RCC). The RCC 23

is chaired by EO’s Executive Vice President and is comprised of her 24

executive leadership team. This committee meets monthly to review 25

current risk-related topics and approve various items such as risk 26

assessments, risk mitigation measures, and changes to the 27

Risk Register. 28

b. Risk Register 29

PG&E uses risk registers to log and classify risks. The EO Risk 30

Register currently includes 72 risks.1 The risks are categorized as 31

1 For a full list of all risks sorted by score and category, see Attachment A of this chapter.

4-4

enterprise risks, asset risks, process risks, or energy policy risks. These 1

different types of risk are defined below. 2

Enterprise Risks (5): Enterprise risks are risks that could have a 3

catastrophic impact on PG&E if they were to occur. 4

Asset Risks (43): Risks that have consequences associated with 5

component failure or malfunction. These are further divided into: 6

Transmission Overhead Risks 7

Distribution Overhead Risks 8

Transmission and Distribution Underground Risks 9

Substation Risks 10

Power Generation Risks 11

Process Risks (14): Process-based risks have consequences 12

associated with business processes, programs, PG&E personnel, etc. 13

Energy Policy Risks (10): These risks are generally financial risks 14

related to bulk power operations, energy markets, portfolio 15

management, etc. 16

Examples of key public safety risks from the EO Risk Register 17

include wildfire, hydro system safety, and asset-related risks associated 18

with the electric T&D system. Energy policy and the majority of process 19

risks are not considered key public safety risks. 20

c. Risk Evaluation 21

EO uses two tools to evaluate items on the Risk Register: 22

The Risk Evaluation Tool (RET) 23

Risk Assessments 24

1) Application of RET to Electric Operations 25

EO uses RET, described in Chapter 2, Section C, to establish a 26

risk score for each risk in the Risk Register. For the majority of 27

uses, EO uses the RET as directed by the EORM Program and no 28

modifications are made to the algorithm, frequency scales, or impact 29

group weightings. While EO does not modify the RET model itself, 30

a variety of data and judgment are inherent when applying the 31

frequency and impact scales of the model and in the formulation of 32

4-5

the P95 scoring scenarios.2 How the RET is used in EO’s risk 1

assessment process is described more fully in the next section. 2

It is important to note that there are distinctions between (i) Risk 3

Register scores, (ii) program/project risk scores (which are 4

discussed later in the Risk Informed Budget Allocation section of this 5

chapter), and (iii) an individual asset risk score which is discussed in 6

the System Tool for Asset Risk (STAR) and Generation Risk 7

Information Tool (GRIT) sections, later in this chapter. 8

2) Risk Assessments 9

The purpose of a risk assessment is to identify potential hazards 10

and analyze what might happen if a hazard event occurs. Within 11

EO, risk assessments are used to provide a systematic 12

understanding of the items on the Risk Register. 13

EO uses a common framework to perform risk assessments and 14

upon completion, the assessments are presented to the EO RCC for 15

review and approval of the Risk Register scores and recommended 16

mitigations. 17

The components of a risk assessment include: 18

Risk definition and scope 19

A scoring scenario (the “P95” scenario) and the application of the 20

RET to determine a Risk Register score 21

Identification of risk drivers and consequences 22

Identification and assessment of risk controls 23

Identification of current gaps and potential mitigations 24

Assessments typically take 60 to 90 days to complete, and are 25

performed by a team of SMEs led by a risk analyst from the System 26

Safety and Risk Management team. The team compiles and analyzes 27

data from a variety of sources (e.g., asset condition data, event reports, 28

reliability data, etc.) to perform the assessment. 29

The team also identifies and assesses existing controls and 30

identifies potential new mitigations (or strengthening of existing controls) 31

during the assessment. Periodic reviews with the risk owner are 32

2 See Chapter 2, Section C for a definition.

4-6

conducted during the assessment. Decisions regarding what mitigations 1

to recommend to the RCC are often made during these sessions. After 2

the RCC approves a risk assessment, the approved mitigations are 3

tracked to ensure completion. 4

EO is currently working to complete a formal risk assessment for all 5

items on the Risk Register. When all the risk assessments are 6

completed, EO will have established a common basis for relative risk 7

scores for assets, processes, and events that rely on a common 8

framework, particularly with respect to the application of the RET for 9

scoring. 10

Illustrative Example: The example below—on overhead conductor 11

risk—demonstrates aspects of the EO risk assessment process. This 12

information is taken from the distribution primary overhead conductor 13

risk assessment, which was presented to the EO RCC on November 14, 14

2013.3 15

Risk Name: Distribution Primary Overhead Conductor. 16

Risk Definition: Failure of or contact with, energized electric 17

distribution primary conductor may result in public or employee safety 18

issues, significant environmental damage (fire), prolonged outages, or 19

significant property damage. 20

Scenario Evaluated (P95): A fatality due to unintentional contact, 21

such as by a third-party tree worker, with an in-place conductor, 22

partnered with an investigation that finds a compliance violation such as 23

lack of signage, or insufficient clearance. Energized wire-down events 24

are also considered as part of this risk. 25

As part of the risk assessment, the team identified types of events 26

that could occur: (1) contact with intact wire (or conductor situated in 27

proper operating position); or (2) contact with a wire that has fallen 28

down. Figure 4-2 displays the list of controls identified during this risk 29

assessment sorted by the type of conductor contact that could occur. 30

3 Attachment B of this chapter contains excerpts from the risk assessment for primary

overhead conductor.

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

Figure 4-3 contains a list of additional mitigations approved as a 1

result of this risk assessment. These mitigations are also sorted by the 2

type of conductor contact that could occur. 3

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

These controls and mitigations represent the work that PG&E 1

performs to address PG&E’s distribution overhead conductor primary 2

risk. Other ongoing work such as line patrols and the daily operations of 3

vegetation management also contributes to the mitigation of this risk. 4

d. Risk Management Software Applications 5

PG&E’s electric system is extensive, including: 142,000 miles of 6

distribution lines; 18,600 miles of transmission lines; 855 substations; 7

107 hydro generating units at 67 powerhouses; 170 dams; 8

approximately 368 miles of conveyance facilities (including canals, 9

flumes, tunnels, pipes, and natural waterways); 93 total penstocks; and 10

3 fossil generating stations. 11

Within these systems and facilities there are millions of individual 12

assets with a variety of processes and analytical methodologies to 13

manage risk. While risk management processes and methods are 14

becoming more uniform, a more systematic and consistent approach 15

that integrates the concepts of probability and severity for asset failures 16

4-9

is needed. Towards this end, PG&E is developing software applications 1

that will serve as platforms to drive consistency and improve risk 2

management within and across asset classes. 3

1) System Tool for Asset Risk 4

The software that PG&E is developing to address transmission 5

and distribution assets is the System Tool for Asset Risk (STAR). 6

When fully developed, the STAR application is envisioned to be the 7

source system for risk elements (e.g., asset health indices, risk 8

impact factors and resultant risk scores)4 for asset classes 9

(e.g., poles, transformers, and conductors) that can have a 10

significant impact on safety, reliability, and the environment. The 11

STAR platform will: 12

Calculate asset health indices and risk scores 13

Represent the indices and scores geospatially and graphically 14

Facilitate risk analysis at an asset and system level 15

STAR will accomplish this by automating the collection of data 16

from a variety of sources (e.g., geospatial information systems, 17

financial and asset management systems, equipment condition 18

databases) to standardize and facilitate the risk calculations across 19

the EO T&D asset base. The system will be flexible and enable an 20

evolutionary process in both risk calculations and new data sources 21

as they are identified. Ultimately, the application would be an 22

integral part of the risk management process within EO. 23

Since STAR will draw data from existing sources, PG&E 24

anticipates that information gathering methods related to asset 25

characteristics and condition will generally remain the same. 26

Examples include: 27

Substation Assets – Dissolved gas analysis tests, equipment 28

test results, loading history, substation inspection results, input from 29

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.

4-10

substation maintenance personnel and asset characteristics such as 1

equipment manufacturer, year installed, etc. 2

Transmission and Distribution Line Assets – Pole test and 3

treat programs, General Order 165 patrol and inspection programs, 4

equipment inspection results, load flow programs, transformer 5

loading programs, vegetation management information, and asset 6

characteristics such as equipment size and type, manufacturer, year 7

installed, etc. 8

To support the STAR effort, PG&E has used Electric Program 9

Investment Charge (EPIC)5 funding to create a prototype of the 10

application. The STAR prototype calculates and visually displays 11

risk scores at an individual asset level for electric distribution wood 12

poles, overhead primary conductor line sections, distribution circuit 13

breakers and distribution substation transformers for a portion of 14

PG&E’s territory. By creating a prototype of STAR as part of the 15

EPIC Program, it has been possible to research, develop, and 16

demonstrate risk scoring processes and algorithms. Figure 4-4 17

shows sample screenshots from the STAR prototype. 18

5 EPIC funding provides public interest investments in the areas of applied research and

development and technology demonstration and deployment.

4-11

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.

4-12

STAR will take several years to implement across all of EO 1

T&D. The implementation will likely face challenges in the areas of 2

data availability and consistency, interfacing with existing 3

applications, and the creation of algorithms. When complete, the 4

STAR tool will provide risk scores for EO T&D facilities that asset 5

management personnel will use to identify work and develop asset 6

strategies. PG&E anticipates that, as improvements in data quality 7

and analytic capabilities occur, the algorithms for asset health 8

indices and risk scores will also evolve. 9

2) Generation Risk Information Tool 10

The software application being developed for PG&E’s fossil, 11

hydro, and other non-nuclear generating facilities is the Generation 12

Risk Information Tool (GRIT). GRIT is an integrated asset 13

management application which provides data centralization, 14

standardization of asset management scoring, asset risk trending, 15

improved reporting, and analytics. GRIT interfaces with SAP Work 16

Management and is designed for logging, planning, and reporting on 17

assessments (tests, inspections, reviews, calculations, etc.), asset 18

condition indicators, and asset health and consequence scores. 19

Consequence scores are in line with the RET,6 as described earlier 20

in Section B of this chapter. Lastly, GRIT also tracks risk mitigation 21

activities, including projects, maintenance, and operational changes. 22

The GRIT application organizes and displays condition and 23

consequence data on equipment within major hydro areas. These 24

equipment records are categorized by program and geography. The 25

GRIT prototype became operational in 2014, and has 15 hydro 26

asset types in the tool today, with more expected soon. 27

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.

4-13

e. Risk Informed Budget Allocation 1

Chapter 3 describes PG&E’s Risk Informed Budget Allocation 2

(RIBA) process. EO uses RIBA as part of PG&E’s Integrated Planning 3

Process. 4

EO generally uses RIBA as directed by PG&E’s Finance 5

organization (i.e., no modifications to the frequency scales or the impact 6

groups of safety, reliability or environment). 7

2. Nuclear Power Generation 8

Risk is managed for Nuclear Power Generation by the Compliance and 9

Risk Department. The director of this department reports directly to the 10

Senior Vice President, Chief Nuclear Officer. Within the Compliance and 11

Risk Department, approximately two full time employees are focused on risk 12

issues. Their responsibilities include coordination of policies and 13

procedures developed to identify, quantify and mitigate or manage risk. Like 14

EO, Nuclear Power Generation maintains its own Risk Register, and 15

prepares Session D risk analyses as part of the Integrated Planning Process 16

previously described. 17

The tools used by Nuclear Power Generation to manage risk include the 18

RET and RIBA processes discussed above and in Chapters 2 and 3 of this 19

testimony. In addition, Nuclear Power Generation implements a number of 20

additional risk management tools specific to nuclear generation. These 21

tools are often prescribed by the Nuclear Regulatory Commission (NRC), 22

which provides extensive oversight of a broad range of plant activities.7 23

Some of the key additional procedures and risk tools used specifically at 24

the Diablo Canyon Power Plant (DCPP) include: 25

1) Probabilistic Risk Assessment. This tool is used to assess 26

vulnerabilities to a wide range of events and to risk-inform decisions and 27

changes, including priority, type, and controls applied to such activities. 28

2) A robust risk-informed work management program provides appropriate 29

priorities for performing maintenance on permanent plant equipment and 30

requires detailed instructions to assure the proper performance of 31

7 These tools are subject to the jurisdiction of the NRC and are provided here for

informational purposes.

4-14

maintenance, including specification of in-process and post- 1

maintenance quality checks, proper specification of materials to be 2

used, and post-maintenance testing to confirm functionality of 3

equipment following maintenance. 4

3) The NRC maintenance rule (10 Code of Federal Regulations 5

(CFR) 50.65) requires the reliability of permanent plant equipment 6

critical to mitigation of upset conditions or whose failure could cause 7

plant transients to be monitored, and actions initiated (such as increased 8

preventive maintenance or testing) to meet minimum reliability 9

standards. 10

4) DCPP maintains a robust corrective action program as required by 11

10 CFR 50 Attachment B to assure that performance shortcomings are 12

identified, captured, and evaluated for corrective action. 13

5) Diablo Canyon procedure ER1-DC1, “Component Classification,” 14

requires items whose failure could result in a plant trip, loss of 15

generation, or other plant level important function, to be flagged and 16

requires high levels of preventive maintenance to ensure equipment 17

reliability. 18

C. Areas of Focus and Improvement 19

1. Electric Operations 20

Though much progress has been made thus far, EO anticipates future 21

refinement of our risk management program. Potential areas of future focus 22

include: 23

Improving Quantitative Rigor Associated With Likelihood of Asset 24

Failure. To the extent possible, EO believes it is better to develop and 25

rely on leading rather than lagging asset failure indicators. This will 26

allow EO to predict and address failures before they occur and therefore 27

reduce the need for emergency replacement activity. Steps that can aid 28

in facilitating this goal include: (1) improving the collection and tracking 29

of asset health metrics; and (2) collaborating across the utility industry to 30

establish models that better predict asset failure. A continued focus on 31

strengthening the collection and tracking of metrics related to asset 32

health will improve process integrity, while EO works to establish 33

4-15

predictive indicators. Collaboration across the industry will be important 1

to setting the stage for validating new predictive indicators. 2

Implement STAR. STAR’s analytics-centered asset management 3

approach is designed to continuously update risk scores based on 4

regular updates to source data systems. STAR will: (1) allow EO to 5

incrementally update asset-level, and ultimately system-level, risk 6

scores; (2) facilitate the use of asset analytics to drive proactive asset 7

replacement; and (3) create a platform to better collect and track asset 8

health metrics. The continuous incremental updating of asset risk 9

scoring through the use of STAR can be used to strengthen financial 10

planning. This will be done by linking STAR to RIBA directly, thus 11

allowing STAR to inform financial planning through the Integrated 12

Planning Process. 13

Enhance GRIT. In future phases, data from additional sources will be 14

linked to GRIT to aid Power Generation users in making informed 15

decisions about equipment replacement and project costs. New 16

functionality (including a dashboard) will be built and GRIT will be further 17

integrated with other systems. Lastly, three to five more asset types will 18

be added to the system. 19

Further Develop and Refine the EO Risk Register to Address 20

Interactive Threats. To date, the EO risk assessment process has 21

focused primarily on an in-depth examination of individual risks and 22

individual risk drivers or threats. This method does not account for the 23

interaction between multiple risks and threats. With this in mind, EO will 24

consider ways to better understand the relationship between multiple 25

risks and/or multiple threats. 26

Improving the Relationship Between Risks and Expenditures. 27

Establishing a link between risks and expenditures for controls and 28

mitigations will help EO to better communicate how its expenditure 29

portfolios align with the Risk Register. 30

2. Nuclear Power Generation 31

Though much progress has been made thus far, Nuclear Power 32

Generation anticipates future expansion and refinement of our risk 33

management program. Potential areas of future focus may include: 34

4-16

Further Develop and Refine the Nuclear Power Generation Risk 1

Register to Expand the Population for Review. To date, the Nuclear 2

Power Generation risk assessment process has focused primarily on 3

major projects. Approximately 140 in-flight projects and major projects 4

in the long-term plan have been risk assessed. An additional 5

71 projects have been identified for risk assessment to be completed 6

over the next several months. Procedures for project review have been 7

modified to require all new projects to complete this risk assessment 8

before funds are committed beyond initial project scoping efforts. 9

Training materials for project managers and project leadership are also 10

being developed to ensure appropriate impact criteria are considered 11

and scoring is consistently applied. 12

Improving the Relationship Between Risks and Expenditures. 13

Establishing a stronger link between risks and required project 14

contingency will help Nuclear Power Generation better communicate 15

risks associated with the expenditure portfolio. 16

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 4

ATTACHMENT A

ELECTRIC OPERATIONS RISK REGISTER

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Pro

tect

ion

an

d C

on

tro

l Sys

tem

s 3

7

57

Fo

ssil

Hig

h E

ner

gy S

yste

ms

33

58

Su

bst

atio

n V

olt

age

and

Flo

w C

on

tro

l Eq

uip

men

t 3

2

59

Tr

ansm

issi

on

Ove

rhea

d S

wit

ches

3

2

60

D

istr

ibu

ted

Gen

erat

ion

3

1

#

Ris

k N

ame

C

urr

en

t R

esi

du

al

Ris

k Sc

ore

61

D

istr

ibu

tio

n U

nd

ergr

ou

nd

Su

bsu

rfac

e an

d P

ad-

Mo

un

t Tr

ansf

orm

ers

31

62

Fo

ssil

Pro

tect

ion

an

d C

on

tro

l Sys

tem

s 2

7

63

D

istr

ibu

tio

n O

verh

ead

Str

eetl

igh

t St

ruct

ure

s 2

5

64

D

istr

ibu

tio

n O

verh

ead

Lin

e Eq

uip

men

t –

Pro

tect

ive

2

4

65

Fo

ssil

Bal

ance

of

Pla

nt

23

66

H

ydro

Bal

ance

of

Pla

nt

23

67

D

istr

ibu

tio

n O

verh

ead

Lin

e Eq

uip

men

t –

Vo

ltag

e R

egu

lato

rs, B

oo

ster

s, a

nd

Cap

acit

ors

1

8

68

D

istr

ibu

tio

n O

verh

ead

Tra

nsf

orm

ers

18

69

Fu

el C

ell S

yste

ms

18

70

P

ho

tovo

ltai

c Sy

stem

s 1

8

71

Su

bst

atio

n G

rou

nd

ing

Syst

ems

18

72

H

ydro

Mat

eri

al R

elea

se in

to W

ate

r 1

3

No

te:

The

Elec

tric

Op

erat

ion

s R

isk

Reg

iste

r is

a d

ynam

ic d

ocu

men

t.

Ris

ks a

nd

ris

k sc

ore

s ca

n c

han

ge.

4-AtchA-2

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 4

ATTACHMENT B

RISK ASSESSMENT EXAMPLE

Ris

k A

sses

smen

t Exa

mpl

e:

Prim

ary

Ove

rhea

d C

ondu

ctor

The

follo

win

g do

cum

ent c

onta

ins

exce

rpts

from

PG

&E’

s ris

k as

sess

men

t on

Prim

ary

Ove

rhea

d C

ondu

ctor

s co

nduc

ted

in N

ovem

ber o

f 201

3.

4-AtchB-1

Syst

em S

afet

y –

Ove

rhea

d Pr

imar

y C

ondu

ctor

s

Nov

embe

r 201

3

•D

efin

eo

Ris

k D

efin

ition

and

Sco

pe

•M

easu

reo

Ass

et O

verv

iew

•A

naly

zeo

Bow

Tie

Ana

lysi

so

Ove

rhea

d P

rimar

y E

vent

so

Con

tact

with

“Int

act”

Ene

rgiz

edC

ondu

ctor

so

Vege

tatio

no

Con

tact

with

Wire

s D

own

oC

urre

nt C

ontro

l Miti

gatio

nso

Cur

rent

Con

trols

Ass

essm

ent

•Im

prov

eo

Rec

omm

enda

tions

oA

sses

smen

t of P

ropo

sed

Con

trols

•A

ppen

dix

4-AtchB-2

Ris

k D

efin

ition

and

Sco

pe

Ris

k D

efin

ition

: Fa

ilure

of o

r con

tact

with

, ene

rgiz

ed e

lect

ric

dist

ribut

ion

prim

ary

cond

ucto

r res

ults

in p

ublic

or

empl

oyee

saf

ety

issu

es, s

igni

fican

t env

ironm

enta

l da

mag

e, p

rolo

nged

out

ages

, or s

igni

fican

t pr

oper

ty d

amag

e

In S

cope

•

All 2

.4kV

to 2

1kV

dist

ribut

ion

over

head

con

duct

ors

incl

udin

g sp

lices

, con

nect

ors

and

jum

pers

•Ev

ents

invo

lvin

g in

-pla

ce a

sset

s op

erat

ing

as-

desi

gned

and

failu

re o

r wire

dow

n•

Even

t con

sequ

ence

s in

term

s of

inju

ry/fa

talit

ies

and

prop

erty

dam

age,

incl

udin

g no

n-ca

tast

roph

ic fi

res

Out

of S

cope

•

Supp

ort s

truct

ures

•Tr

ansm

issi

on a

nd s

econ

dary

ove

rhea

d co

nduc

tors

•Sy

stem

pro

tect

ion

•Ig

nitio

n of

cat

astro

phic

wild

fire

Prim

ary

Ove

rhea

d C

ondu

ctor

s

Impa

ct

Probability

Ris

k P

riorit

izat

ion

Cut

off L

ine

0102030405060708090100

01

23

45

Res

idua

l Ris

k H

eat M

ap

Prim

ary

O

verh

ead

Con

duct

or

Ana

lysi

s in

pro

gres

s, ri

sk s

tatu

s un

know

n

Cur

rent

con

trols

not

suf

ficie

nt

Cur

rent

con

trols

not

suf

ficie

nt, n

ew c

ontro

ls a

re

bein

g im

plem

ente

d C

urre

nt c

ontro

ls a

re s

uffic

ient

4-AtchB-3

Ass

et O

verv

iew

Con

duct

or S

ize

(sm

all t

o la

rge)

N

umbe

r of

Circ

uit M

iles

Perc

ent o

f To

tal

6 C

u22

,157

20%

4 C

u6,

310

6%4

ACSR

47,5

5542

%2

ACSR

9,83

69%

2 C

u3,

826

3%1/

0 AC

SR1,

791

2%1/

0 C

u2,

105

2%4/

0 Al

5,08

14%

397

Al5,

435

5%71

5 Al

4,97

04%

Oth

er S

izes

4,38

14%

Tota

l 11

3,44

7 10

0%

•11

3,50

0 ov

erhe

ad c

ircui

t mile

s

•A

CS

R --

53%

•C

oppe

r -- 3

1%

•A

lum

inum

-- 1

3%

•91

,000

circ

uit m

iles

smal

ler t

han

1/0

•27

% o

f con

duct

ors

olde

r tha

n 50

yrs

“Oth

er S

izes

” inc

lude

app

roxi

mat

ely

250

mile

s of

cop

perw

eld

cond

ucto

r and

ver

y sm

all s

izes

(i.e

., 8

Cu)

– T

his

is li

kely

ver

y ol

d co

nduc

tor.

Woo

d Po

le A

ge a

s a

Prox

y fo

r Con

duct

or A

ge

Prim

ary

Ove

rhea

d C

ondu

ctor

s

33

%

18

%

19

%

16

%

9%

5%

0%

5%

10

%

15

%

20

%

25

%

30

%

35

%

> 5

0 y

rs4

0-5

0 y

rs3

0-4

0 y

rs2

0-3

0 y

rs1

0-2

0 y

rs<

10

yrs

4-AtchB-4

Bow

Tie

Ana

lysi

s

Fata

lity

Inju

ry

Fire

Third

par

ty:

•Fo

reig

n ob

ject

•C

onst

ruct

ion

Equi

pmen

t•

Non

PG

&E W

orke

r

Inta

ct

Con

duct

or

Even

t

PG&E

Em

ploy

ee:

•W

PE

Equi

pmen

t Fai

lure

: •

Con

duct

or/s

plic

e•

Cor

rosi

on

Vege

tatio

n:

•C

ompl

iant

tree

s•

Non

com

plia

nt tr

ees

Pro

perty

Dam

age

Fata

lity

Inju

ry

Fire

Third

par

ty:

•Ve

geta

tion

•N

on P

G&E

Wor

ker

Wire

Dow

n C

ondu

ctor

Ev

ent

PG&E

Em

ploy

ee:

•W

PE

Anim

al

Con

sequ

ence

s D

river

s

Anim

al

Vege

tatio

n:

•C

ompl

iant

tree

s•

Non

com

plia

nt tr

ees

Pro

perty

Dam

age

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-5

OH

Prim

ary

Con

duct

ors

is S

econ

d Le

adin

g C

ause

of I

njur

y/Fa

talit

y Ev

ents

(ca

r pol

e is

1st

)

•86

inju

ry/fa

talit

y an

d pr

oper

tyda

mag

e ev

ents

in th

e pa

st e

ight

year

s in

volv

ed o

verh

ead

prim

ary

cond

ucto

rso

62 in

tact

faci

litie

so

24 w

ire d

own

•O

f the

86

even

ts, t

here

wer

e 29

fata

litie

s•

20 p

rope

rty d

amag

e (>

$50k

) eve

nts

o14

cau

sed

by w

ires

dow

n, fi

ve b

y 3r

d

party

and

one

by

PG

&E

con

tract

or

Inju

ry/F

atal

ity a

nd T

hird

Par

ty P

rope

rty

Dam

age

OH

Prim

ary

Con

duct

or --

200

5 to

201

2

Cat

egor

y 20

05

2006

20

07

2008

20

09

2010

20

11

2012

To

tal

Third

Par

ty In

jury

/Fat

ality

14

8

6 7

5 5

6 7

58

PG

&E

Inju

ry/F

atal

ity

1 2

0 2

1 1

1 0

8 Th

ird P

arty

Pro

perty

Dam

age

2 4

3 3

4 2

1 1

20

Tota

l 17

14

9

12

10

8 8

8 86

Inju

ry/F

atal

ity a

nd P

rope

rty

Dam

age

Even

ts

Invo

lvin

g O

H P

rimar

y C

ondu

ctor

-- 2

005

to 2

012

50

5

7

62

8

3

13

24

0

20

40

60

80

Thir

d P

arty

Inju

ry/F

atal

ity

Eve

nt

PG

&E

Inju

ry/F

atal

ity

Eve

nt

Pro

per

ty D

amag

eEv

en

tTo

tal E

ven

ts

Inta

ctW

ire

Do

wn

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-6

Con

tact

with

“In

tact

” En

ergi

zed

Prim

ary

Con

duct

or in

its

Nor

mal

Sta

te

•Th

ird p

arty

: 50

eve

nts

over

8 y

ears

; 22

fata

litie

s, 2

9 in

jurie

s

•P

G&

E E

mpl

oyee

s: 5

eve

nts

over

8 y

ears

; 2 fa

talit

ies,

3 in

jurie

so

3 ev

ents

– 1

dire

ct c

onta

ct, 2

whi

le in

stal

ling/

repl

acin

g fa

cilit

ies

o2

even

ts w

ith d

igge

r der

rick

boom

s

Prim

ary

Ove

rhea

d C

ondu

ctor

s

Fore

ign

Obj

ects

: 32

Eve

nts

Vehi

cles

stri

king

pol

es,

cons

truct

ion

equi

pmen

t co

ntac

ting

prim

ary

lines

, airc

raft,

pi

pes,

ant

enna

, ste

el b

eam

, pi

pes,

sur

vey

rod,

and

rain

gu

tters

/dow

n sp

outs

Th

eft a

nd O

ther

s: 6

Eve

nts

Atte

mpt

ed w

ire th

eft o

r un

auth

oriz

ed c

limbi

ng

Non

-PG

&E

Per

sonn

el:

12 E

vent

s Tr

ee tr

imm

ers

and

com

mun

icat

ion

wor

kers

4-AtchB-7

Loca

tion

of 3

rd P

arty

Con

tact

with

Con

duct

or

OH

Prim

ary

Third

Par

ty In

jury

/Fat

ality

Ev

ents

by

Cou

nty

2005

to 2

012

Cou

nty

Num

ber o

f Ev

ents

San

ta C

lara

6

Mad

era

5 S

an L

uis

Obi

spo

5 S

anta

Cru

z 4

Con

tra C

osta

3

El D

orad

o 3

Fres

no

3 M

onte

rey

3 S

an M

ateo

3

Sut

ter

3

Subt

otal

of 1

0 C

ount

ies

38

13 C

ount

ies

with

1 o

r 2 e

vent

s 20

25

Cou

ntie

s w

ith z

ero

even

ts

0

Syst

em T

otal

58

•P

G&

E c

over

s 48

cou

ntie

so

38 e

vent

s in

10

coun

ties

o20

eve

nts

in 1

3 ot

her c

ount

ies

oN

o ev

ent i

n 25

cou

ntie

s

•N

o st

rong

rela

tions

hip

betw

een

even

t cau

ses

and

loca

tion

•S

anta

Cla

ra, M

ader

a, S

an L

uis

Obi

spo

and

San

ta C

ruz

are

the

coun

ties

with

the

mos

tev

ents

:•

Non

-PG

&E

wor

ker a

ccou

nted

for h

alf o

fth

e S

anta

Cla

ra e

vent

s•

Fore

ign

obje

cts

are

the

maj

or c

ause

inM

ader

a, S

an L

uis

Obi

spo

and

San

ta C

ruz

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-8

Wire

Dow

n C

ondu

ctor

Eve

nt --

Driv

ers

Four

Bas

ic C

ause

s of

Wire

Dow

n

•E

quip

men

t fai

lure

oC

ondu

ctor

s, s

plic

es, c

onne

ctor

s, ju

mpe

rs

•“C

ompl

iant

” veg

etat

ion

still

cre

ate

wire

s do

wn

o90

% o

f veg

etat

ion-

rela

ted

wire

dow

n in

volv

e a

tree,

tree

-bra

nch,

or t

ree

bark

falli

ng o

n th

e lin

efro

m o

utsi

de th

e re

quire

d cl

eara

nce

dist

ance

o<

5% d

ue to

tree

gro

win

g in

to li

ne o

r PG

&E

cont

ract

or tr

imm

ing

•Th

ird-p

arty

-initi

ated

oVe

hicl

e/po

le (7

2%)

oB

allo

ons

(9%

)o

3rd p

arty

con

tact

(4%

)o

Gun

sho

t (4%

)o

Oth

er (1

1%) s

prea

d ov

er s

even

sub

-cat

egor

ies

•A

nim

al in

itiat

edo

Bird

(78%

)o

Squ

irrel

(12%

)o

Oth

er (1

0%)

An

imal

, 4

% Eq

uip

men

t Fa

ilure

/In

, 3

8%

Thir

d p

arty

, 1

4%

Veg

etat

ion

, 4

3%

2008

-201

2 W

ire D

own

by B

asic

Cau

se

2008

20

09

2010

20

11

2012

To

tal

Vege

tatio

n 74

6 80

2 76

9 68

0 1,

202

4,19

9 Eq

uipm

ent F

ailu

re

743

623

653

604

1,11

8 3,

741

Third

par

ty

174

197

218

210

541

1,34

0 An

imal

74

75

72

74

10

1 39

6 C

ompa

ny In

itiat

ed

7 5

6 5

16

39

Unk

now

n ca

use

9 6

16

31

Tota

ls

1,75

3 1,

708

1,73

4 1,

573

2,97

8 9,

746

•20

12 o

utag

e re

porti

ng e

nhan

cem

ent s

igni

fican

tly in

crea

sed

the

num

ber o

f out

ages

and

acc

urac

y re

porte

d w

ith w

ire-d

own.

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-9

Wire

Dow

n - I

njur

y/Fa

talit

y &

Pro

pert

y D

amag

e

Prim

ary

Ove

rhea

d C

ondu

ctor

s

3rd P

arty

Fat

ality

/Inju

ry

PG

&E E

mpl

oyee

Fa

talit

y/In

jury

P

rope

rty D

amag

e

8 ev

ents

4

fata

litie

s, 5

inju

ries

3 ev

ents

1

fata

lity,

2 in

jurie

s 14

eve

nts

•3

vege

tatio

n•

1 bi

rd•

1 st

ruct

ure

fire

(fire

fight

er)

•1

snow

sto

rm•

1 w

ild la

nd fi

re (f

irefig

hter

)•

1 co

nduc

tor c

onta

ctin

g gu

ywire

(com

mun

icat

ion

wor

ker)

•1

tree

fell

on c

ondu

ctor

(inj

ury,

Janu

ary

2006

).•

1 co

nduc

tor c

onta

ctin

g x-

arm

(fata

lity,

Jan

uary

200

8)•

1 gu

y w

ire w

rapp

ed w

ithpr

imar

y co

nduc

tor f

ollo

win

g ca

rhi

tting

dow

n gu

y (in

jury

,D

ecem

ber 2

008)

•5

cond

ucto

r fai

lure

s•

4 ve

geta

tion

•2

pole

fire

s•

1 bi

rd•

1 eq

uipm

ent c

onne

ctor

•1

pole

failu

re

2005

to 2

012

4-AtchB-10

Wire

s D

own

-- Ve

geta

tion

Inju

ries/

Fata

litie

s •

3 co

ntac

ts a

s a

resu

lt of

a v

eget

atio

n re

late

d w

ire d

own

Fire

Igni

tions

•

Num

ber o

f eve

nts

is d

ecre

asin

g. T

ypic

al e

vent

invo

lves

less

than

10

acre

s bu

t the

pos

sibi

lity

of a

cat

astro

phic

fire

ex

ists

:

oS

outh

ern

Cal

iforn

ia:

2008

Witc

h C

reek

, Gue

jito

and

Ric

efir

es (S

DG

&E

) and

Mal

ibu

Can

yon

Fire

(SC

E)

oP

G&

E:

2008

Whi

skey

Fire

- 7,

783

acre

s (T

eham

a co

unty

)

•Th

e ris

k of

cat

astro

phic

wild

fire

will

be

addr

esse

d as

par

tth

e en

terp

rise

risk

man

agem

ent a

sses

smen

t

•S

yste

m P

rote

ctio

n w

ill h

ave

a se

para

te ri

sk a

sses

smen

tan

d w

ill in

clud

e a

reco

mm

enda

tion

to re

view

recl

ose

rela

yse

tting

s in

UW

F/O

WF/

SB

WF

area

s

Pro

perty

Dam

age

•4

prop

erty

dam

age

even

ts d

ue to

veg

etat

ion

rela

ted

wire

dow

n

10

3

89

73

11

0

60

6

7

86

8

7

50

63

5

3

0

20

40

60

80

10

0

12

0

Vege

tatio

n-R

elat

ed Ig

nitio

ns --

200

1 to

201

2

Data not collected

Fire

Siz

e N

umbe

r

≤ 10

acr

es

338

10 to

100

acr

es9

100

to 1

,000

acr

es3

1,00

0 to

10,

000

acre

s1

> 10

,000

acr

es0

Tota

l 35

1

OH

Prim

ary

Con

duct

or

Fire

s by

Siz

e 20

07 to

201

2

1 ac

re ≈

1 fo

otba

ll fil

ed

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-11

•Th

e sy

stem

ave

rage

of w

ire d

own

even

ts d

ue to

equ

ipm

ent f

ailu

re is

0.7

7 pe

r 100

mile

s

•E

ast B

ay, S

an F

ranc

isco

, Pen

insu

la, C

entra

l Coa

st a

nd S

acra

men

to h

ave

valu

es >

150

% o

f the

syst

em a

vera

ge.

Exc

ept f

or S

acra

men

to, a

ll th

e di

visi

ons

have

cor

rosi

on a

reas

.

Wire

Dow

n --

Equi

pmen

t Fai

lure

0.4

9

0.4

9

0.5

1

0.5

4

0.5

8

0.5

9

0.6

7

0.7

3

0.7

3

0.7

6

0.8

9

0.9

1

0.9

2

1.0

0

1.1

9

1.2

7

1.5

5

1.7

6

1.9

8

-

0.5

0

1.0

0

1.5

0

2.0

0

2.5

0

WD per 100 miles of OH Conductor

Wir

e-D

ow

n p

er

10

0 M

iles

of

OH

Co

nd

uct

or

(20

12

- 2

01

3 E

qu

ip F

ailu

re R

ela

ted

)

syst

em

ave

rage

= 0

.77

per

10

0 M

ile

•W

ire s

ize,

type

and

loca

tion

are

attri

bute

s

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-12

Con

duct

or S

ize

•S

ma

ll w

ire

(< 1

/0) w

ire d

own

rate

is 9

% h

ighe

r tha

n th

e sy

stem

ave

rage

(0.8

4 vs

. 0.7

7)

Con

duct

or T

ype

•Th

e pe

rform

ance

of c

op

per

cond

ucto

r is

sign

ifica

ntly

wor

se th

an th

e sy

stem

val

ue(1

.15

vs. 0

.77)

Cor

rosi

on Z

one

•Th

e pe

rform

ance

of c

ondu

ctor

s in

co

rro

sio

n z

ones

is w

orse

than

non

-cor

rosi

on z

ones

o6

Cu

is e

stim

ated

to b

e 2.

5 tim

es h

ighe

r in

corr

osio

n zo

neo

4 A

CS

R is

est

imat

ed to

be

13 ti

mes

hig

her i

n co

rros

ion

zone

•Th

e fo

llow

ing

divi

sion

s ha

ve c

orro

sion

zon

es

Equi

pmen

t Rel

ated

Wire

Dow

n - A

ttrib

utes

H

umbo

ldt

P

enin

sula

S

onom

a

Cen

tral C

oast

N

orth

Bay

Lo

s P

adre

s

Mis

sion

S

an F

ranc

isco

E

ast B

ay

•S

ix o

f the

se d

ivis

ions

hav

e w

ire d

own

rate

s gr

eate

r tha

n th

e sy

stem

ave

ragePrim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-13

Attr

ibut

es T

hat P

oten

tially

Incr

ease

the

Con

sequ

ence

s of

a W

ire D

own

Even

t

Attr

ibut

e #

6 C

u #

4 C

u

Oth

er S

mal

l C

oppe

r C

ondu

ctor

s Su

b To

tal

Cop

per

4 AC

SR

2 AC

SR

Sub

Tota

l AC

SR

Tota

l Sm

all

Con

duct

or

Wild

Fire

Are

a 31

0 10

4 67

48

1 54

9 98

64

7 1,

128

Urb

an P

opul

atio

n A

rea

7,73

8 1,

931

660

10,3

29

8,40

9 27

6 8,

685

19,1

04

Cor

rosi

on A

rea

2,34

1 58

6 21

8 3,

145

683

16

699

3,84

4

•A

sset

loca

tion

is a

n at

tribu

te th

at in

crea

ses

the

nega

tive

cons

eque

nce

of a

wire

dow

n ev

ent

oW

ild F

ire A

rea

(Urb

an, O

ther

, San

ta B

arba

ra)

oU

rban

Pop

ulat

ion

Are

as (u

sing

GIS

def

initi

on o

f 1,0

00 p

eopl

e/sq

uare

mi)

oC

orro

sion

Are

aso

Maj

or ro

adw

ays

and

wat

erw

ays

•W

ire d

own

even

ts w

here

con

duct

or re

mai

ns e

nerg

ized

is a

noth

er a

ttrib

ute

that

pot

entia

llyin

crea

ses

the

cons

eque

nces

of w

ire d

own

even

tso

Ene

rgiz

ed c

ondu

ctor

dat

a va

ries

cons

ider

ably

bet

wee

n di

visi

ons.

Im

prov

ed d

ata

colle

ctio

n is

nee

ded

•N

umbe

r of i

n-lin

e co

nnec

tors

als

o in

fluen

ces

likel

ihoo

d of

failu

re

Estim

ated

Am

ount

s of

Sm

all W

ire S

izes

by

Attr

ibut

e

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-14

Cur

rent

Con

trol

Miti

gatio

ns --

Inta

ct C

onta

ct

V

eget

atio

n M

anag

emen

to

Rou

tine

trim

min

g &

rem

oval

(~ 1

.3 m

illion

uni

ts/y

ear)

o99

.5 %

com

plia

nce

with

regu

lato

ry re

quire

men

ts

oW

ork

at h

isto

ric o

utag

e lo

catio

ns

oP

ilot a

naly

zing

failu

re c

hara

cter

istic

s of

oth

erw

ise

heal

thy

trees

in w

ildfir

e ar

eas

D

esig

n, C

onst

ruct

ion

and

Ope

ratin

gR

equi

rem

ents

oC

lear

ance

requ

irem

ents

oW

arni

ng s

igns

O

verh

ead

Line

Mai

nten

ance

Pro

gram

oV

isua

l pat

rols

and

insp

ectio

ns th

at c

an p

oten

tially

iden

tify

issu

es s

uch

as e

xces

sive

sag

, in

adeq

uate

clea

ranc

es, v

eget

atio

n pr

oble

ms,

etc

.

P

ublic

Aw

aren

ess

Pro

gram

so

Wire

Dow

n aw

aren

ess

oTr

ee T

rimm

ers

awar

enes

s

oN

eed

awar

enes

s pr

ogra

m fo

r spe

cific

third

par

ties

such

as

pain

ters

, roo

fers

, cab

le, c

rane

ope

rato

rs

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-15

Cur

rent

Con

trol

Miti

gatio

ns --

Wire

Dow

n C

onta

ct

Ve

geta

tion

Man

agem

ent (

see

prio

r pag

e)

P

ublic

Aw

aren

ess

Pro

gram

so

Wire

Dow

n aw

aren

ess

oTr

ee T

rimm

ers

awar

enes

s

D

esig

n, C

onst

ruct

ion

and

Ope

ratin

g R

equi

rem

ents

oB

ulle

tins

addr

essi

ng th

e us

e of

6 C

u an

d au

tom

atic

splic

es

oE

xpan

ding

cor

rosi

on a

rea

boun

darie

s

oR

evie

w o

f min

imum

wire

siz

es

oR

evie

w o

f spl

ices

per

spa

n an

d ap

plic

atio

n of

shu

ntsp

lices

O

H C

ondu

ctor

Rep

lace

men

t Pro

gram

oR

epla

ced

96 m

iles

in 2

013.

201

4 pl

an is

to re

plac

e 18

7ci

rcui

t mile

s (c

apac

ity a

nd re

liabi

lity

prog

ram

s)

In

frare

d an

d S

plic

e In

vent

ory

Pro

gram

oA

sses

sed

10,0

00 m

iles

in 2

013.

201

4 pl

an to

infra

red

and

inve

ntor

y sp

lices

on

anot

her 1

0,00

0 m

iles.

S

yste

m P

rote

ctio

no

2012

revi

ew c

oncl

uded

that

PG

&E

’s p

ract

ices

refle

ctw

hat i

s cu

rrent

ly c

onsi

dere

d go

od p

ract

ice

in th

ein

dust

ry

Li

ne M

aint

enan

ce P

rogr

amo

Visu

al p

atro

ls a

nd in

spec

tions

that

can

pot

entia

llyid

entif

y is

sues

suc

h as

exc

essi

ve s

ag,

inad

equa

tecl

eara

nces

, veg

etat

ion

prob

lem

s, e

tc.

91

1 R

espo

nse

oP

roce

sses

and

met

rics

to re

spon

d in

a ti

mel

ym

anne

r to

emer

genc

y si

tuat

ionsPrim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-16

Cur

rent

Con

trol

s A

sses

smen

t - A

mbe

r

Ris

k D

river

s

Current Controls

Con

trol D

escr

iptio

nFr

eque

ncy/

Impa

ct

Con

trol T

ype

Thi

rd-P

arty

E

quip

men

t Fa

ilure

V

eget

atio

n W

ork

Pro

cedu

re

Err

or

Ani

mal

Pub

lic A

war

enes

s P

rogr

ams

(Wire

Dow

n/Tr

ee

Wor

kers

) Fr

eque

ncy

Pre

vent

ive

(adm

inis

trativ

e)

Veg

etat

ion

Man

agem

ent

Freq

uenc

y P

reve

ntiv

e

Line

Mai

nten

ance

Pro

gram

Fr

eque

ncy

Pre

vent

ive

Des

ign,

Con

stru

ctio

n an

d O

pera

ting

Pro

cedu

res

Bot

h P

reve

ntiv

e (a

dmin

istra

tive)

Con

duct

or R

epla

cem

ent P

rogr

am

Freq

uenc

y P

reve

ntiv

e

Infra

red

Insp

ectio

n /S

plic

e In

vent

ory

Freq

uenc

y P

reve

ntiv

e

Site

Inve

stig

atio

n (w

ire d

own,

veg

etat

ion,

wor

k pr

oced

ure)

Fr

eque

ncy

Pre

vent

ive

Sys

tem

Pro

tect

ion

(sep

arat

e ris

k ev

alua

tion)

Im

pact

D

etec

tive

911

Res

pons

e Im

pact

P

reve

ntiv

e

Adeq

uate

Con

trol

Wea

k C

ontro

l St

rong

Con

trol

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-17

Rec

omm

enda

tions

– N

ew R

isk

Miti

gatio

ns

Wor

k R

ecom

men

ded

Ris

k D

river

Af

fect

ed

Addr

esse

s Im

pact

/ Fr

eque

ncy

Prop

osed

Ac

tion

Ow

ner

Tim

ing

Com

men

ts

Exp

and

publ

ic s

afet

y ou

treac

h pr

ogra

m to

(1) f

ocus

on

spec

ific

third

par

ties

such

as

pain

ters

, ro

ofer

s, c

able

, cra

ne o

pera

tors

be

yond

veg

; (2)

exp

ande

d m

etric

s an

d re

porti

ng to

ens

ure

effo

rts a

re e

ffect

ive

3rd p

arty

Fr

eque

ncy

& Im

pact

C

ompl

ete

plan

by

Q2

2014

Coo

rdin

ate

with

Ext

erna

l C

omm

unic

atio

ns a

nd C

usto

mer

C

are.

Low

er th

e ris

k of

ac

cide

ntal

con

tact

with

di

strib

utio

n co

nduc

tors

Rev

iew

tree

trim

min

g pr

actic

es

to e

xplo

re o

ppor

tuni

ties

to fo

cus

on h

isto

rical

wire

dow

n lo

catio

ns

Vege

tatio

n Fr

eque

ncy

Com

plet

e E

valu

atio

n an

d Fi

naliz

e P

lan

by

Q2

2014

Fina

l GR

C d

ecis

ion

will

spec

ify

vege

tatio

n ba

lanc

ing

acco

unt

amou

nt

Rev

ise

STA

R T

ool t

o as

sign

ad

ditio

nal r

isk

to s

mal

l and

co

pper

wire

s an

d lo

catio

ns w

ith

high

er fa

ilure

rate

s

Equ

ipm

ent

Freq

uenc

y C

ompl

ete

by Q

2 20

14

Add

ress

hig

h co

nseq

uenc

e lo

catio

ns s

uch

as fr

eew

ay

cros

sing

, fro

m a

impa

ct

pote

ntia

l, to

bet

ter p

riorit

ize

repl

acem

ent o

r upg

rade

s

Dev

elop

a p

lan,

incl

udin

g qu

antit

ies

and

sche

dule

s, to

re

plac

e ce

rtain

sm

all w

ire (s

uch

as 4

Cu,

6 C

u &

AC

SR

) in

wild

fir

e ar

eas,

urb

an a

reas

and

hig

h co

rrosi

on a

reas

.

Equ

ipm

ent

Failu

re

Freq

uenc

y

Pla

n: Q

2 20

14

Impl

emen

t:

Q3

2014

Prim

ary

Ove

rhea

d C

ondu

ctor

s

4-AtchB-18

Rec

omm

enda

tions

– N

ew R

isk

Miti

gatio

ns

Wor

k R

ecom

men

ded

Ris

k D

river

Af

fect

ed

Addr

esse

s Im

pact

/ Fr

eque

ncy

Prop

osed

Act

ion

Ow

ner

Tim

ing

Com

men

ts

Ele

ctric

dis

tribu

tion

stan

dard

s to

issu

e gu

idel

ines

for t

hres

hold

lim

it on

max

imum

num

ber

of in

-line

con

nect

ors

on

exis

ting

lines

as

wel

l as

crite

ria/d

river

for

nom

inat

ing

OH

wire

for

repl

acem

ent.

Equ

ipm

ent

Failu

re

Freq

uenc

y C

ompl

ete

Q1,

201

4

Gui

danc

e on

the

allo

wab

le

num

ber o

f spl

ices

in n

ew

span

s al

read

y ex

ists

.

Rev

isit

exis

ting

dist

ribut

ion

prot

ectio

n pr

actic

es a

nd e

xplo

re

pote

ntia

l app

licat

ion

of

new

tech

nolo

gy o

ptio

ns to

re

duce

like

lihoo

d of

a

dow

n pr

imar

y w

ire

rem

aini

ng

ener

gize

d.

Pre

pare

a

repo

rt su

mm

ariz

ing

the

findi

ngs

and

reco

mm

enda

tions

.

Third

Par

ty

Freq

uenc

y &

Im

pact

C

ompl

ete

Q2,

201

4

Prim

ary

Ove

rhea

d C

ondu

ctor

s

Prio

r to

exec

utin

g ne

w re

com

men

datio

ns, w

e fin

d th

e cu

rren

t res

idua

l ris

k of

ED

OH

Con

duct

or is

“a

mbe

r”.

Upo

n im

plem

enta

tion

of p

ropo

sed

incr

emen

tal c

ontro

ls a

nd c

ontin

uatio

n of

exi

stin

g co

ntro

ls, w

e an

ticip

ate

the

futu

re re

sidu

al ri

sk w

ill c

ontin

ue to

be

“am

ber.”

4-AtchB-19

Ris

k Sc

enar

ios

– C

urre

nt R

esid

ual R

isk

Typi

cal r

esul

t of a

n as

set f

ailu

re:

A se

rvic

e in

terr

uptio

n to

app

roxi

mat

ely

350

cust

omer

s fo

r app

roxi

mat

ely

two

hour

s (e

xclu

ding

maj

or e

vent

da

ys) a

nd d

oes

not r

esul

t in

an e

lect

ric c

onta

ct o

r fire

igni

tion.

Extr

eme

resu

lt of

an

asse

t fai

lure

: A

cond

ucto

r fai

lure

or t

ree

cont

act c

ausi

ng:

(a) A

rela

tivel

y sm

all (

<100

0 ac

res)

fire

in a

den

sely

pop

ulat

ed a

rea

(e.g

., O

akla

nd H

ills)

resu

lting

in

sign

ifica

nt p

rope

rty d

amag

e, fa

talit

ies

and

inju

ries;

or

(b) A

larg

e fir

e in

a ru

ral a

rea

invo

lvin

g m

ore

than

100

squ

are

mile

s (a

ppro

xim

atel

y 64

,000

acr

es)

resu

lting

in li

mite

d pr

oper

ty d

amag

e bu

t wou

ld in

clud

e fa

talit

ies

and

inju

ries

Thes

e sc

enar

ios

are

used

to s

core

and

prio

ritiz

e ou

r rel

ativ

e ris

k in

the

Ris

k R

egis

ter f

or E

lect

ric O

pera

tions

Ris

k Sc

enar

io

Freq

uenc

y Le

vel*

Impa

ct L

evel

*

Safe

ty

Envi

ronm

enta

lC

ompl

ianc

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PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 5

GAS OPERATIONS

5-i

PACIFIC GAS AND ELECTRIC COMPANY CHAPTER 5

GAS OPERATIONS

TABLE OF CONTENTS

A. Introduction ....................................................................................................... 5-1

B. General Processes ........................................................................................... 5-1

1. Organizational Structure ............................................................................ 5-1

2. Enterprise and Operational Risk Management and Integrated Planning Processes ................................................................................... 5-3

3. Risk-Based Prioritization Methodologies .................................................... 5-4

a. DIMP.................................................................................................... 5-5

1) Know the PG&E System ............................................................... 5-6

2) Identify Threats ............................................................................. 5-7

3) Evaluate and Rank Risks .............................................................. 5-8

4) Implement Measures to Address Risks ....................................... 5-12

5) Measure Performance, Monitor Results and Evaluate Effectiveness ............................................................................... 5-13

6) Conduct Complete Program Evaluations and Make Improvements ............................................................................. 5-13

7) Report Results ............................................................................ 5-13

b. Program-Specific Prioritization Methodologies .................................. 5-13

4. Gas Operations Integrated Planning Process .......................................... 5-14

a. Session D and Risk Register ............................................................. 5-14

b. Session 1 and Risk Informed Budget Allocation ................................ 5-16

c. Session 2 and a Risk-Informed, Executable Work Plan .................... 5-16

C. Areas of Focus and Improvement................................................................... 5-17

5-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 5 2

GAS OPERATIONS 3

A. Introduction 4

This chapter describes how Pacific Gas and Electric Company’s (PG&E) 5

Gas Operations organization is using the Enterprise and Operational Risk 6

Management (EORM) Standard, its Integrity Management program, and other 7

tools to manage gas system risks. 8

B. General Processes 9

1. Organizational Structure 10

Within Gas Operations, risk management is owned by the Risk Register, 11

Asset Knowledge and Integrity Management, and Investment Planning 12

departments. 13

The Risk Register team is responsible for overseeing risk management 14

activities driven by the EORM Program. This includes maintenance of 15

Gas Operations’ Risk Register and implementation of the Session D 16

process. 17

The Asset Knowledge and Integrity Management (AK&IM) Department 18

is responsible for overseeing PG&E’s Transmission Integrity 19

Management Program (TIMP), Distribution Integrity Management 20

Program (DIMP), and Facility Integrity Management Program (FIMP). 21

These programs are driven by federal requirements1 and involve risk 22

management programs that are focused on asset-related threats and 23

risks. The Senior Director of AK&IM is also accountable for the asset 24

management planning processes within Gas Operations2 and oversees 25

the development of asset management plans for each of Gas 26

1 TIMP is driven by Title 49 of the Code of Federal Regulations – Transportation

(49 CFR) 192 Subpart O. DIMP is driven by 49 CFR 192 Subpart P. FIMP is a new concept that has been discussed as part of the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) proposed rulemaking related to the Integrity Verification Process.

2 Gas Operations’ asset management activities are executed in line with the PAS-55/ISO-55001 Asset Management standard.

5-2

Operations’ asset families. Asset families and asset management plans 1

are described in more detail below. 2

The Investment Planning team is responsible for overseeing Gas 3

Operations’ implementation of the Risk Informed Budget Allocation 4

(RIBA) process described in Chapter 2. 5

In mid-2012, PG&E introduced a new paradigm into Gas Operations. 6

PG&E divided its assets into families and designated an individual—the 7

Asset Family Owner (AFO)—for each asset family who is accountable for 8

managing the health of those assets. 9

PG&E has identified eight asset families within Gas Operations. These 10

are outlined in Figure 5-1 below. 11

FIGURE 5-1 PACIFIC GAS AND ELECTRIC COMPANY

GAS OPERATIONS ASSET FAMILIES

Risks are identified and included in the Gas Operations Risk Register 12

based on the asset family structure, and investment decisions are made 13

5-3

within and across asset families aligned with the investment planning, 1

budgeting, and rate case frameworks. 2

In addition, Gas Operations implemented a new risk and asset 3

management process and strengthened senior leadership oversight through 4

its Risk and Compliance Committee (RCC). The RCC is chaired by the 5

Executive Vice President, who appoints representatives from Gas 6

Operations to participate on the committee. RCC members have a broad 7

understanding of the business, its processes, and associated risks. The 8

RCC meets monthly to review current risk-related topics and approve items 9

such as risk assessments, risk mitigation measures and changes to the Risk 10

Register. 11

2. Enterprise and Operational Risk Management and Integrated Planning 12

Processes 13

As described in Chapter 2, PG&E’s EORM Program allows PG&E to 14

manage assets and risks at both an enterprise and operational level. The 15

enterprise risks are those that could threaten the viability of PG&E and 16

typically span multiple lines of business (LOBs). Operational risks arise 17

from assets, people, processes and technologies within specific LOBs, such 18

as Gas Operations. By assessing and managing risks from both points of 19

view, PG&E can better manage the interdependencies and drive for 20

consistency among LOBs. 21

Gas Operations has adopted a risk management process that provides 22

a repeatable and consistent method to identify, assess, rank and mitigate 23

risk. This risk management process is fully integrated into PG&E’s 24

Integrated Planning Process to ensure risk informs the chosen strategies, 25

which in turn drives the allocation of resources. Gas Operations has been 26

advancing its risk management methodology over the last three years, and 27

continues to (i) increase the rigor and documentation of the risk 28

management process; (ii) use more data; (iii) expand the scope of risks 29

assessed as part of the process; and (iv) improve consistency of risk scoring 30

across Gas Operations. 31

The three phases of Gas Operations’ risk management and planning 32

process—(1) Identify threats and assess risks by Asset Family; (2) Develop 33

proposed mitigation programs within Asset Families; and (3) Develop 34

5-4

executable Investment Plan—are aligned with the PG&E’s Integrated 1

Planning Process. The three phases are depicted in Figure 5-2. 2

FIGURE 5-2 PACIFIC GAS AND ELECTRIC COMPANY

RISK MANAGEMENT PROCESS AND PLANNING

Additional information on PG&E’s Integrated Planning Process can be 3

found in Chapters 1, 2 and 3. 4

3. Risk-Based Prioritization Methodologies 5

To support decision making in the Integrated Planning Process, Gas 6

Operations uses several methodologies to prioritize programs and projects. 7

Some examples of these approaches are outlined in this section. 8

5-5

a. DIMP 1

Federal regulations3 require Gas Operators to develop an approach 2

to ensure the integrity of its distribution system. PG&E’s overarching 3

DIMP framework is outlined in Figure 5-3 below: 4

FIGURE 5-3 PACIFIC GAS AND ELECTRIC COMPANY

DIMP CONTINUOUS IMPROVEMENT CYCLE

Consistent with other gas operators within California, PG&E uses a 5

leak-based risk model to assess the risk of distribution pipelines. 6

This model considers five years of historical leak data to identify 7

geographical areas with elevated risk. A negative trend of leak repairs 8

for a geographic area for each threat helps identify where additional 9

mitigation may be applied. 10

The California Public Utilities Commission (CPUC) oversees DIMP 11

and periodically performs audits in accordance with State and Federal 12

3 49 CFR, Part 192-Transportation of Natural and Other Gas by Pipeline: Minimum

Federal Standards, Subpart P – Gas Distribution Pipeline Integrity Management.

5-6

Guidelines.4 Some of the topics addressed in the audits include a 1

review of how operators identify threats, perform risk evaluation, and 2

identify mitigation.5 3

Each of the seven steps in PG&E’s DIMP cycle is summarized 4

below. 5

1) Know the PG&E System 6

System knowledge is the core foundation of DIMP and improves 7

the overall safety and reliability of the distribution pipeline system. 8

At the beginning of each DIMP cycle, the DIMP Mitigation and DIMP 9

Risk teams review the data sources. Consideration is given to 10

information gained from design records, operations, and 11

maintenance as well as knowledge gained from the DIMP Steering 12

Committee, which is comprised of members of the DIMP team and 13

is supplemented with subject matter experts (SME) in each of the 14

DIMP threat categories. 15

PG&E’s DIMP Risk team uses the data, outlined in Figure 5-4, 16

to provide a comprehensive dataset for risk evaluation. As shown in 17

Figure 5-4, a majority of the data used is entered into SAP.6 18

This data is entered by field personnel conducting leak surveys, 19

excavation activities, or other field activities along the pipeline. 20

PG&E uses 20 attribute data fields for its risk analysis. 21

4 49 CFR 190.203 authorizes PHMSA to perform inspections. General Order 112-E

refers to CFR 190 and PHMSA relegates its authority to the CPUC to oversee operators.

5 PHMSA Form 24 (192.1005-192.1011) Gas Distribution System DIMP Implementation Inspection, July 7, 2014, Rev 0.

6 SAP is PG&E’s system of record for asset registry and work management.

5-7

FIGURE 5-4 PACIFIC GAS AND ELECTRIC COMPANY

PRIMARY AND SECONDARY DATA SOURCES FOR RISK ATTRIBUTES

Attribute Primary Data

Source Secondary Data Source

Leak Number SAP n/a

Division SAP Pathfinder GIS

District SAP Pathfinder GIS

City SAP Pathfinder GIS

Line Use SAP Plat sheet

Leak grade SAP n/a

Reported Leak Cause SAP n/a

Leak Source SAP n/a

Material of Leaking Component SAP (Pipe Data) SAP (Inspection)

Pressure SAP SynerGEE

Diameter SAP (Pipe) SAP (Inspection)

Surface Over Pipe SAP (Inspection) SAP (Surface Over Read Location)

Repair Date SAP n/a

Proximity to Areas of Public Assembly SAP GIS Public Assembly Data

Employee and Other Injury RiskMaster SAP

Employee and Other Fatality RiskMaster SAP

Damage Cost RiskMaster SAP

Wall to Wall Paving SAP n/a

Injury/Fatality Metric PHMSA n/a

Injury/Fatality Ratio PHMSA n/a

Other data fields extracted from SAP are reviewed and help in 1

determining appropriate mitigation activities. 2

2) Identify Threats 3

PG&E uses leak data and SME input for threat identification and 4

risk evaluation. The DIMP Risk team reviews the collected dataset 5

and assigns one of eight threat categories (identified in 49 CFR 6

Part 192, Subpart P) to each leak. The DIMP Risk team then 7

applies sub threats, which identify risk drivers and determines if 8

accelerated actions are needed to mitigate risk. 9

Additionally, PG&E monitors potential threats. These threats 10

are identified by data sources independent from leak repair 11

5-8

(Figure 5-5). This includes reviewing internal, industry and 1

government data sources to generate a potential threat list which is 2

annually reviewed and evaluated for risk. The identified potential 3

threat list, its validity and any action required is reviewed and 4

approved by the DIMP Steering Committee. 5

FIGURE 5-5 PACIFIC GAS AND ELECTRIC COMPANY

SOURCE DATA FOR MONITORING POTENTIAL THREATS

Database Monitoring Interval

PHMSA Bulletins Annually

National Transportation Safety Board Accident Reports

Quarterly

DIMP Field Review As Performed

Material Problem Reports Quarterly

Gas Corrective Action Plan Reporting Quarterly

Potential Threat Log Annually

3) Evaluate and Rank Risks 6

The risk assessment for the gas distribution system is informed 7

from its leak history. In the assessment, each leak receives a score 8

based on its Likelihood of Failure (LoF) and Consequence of Failure 9

(CoF). The LoF for each leak is equal to 1 since the failure has 10

already occurred. The CoF portion of the risk model is based on the 11

following components: Impact on Life; Consequence Potential; 12

Leak Magnitude; and Injury/Fatality statistics. Figure 5-6 outlines 13

the variables considered in each of these components. The 14

variables of each component are identified and the relative severity 15

of a variable’s points determines the contribution to the 16

consequence of a leak. 17

5-9

FIGURE 5-6 PACIFIC GAS AND ELECTRIC COMPANY

RISK EVALUATION CONSEQUENCE FACTORS AND EQUATION

Impact on Life Consequence Potential Leak Magnitude Injury Fatality Near Public Injury Fatality Damage

Wall to Wall Paving Surface Proximity

Pipeline Pressure

Pipeline Diameter

Leak Grade

Injury Fatality Metric

Injury Fatality Ratio

_______________

CoF = [(Impact on Life)+(Consequence Potential)]*[(Leak Magnitude)*(Injury Fatality)]

As shown in the equation below, the total consequence 1

associated with each threat is the sum of the applicable leak 2

consequence scores. 3

𝑅𝑇 = ∑ 𝐿𝑜𝐹𝑖 𝑋 𝐶𝑂𝐹𝑖

𝑛

𝑖=1

Where: RT = Total risk per threat N = Number of leak events LoFi = Likelihood of each recorded leak event (equal to 1) CoFi = Consequence of each leak event

The risk scores from this equation are aggregated by 4

geographical area to develop a relative risk ranking of all threats and 5

geographical areas. 6

Following the calculation of the risk scores, the DIMP Risk team 7

analyzes risk at the appropriate level of aggregation for each threat. 8

Excavation is a threat that varies at a local level, and therefore must 9

be managed and mitigated at the local level. Because of this, PG&E 10

separates out excavation threats from this analysis, and reviews this 11

risk at the city level. Figures 5-7 and 5-8 below show the risk 12

analysis done for excavation at the city level, and the analysis done 13

for all other threats at the district (subset of a PG&E division) level. 14

Values to the right of the vertical lines represent high risk, and the 15

values within the two lines define medium risk areas. 16

5-10

FIGURE 5-7 PACIFIC GAS AND ELECTRIC COMPANY RISK FOR EXCAVATION – CITY LEVEL

5-11

FIGURE 5-8 PACIFIC GAS AND ELECTRIC COMPANY

RISK FOR ALL CAUSES EXCEPT EXCAVATION – DISTRICT LEVEL

The DIMP Risk team uses standard deviations to define 1

distribution bands in determining geographic areas of low, medium, 2

or high risk for each of the two risk analyses shown in Figures 5-7 3

and 5-8. 4

System performance is identified based on a 5-year linear trend 5

of leak repairs for the same geographic area for each threat. The 6

leak data gathered (as summarized in Figure 5-4) is reviewed for 7

5-12

this analysis. Good performance is indicated by a decreasing 1

5-year linear trend. Fair performance is indicated by a flat (slope 2

equals zero) 5-year linear trend. Poor performance is indicated by 3

an increasing 5-year linear trend. 4

The combination of risk scores and system performance, 5

outlined below, determine if a Root Cause Analysis (RCA) is 6

needed. RCAs help determine the appropriate mitigation activities 7

for each threat. PG&E performs RCAs in cases as shown in 8

Figure 5-9. 9

FIGURE 5-9 PACIFIC GAS AND ELECTRIC COMPANY

NEED FOR ROOT CAUSE ANALYSIS DETERMINATION

Performance Good Fair Poor

Ris

k

Low Review Next DIMP Cycle

Review Next DIMP Cycle

Review Next DIMP Cycle

Medium Review Next DIMP Cycle

Review Next DIMP Cycle Perform RCA

High Review Next DIMP Cycle Perform RCA Perform RCA

4) Implement Measures to Address Risks 10

The DIMP Mitigation team considers all current and applicable 11

mitigation measures. During this review the DIMP Mitigation team 12

will identify new mitigation measures or changes to the program that 13

will reduce risk.7 If existing programs and activities do not 14

adequately address the risk, the team will work to develop a new 15

program or project to mitigate the risk. Program specific mitigation 16

actions such as the Aldyl-A Replacement program and the Gas 17

Pipeline Replacement Program are reviewed to ensure work is 18

prioritized accordingly. These programs and projects are included in 19

the Session 1 and Session 2 processes to be prioritized and 20

funded accordingly. 21

7 Order Instituting Rulemaking 15-01-008, issued March 18, 2015, provides criteria for

replacement and repair based on leak grade. The process for determining mitigation may change as additional clarity is provided through the rulemaking.

5-13

5) Measure Performance, Monitor Results and Evaluate 1

Effectiveness 2

In accordance with the program evaluation requirements,8 3

PG&E performs reviews and evaluations annually. The review 4

includes refreshing leak data to incorporate new risks into the risk 5

management process. The process described above is applied to 6

the refreshed data, and included in the risk prioritization of the gas 7

distribution system. Additionally, the DIMP Risk team evaluates 8

existing algorithms and statistical methodologies used to derive the 9

overall risk score. 10

6) Conduct Complete Program Evaluations and Make 11

Improvements 12

PG&E performs reviews and evaluations of its threat 13

identification, risk analysis, and mitigation performance on a periodic 14

basis. PG&E also participates in internal quality assurance audits 15

as well as external audits performed by regulatory agencies to 16

ensure the program is meeting legal requirements. 17

7) Report Results 18

PG&E communicates the status of its reviews to key internal 19

stakeholders on an annual basis. Additionally PG&E completes 20

the following PHMSA forms: PHMSA F 7100.1-1 (Annual Report 21

Form)9 and PHMSA F 7100.1-2 (Mechanical Fitting Failure 22

Report Form). 23

b. Program-Specific Prioritization Methodologies 24

For most risk-based programs, it is necessary to have a prioritization 25

methodology that allows for risk ranking at the granular asset level to 26

allow for implementation of the program over multiple years while 27

maximizing risk reduction in the short term. Each program has either a 28

8 49 CFR, Part 192-Transportation of Natural and Other Gas by Pipeline: Minimum

Federal Standards, Subpart P – Gas Distribution Pipeline Integrity Management, 192.1007(f).

9 PG&E provides a copy of PHMSA F 7100.1-1 to the CPUC with a report outlining the major mitigation programs and accomplishments of the program during the previous year.

5-14

relative risk calculation methodology including components related to 1

likelihood of failure and consequence of failure, or a decision tree 2

methodology that prioritizes projects into tranches of equivalent risk. 3

Below are some of the risk mitigation programs included in the 4

Integrated Planning Process: 5

Aldyl-A Replacement Program – replacement of Aldyl-A pipe based 6

on vintage, material properties, leak history, and other factors. 7

Gas Pipeline Replacement Program – replacement of cast iron and 8

pre-1940 steel based on leak history, vintage, material properties, 9

corrosion potential, and other factors. 10

High-Pressure Regulator (HPR) Replacement Program – 11

replacement of HPRs based on vintage, material properties, and 12

other factors. 13

4. Gas Operations Integrated Planning Process 14

Gas Operations follows the PG&E Integrated Planning process for 15

identifying risks, developing mitigation programs, and prioritizing work to 16

address risks. The details of Gas Operations’ approach to this process are 17

outlined below. 18

a. Session D and Risk Register 19

Each AFO with the assistance of SMEs, is responsible for identifying 20

the risks associated with their asset family and scoring each risk based 21

on system knowledge, available data, and SME knowledge. The 22

categorization and evaluation of threats and risks are driven by 23

industry-adopted integrity management principles,10 PG&E’s obligation 24

to serve—both in terms of ensuring reliable delivery of natural gas and 25

increasing capacity to meet demand—as well as risks posed by an 26

inadequate response to and recovery from emergencies. 27

As stated above, PG&E has strengthened and advanced its risk 28

management methodology. By implementing the process improvements 29

noted below, PG&E has been able to effectively identify and score risks 30

within Gas Operations: 31

10 For transmission assets, threats follow American Society of Mechanical

Engineers B31.8S. For distribution assets, threats follow 49 CFR 192 Subpart P.

5-15

Greater Utilization and Integration of Data: Gas Operations has 1

increased visibility into potential risks by integrating Corrective 2

Action Plan (CAP) and process hazard analysis data into the risk 3

identification and scoring processes. 4

Increased Rigor and Documentation: SME input is used for 5

identification and validation of risks. Additionally, SME review and 6

sign-off is required for each asset family’s risk register. 7

Expanded Scope of Risk Assessment: Risks that fall outside the 8

asset families’ risk registers, such as Gas System Operations and 9

Employee Qualification risks, are identified, scored, and calibrated 10

against asset risks and are included in the Risk Register for 11

Gas Operations. 12

External Review: PG&E has leveraged the use of third-party 13

industry experts to validate Gas Operations’ risk methodology and 14

scoring. 15

Calibration of Risk: This is achieved through the consistent 16

application and calibration of risk categories and the risk scoring 17

across Gas Operations risks. 18

After identifying and scoring the risks, AFOs meet with the Gas 19

Operations’ Risk Register team to calibrate and validate ranking of each 20

threat. The AFOs document this ranking in a Risk Register 21

(Attachment A), which is updated and refined as additional information is 22

obtained and evaluated. Gas Operations communicates its top risks 23

(based on the Risk Register scoring) to PG&E leadership in Session D 24

of the Integrated Planning Process. Each risk is evaluated to determine 25

if existing mitigations are effectively managing the risk. During this step, 26

the AFOs also identify any interdependencies with other LOBs to 27

effectively manage the risk. As described below, to the extent that 28

additional mitigations are necessary, asset management plans and work 29

plans are built out in order to mitigate or reduce the risks. 30

In addition to the Session D effort, risk is also tracked within Gas 31

Operations during monthly RCC meetings described above. At these 32

meetings, AFOs highlight progress made on key risks and the status of 33

those risks. Furthermore, all Gas Operations risks included in the Risk 34

5-16

Register are stored in the Enterprise Compliance Tracking System for 1

further updates, review and reporting. 2

b. Session 1 and Risk Informed Budget Allocation 3

Based on the risks identified and scored during Session D, AFOs 4

then analyze and develop the proposed scope and pace of mitigation 5

programs. Each of the mitigation programs is designed to address the 6

identified threats and risks within the asset families to reduce those 7

risks. The AFOs submit the list of mitigation programs to the Investment 8

Planning team for further assessment and prioritization using the 9

RIBA process. 10

The RIBA risk scores are then used to develop the 5-year strategic 11

investment plan for Gas Operations, which is submitted for 12

consideration at the enterprise level as part of Session 1. Additional 13

details about RIBA can be found in Chapter 3. 14

c. Session 2 and a Risk-Informed, Executable Work Plan 15

In Session 2, individual projects are identified within the programs 16

identified in Session 1 and the RIBA framework is applied to assist in 17

developing an executable plan and scope of work for the following year. 18

The investment plan developed in Session 2 includes refinement and 19

additional details to inform execution plans. After the total portfolio of 20

proposed projects has been prioritized using a risk score, Investment 21

Planning applies additional factors such as constraints to the total 22

portfolio to ensure the work can be accomplished effectively. 23

Constraints include, for instance, resource constraints such as 24

availability of trained and qualified personnel, execution constraints such 25

as the time necessary to obtain required permits, and system 26

constraints such as the ability to deliver gas to customers while 27

performing the total portfolio of work. 28

Investment Planning then works with the AFOs to finalize the 29

proposed investment plan based on the risks and constraints identified. 30

This process requires discussion and rationalization among mitigation 31

programs across asset families. 32

5-17

C. Areas of Focus and Improvement 1

Gas Operations is exploring opportunities within its risk management 2

processes to develop a more structured optimization model that can enhance 3

prioritization based on risk, resource, budget, and system constraints as part of 4

the integrated planning process. Gas Operations will also continue to improve 5

asset data quality including integration of asset health condition assessments for 6

more informed risk assessments. Additionally, data gathered from root cause 7

analyses, CAP, quality assurance/quality control, monitoring of compliance 8

activities, and audit findings will help drive more informed risk processes. 9

In addition, in 2013, PG&E began working on the Pathfinder Program which 10

will establish a single database for gas distribution asset information. Pathfinder 11

will provide a “system of record” for all gas distribution asset data to facilitate risk 12

assessments required for DIMP and will provide the foundation for a new unified 13

Geographic Information System (GIS)/SAP model for storing gas distribution 14

asset data. Additionally, the DIMP team will be using Riskfinder, which is a set 15

of tools that helps automate the gathering of additional data streams. Another 16

tool embedded in Riskfinder is the Uptime tool, which performs GIS-based risk 17

analysis. This data will be used by the DIMP team to drive risk decisions and 18

identify appropriate mitigations. 19

The DIMP team will also be expanding their review to regulator stations and 20

meter sets. Regulator stations can potentially impact the integrity of 21

downstream assets. This provides additional data that the DIMP Team will use 22

to identify threats, assign a risk scoring, and develop mitigation work. 23

By leveraging technology and developing more consistent risk 24

methodologies for diverse assets, programs will be prioritized based on risk 25

across the system by making an asset-to-asset comparison rather than 26

prioritization occurring within individual programs. This change in methodology 27

will allow PG&E to ensure the highest risk assets, regardless of asset type, are 28

replaced first, thus maximizing risk reduction. 29

PG&E plans on additional benchmarking within and outside the industry to 30

validate and enhance its risk management framework and process. PG&E will 31

also continue to seek external review from industry experts and academic 32

research teams to help its risk management process validation and 33

improvement journey. 34

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 5

ATTACHMENT A

GAS OPERATIONS RISK REGISTER

As

of A

pril

14, 2

015

Gas

Ope

ratio

ns R

isk

Reg

iste

r (1/

5)

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e

21

DM

S39

‒ E

xcav

atio

n D

amag

e, T

hird

Par

ty ‒

Rup

ture

N

on A

t-Fau

lt

406

22

TRA

11 ‒

Inco

rrec

t Ope

ratio

ns ‒

Ove

r Pre

ssur

izat

ion

34

8 23

TR

A9

‒ S

tress

Cor

rosi

on C

rack

ing

32

6 24

G

as C

ompl

ianc

e P

erfo

rman

ce R

isk

316

25

MC

14 ‒

Wel

ding

/Fab

ricat

ion

‒ O

verp

ress

ure

Com

plex

S

tatio

n 31

3

26

MC

10 ‒

Inco

rrec

t Ope

ratio

n ‒

Term

inal

/Lar

ge C

ompl

ex

313

27

MC

4 ‒

Inco

rrec

t Ope

ratio

ns ‒

Com

plex

Sta

tions

31

3 28

M

C6

‒ In

corr

ect O

pera

tions

‒ B

ackb

one

(PLS

) Sta

tions

31

3 29

S

TO17

‒ E

xter

nal C

orro

sion

‒ P

ipel

ine

313

30

MC

3 ‒

Inco

rrec

t Ope

ratio

ns ‒

LoC

Sim

ple

Sta

tions

31

2 31

M

C13

‒ W

eldi

ng/F

abric

atio

n ‒

LoC

Sim

ple

Sta

tion

312

32

STO

20 ‒

Man

ufac

turin

g ‒

Pip

elin

e 31

2 33

S

TO12

‒ E

rosi

on ‒

Met

ers

311

34

STO

15 ‒

Ero

sion

‒ V

alve

s 31

1 35

S

TO18

‒ F

atig

ue ‒

All

Seg

men

ts

311

36

DM

S42

‒ In

corr

ect O

pera

tions

‒ E

mpl

oyee

Qua

lific

atio

ns

311

37

TRA

16 ‒

Equ

ipm

ent R

elat

ed ‒

Ove

r-P

ress

ure

Eve

nt

311

38

MC

18 ‒

Equ

ipm

ent R

elat

ed ‒

LoC

Com

plex

/ S

impl

e S

tatio

n 31

1

39

MC

36 ‒

Equ

ipm

ent R

elat

ed ‒

Ter

min

al/L

arge

Com

plex

31

1 40

M

C19

‒ E

quip

men

t Rel

ated

‒ B

ackb

one

(PLS

) Sta

tions

31

1

41

DM

S8

‒ In

corr

ect O

pera

tions

‒ C

ross

Bor

e in

Sub

urba

n A

rea

310

42

CP

1 ‒

Ext

erna

l/Int

erna

l Cor

rosi

on

310

43

CP

2 ‒

Ext

erna

l Cor

rosi

on ‒

Und

er P

ipe

Insu

latio

n 31

0 44

C

P10

‒ In

tern

al C

orro

sion

and

Ero

sion

31

0 45

C

P18

‒ S

tress

Cra

ckin

g C

orro

sion

31

0 46

D

MS

5 ‒

Mat

eria

l or W

eld

‒ P

last

ic (S

yste

m S

afet

y)

310

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 1

GO

‒ C

yber

secu

rity

811

2 TR

A4

‒ C

atas

troph

ic P

ipel

ine

Failu

re ‒

Man

ufac

turin

g R

elat

ed D

efec

ts

807

3 TR

A1

‒ C

atas

troph

ic P

ipel

ine

Failu

re ‒

Ext

erna

l C

orro

sion

80

7

4 TR

A8

‒ C

atas

troph

ic P

ipel

ine

Failu

re ‒

Inte

rnal

C

orro

sion

80

7

5 TR

A3

‒ C

atas

troph

ic P

ipel

ine

Failu

re ‒

Wel

ding

/ Fa

bric

atio

n R

elat

ed ‒

Pre

-196

2 C

onst

ruct

ion

with

Lan

d M

ovem

ent

806

6 S

TO16

‒ In

tern

al C

orro

sion

and

/or E

rosi

on ‒

Pip

elin

e 80

4

7 D

MS

45 ‒

Inco

rrec

t Ope

ratio

ns ‒

Cro

ss B

ore

in U

rban

A

rea

617

8 C

P19

‒ T

hird

Par

ty/M

echa

nica

l Dam

age

‒ V

anda

lism

59

6

9 C

P22

‒ W

eath

er R

elat

ed/O

utsi

de F

orce

s ‒

Sei

smic

(M

anne

d)

596

10

DM

S40

‒ R

ecor

ds M

anag

emen

t ‒ D

istri

butio

n M

ains

and

S

ervi

ces

591

11

TRA

12 ‒

Cat

astro

phic

Pip

elin

e Fa

ilure

‒ W

eath

er

Rel

ated

and

Out

side

For

ces

‒ La

nd M

ovem

ent

579

12

MC

32 ‒

Wea

ther

Rel

ated

/Out

side

For

ces

‒ S

eism

ic

573

13

MC

15 ‒

Equ

ipm

ent R

elat

ed ‒

LoC

Com

plex

/ S

impl

e S

tatio

n

573

14

MC

1 ‒

Inco

rrec

t Ope

ratio

ns ‒

LoC

LP

Dis

tribu

tion

551

15

CP

12 ‒

Man

ufac

turin

g D

efec

ts

551

16

CP

8 ‒

Wel

ding

/Fab

ricat

ion

Rel

ated

55

1 17

S

TO26

‒ W

eath

er a

nd O

utsi

de F

orce

s ‒

Sei

smic

55

1 18

M

C16

‒ E

quip

men

t Rel

ated

‒ L

oC L

P D

istri

butio

n 54

8 19

C

P6

‒ In

corr

ect O

pera

tions

54

8

20

GS

O1

‒ Fa

ilure

to M

eet C

ore

Cus

tom

er D

eman

d fo

r D

esig

n S

tand

ard

Abn

orm

al P

eak

Day

(AP

D)

537

5-AtchA-1

As

of A

pril

14, 2

015

Gas

Ope

ratio

ns R

isk

Reg

iste

r (2/

5)

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 70

C

CE

11 ‒

Nat

ural

For

ces

(Flo

od)

234

71

LNG

15 ‒

Thi

rd-P

arty

Dam

age

‒ N

GV

Tan

k R

uptu

re

234

72

DM

S54

‒ O

ther

Out

side

For

ces

‒ In

acce

ssib

le

Equ

ipm

ent

202

73

CC

E33

‒ O

ther

Out

side

For

ce ‒

Inac

cess

ibilit

y to

Sys

tem

20

2 74

S

TO21

‒ C

onst

ruct

ion

‒ P

ipel

ine

191

75

STO

29 ‒

Thi

rd P

arty

Dam

age

‒ A

ll S

egm

ents

18

4

76

DM

S10

‒ In

corr

ect O

pera

tions

‒ R

egul

ator

(L

ow P

ress

ure)

18

4

77

MC

30 ‒

3rd

Par

ty/M

echa

nica

l Dam

age

‒ V

anda

lism

18

3 78

S

TO23

‒ W

eath

er a

nd O

utsi

de F

orce

‒ M

cDon

ald

Isla

nd

181

79

CP

21 ‒

Wea

ther

Rel

ated

/Out

side

For

ces

‒ S

eism

ic

(Unm

anne

d)

181

80

MC

33 ‒

BTU

Hea

ting

Val

ue

176

81

LNG

25 ‒

Equ

ipm

ent ‒

CN

G In

ject

ion

Equ

ipm

ent O

ps

Failu

re (S

afet

y)

175

82

MC

25 ‒

Ext

erna

l Cor

rosi

on

175

83

DM

S52

‒ M

ater

ial T

race

abili

ty

175

84

MC

30.1

‒ 3

rd P

arty

/Mec

hani

cal D

amag

e ‒

Veh

icul

ar

Dam

age

175

85

DM

S38

‒ O

utsi

de F

orce

‒ L

and

Mov

emen

t Due

to C

reep

17

4 86

D

MS

51 ‒

Co-

Loca

tion

of G

as a

nd E

lect

ric F

acili

ties

174

87

MC

2 ‒

Inco

rrec

t Ope

ratio

ns ‒

LoC

HP

Dis

tribu

tion

174

88

DM

S37

‒ O

verb

uild

s

174

89

CP

29 ‒

Equ

ipm

ent R

elat

ed ‒

Hin

kley

Non

-Ret

rofit

C

ompr

esso

r Rec

ipro

catin

g E

ngin

e 17

4

90

MC

7 ‒

Inco

rrec

t Ope

ratio

ns ‒

LoS

LP

Dis

tribu

tion

174

91

MC

21 ‒

Equ

ipm

ent R

elat

ed ‒

LoS

LP

Dis

tribu

tion

174

92

CC

E5

‒ M

ater

ial o

r Wel

d ‒

Inad

equa

te C

usto

mer

R

egul

ator

Des

ign

17

3

93

STO

13 ‒

Inco

rrec

t Ope

ratio

ns ‒

Val

ves

158

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 47

TR

A6

‒ Th

ird P

arty

/Mec

hani

cal D

amag

e

310

48

STO

3 ‒

Con

stru

ctio

n by

1st

and

2nd

Par

ty ‒

Res

ervo

ir 31

0 49

S

TO30

‒ 1

st, 2

nd, 3

rd P

arty

‒ A

ll S

egm

ents

31

0 50

C

P5

‒ M

anuf

actu

ring

Def

ects

‒ P

ipe

Qua

lity

310

51

STO

19 ‒

Thi

rd P

arty

Dam

age

‒ P

ipel

ine

310

52

DM

S1

‒ E

xcav

atio

n D

amag

e, T

hird

Par

ty ‒

Rup

ture

A

t-Fau

lt D

ue to

Mis

mar

king

by

PG

&E

30

8

53

CP

7 ‒

Inco

rrec

t Ope

ratio

ns ‒

Odo

rizat

ion

308

54

DM

S14

‒ N

atur

al F

orce

s

245

55

CC

E29

‒ M

ater

ial

237

56

CC

E30

‒ M

ater

ial T

race

abili

ty

237

57

DM

S53

‒ In

corr

ect O

pera

tions

(Wor

kman

ship

Tr

acea

bilit

y)

235

58

GS

O3

‒ R

isk

of U

sing

Man

ual O

pera

tions

23

5 59

C

P13

‒ E

quip

men

t Rel

ated

‒ E

lect

rical

Sys

tem

s 23

5

60

LNG

18 ‒

Thi

rd-P

arty

Dam

age

‒ C

NG

Tra

iler

Tran

spor

tatio

n In

cide

nt

235

61

CC

E31

‒ O

ther

Out

side

For

ces

‒ B

uild

ing

and

Met

er

Inte

ract

ion

235

62

DM

S15

‒ E

xter

nal C

orro

sion

‒ U

npro

tect

ed S

teel

Pip

e

234

63

DM

S23

‒ M

ater

ial a

nd W

eld

‒ S

teel

Inst

alle

d Th

roug

h th

e 19

50s

23

4

64

CC

E20

‒ E

quip

men

t ‒ In

door

Met

er S

ets

23

4

65

DM

S46

‒ In

corr

ect O

pera

tions

‒ A

pplic

ant I

nsta

lled

Faci

litie

s 23

4

66

DM

S4

‒ In

tern

al C

orro

sion

23

4

67

DM

S43

‒ O

utsi

de F

orce

‒ L

and

Mov

emen

t Due

to

Ero

sion

or S

ubsi

denc

e 23

4

68

CC

E7

‒ E

quip

men

t or O

ther

Out

side

For

ce ‒

End

of L

ife

Failu

re

234

69

DM

S22

‒ M

ater

ial a

nd W

eld

‒ C

ompo

site

Ris

ers

23

4

5-AtchA-2

As

of A

pril

14, 2

015

Gas

Ope

ratio

ns R

isk

Reg

iste

r (3/

5)

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 11

6 S

TO25

‒ E

quip

men

t ‒ S

tora

ge F

ield

Fac

ilitie

s 95

11

7 TR

A22

‒ In

corr

ect O

pera

tions

82

118

LNG

12 ‒

Thi

rd-P

arty

Dam

age

‒ Fu

elin

g S

tatio

n D

rive

Aw

ay

74

119

LNG

24.1

‒ E

quip

men

t ‒ L

NG

Vap

oriz

er O

utag

e (R

elia

bilit

y)

72

120

GS

O9

‒ S

ched

ulin

g R

isk

68

121

CP

15 ‒

Rec

ords

Man

agem

ent (

P50

) 68

122

TRA

20 ‒

Wea

ther

Rel

ated

and

Out

side

For

ces

‒ Tr

ee D

amag

e

58

123

TRA

10 ‒

Wea

ther

-Rel

ated

Out

side

For

ce ‒

W

ater

Cro

ssin

gs a

nd E

xpos

ed P

ipe

58

124

CP

24 ‒

Hin

kley

Sta

tion

Non

-Ret

rofit

ted

Com

pres

sor

Out

age

Due

to A

ny C

ause

53

125

CP

25 ‒

Del

evan

Sta

tion

Com

pres

sor O

utag

e D

ue to

A

ny C

ause

53

126

CP

32 ‒

San

ta R

osa

Sta

tion

Com

pres

sor O

utag

e D

ue to

A

ny C

ause

53

127

CC

E13

‒ N

atur

al F

orce

s (S

eism

ic)

50

128

CC

E32

‒ O

ther

Out

side

For

ce ‒

Spa

tial C

lear

ance

45

12

9 C

P9

‒ E

quip

men

t Rel

ated

‒ A

ir E

mis

sion

Reg

ulat

ion

44

130

STO

20.1

‒ M

anuf

actu

ring

‒ P

ipel

ine

43

131

LNG

31 ‒

Insu

ffici

ent P

orta

ble

Equ

ipm

ent

42

132

CC

E4

‒ O

ther

Out

side

For

ce ‒

Thi

rd P

arty

Dam

age

‒ C

onst

ruct

ion

and

Red

evel

opm

ent

41

133

STO

27 ‒

Inco

rrec

t Ope

ratio

ns ‒

Sto

rage

Fie

ld F

acili

ties

39

134

TRA

25 ‒

Equ

ipm

ent R

elat

ed ‒

Inop

erab

le V

alve

s

38

135

DM

S47

‒ O

ther

Out

side

For

ces

‒ Tr

ee R

oot D

amag

e to

P

last

ic P

ipe

34

136

STO

16.1

‒ In

tern

al C

orro

sion

and

/or E

rosi

on ‒

Pip

elin

e 34

13

7 C

CE

26 ‒

Equ

ipm

ent F

ailu

re ‒

Met

er/R

egul

ator

33

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e

94

TRA

19 ‒

Mec

hani

cal D

amag

e ‒

Ele

ctric

Sub

stat

ion

Dam

age

14

4

95

TRA

21 ‒

Mat

eria

l Tra

ceab

ility

14

4

96

MC

34 ‒

Rec

ords

Man

agem

ent ‒

Inad

equa

te R

ecor

ds

(P50

) 14

3

97

TRA

26 ‒

Equ

ipm

ent R

elat

ed ‒

Com

pone

nt F

ailu

re

(Drip

s, F

ittin

gs)

138

98

STO

5 ‒

Cor

rosi

on ‒

Wel

l Cas

ing

114

99

STO

31 ‒

Stre

ss C

orro

sion

Cra

ckin

g ‒

Pip

elin

e 10

8 10

0 S

TO10

‒ In

corr

ect O

pera

tions

‒ W

ells

10

7 10

1 S

TO11

‒ E

rosi

on ‒

Wel

ls

107

102

TRA

14 ‒

Mec

hani

cal D

amag

e ‒

Firs

t and

Sec

ond

Par

ty

Dam

age

10

3

103

STO

4 ‒

Inco

rrec

t Ope

ratio

ns ‒

Res

ervo

ir 10

3

104

LNG

24.0

‒ E

quip

men

t ‒ L

NG

Vap

oriz

er O

pera

tions

Fa

ilure

(Saf

ety)

10

3

105

LNG

17.0

‒ T

hird

-Par

ty D

amag

e ‒

LNG

Tan

ker P

arke

d (S

afet

y)

102

106

LNG

16 ‒

Thi

rd-P

arty

Dam

age

‒ LN

G T

anke

r Tr

ansp

orta

tion

Inci

dent

10

2

107

MC

29 ‒

Inte

rnal

Cor

rosi

on

98

108

MC

28 ‒

Stre

ss C

rack

ing

Cor

rosi

on

98

109

STO

22 ‒

Wea

ther

and

Out

side

For

ce ‒

LM

and

PC

98

110

MC

12 ‒

Wel

ding

/Fab

ricat

ion

‒ O

verp

ress

ure

Eve

nt

(Sys

tem

Saf

ety)

98

111

MC

17 ‒

Equ

ipm

ent R

elat

ed (S

yste

m S

afet

y)

98

112

MC

9 ‒

Inco

rrec

t Ope

ratio

ns (S

yste

m S

afet

y)

98

113

MC

22 ‒

Equ

ipm

ent R

elat

ed ‒

LoS

HP

Dis

tribu

tion

98

114

TRA

23 ‒

Thi

rd P

arty

/Mec

hani

cal D

amag

e ‒

Van

dalis

m

97

115

LNG

26 ‒

Thi

rd-P

arty

Dam

age

‒ O

RC

A T

rlr T

rans

po

Inci

dent

97

5-AtchA-3

As

of A

pril

14, 2

015

Gas

Ope

ratio

ns R

isk

Reg

iste

r (4/

5)

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e

158

CP

26 ‒

Tio

nest

a S

tatio

n C

ompr

esso

r Out

age

Due

to

Any

Cau

se (S

yste

m S

afet

y)

24

159

CP

27 ‒

Bur

ney

Sta

tion

Com

pres

sor O

utag

e D

ue to

Any

C

ause

(Sys

tem

Saf

ety)

24

160

CP

28 ‒

Ger

ber S

tatio

n C

ompr

esso

r Out

age

Due

to A

ny

Cau

se

24

161

CP

31 ‒

Bet

hany

Sta

tion

Com

pres

sor O

utag

e D

ue to

A

ny C

ause

24

162

CP

33 ‒

Top

ock

Sta

tion

Com

pres

sor O

utag

e D

ue to

Any

C

ause

24

163

CC

E28

‒ O

ther

Out

side

For

ce ‒

Gro

undi

ng

24

164

LNG

22 ‒

Inco

rrec

t Ope

ratio

ns ‒

CN

G Q

uick

Cha

nge

Bot

tle S

afet

y

24

165

GS

O6

‒ M

arke

t Liq

uidi

ty R

isk

23

166

GS

O8

‒ D

eman

d R

isk

23

167

LNG

19.1

‒ T

hird

-Par

ty D

amag

e ‒

CN

G T

ube

Trai

ler

Par

ked

(Rel

iabi

lity)

23

168

MC

24 ‒

Equ

ipm

ent R

elat

ed ‒

LoS

Com

plex

Sta

tion

22

169

MC

27 ‒

Equ

ipm

ent R

elat

ed ‒

Ter

min

al/L

arge

Com

plex

22

17

0 M

C35

‒ E

quip

men

t Rel

ated

‒ B

ackb

one

(PLS

) Sta

tions

22

17

1 S

TO30

.1 ‒

1st

, 2nd

, 3rd

Par

ty ‒

All

Seg

men

ts

22

172

STO

24 ‒

Wea

ther

and

Out

side

For

ces

‒ M

cDon

ald

Isla

nd

20

173

DM

S2

‒ E

xcav

atio

n D

amag

e Th

ird P

arty

, No

Rup

ture

(P

50)

19

174

CP

30 ‒

Inco

rrec

t Ope

ratio

ns

18

175

CP

17 ‒

Equ

ipm

ent R

elat

ed ‒

Def

erre

d m

aint

enan

ce

18

176

DM

S41

‒ In

corr

ect O

pera

tions

‒ F

usio

n Jo

ints

(P

50)

18

177

STO

33 ‒

Dis

posa

l Wel

l ‒ G

ill R

anch

17

178

STO

34 ‒

Inte

rnal

/Ext

erna

l Cor

rosi

on ‒

Dis

posa

l ‒ W

ell ‒

G

ill R

anch

17

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e

138

LNG

30 ‒

Inco

rrec

t Ope

ratio

ns ‒

Sta

tion

Doc

umen

tatio

n S

afet

y

32

139

LNG

32.0

‒ E

quip

men

t ‒ S

tatio

n C

ompr

esso

r and

C

ompo

nent

(Saf

ety)

32

140

LNG

19.0

‒ T

hird

-Par

ty D

amag

e ‒

CN

G T

ube

Trai

ler

Par

ked

(Saf

ety)

32

141

DM

S50

‒ M

ilita

ry F

acili

ties

31

142

LNG

27 ‒

Thi

rd-P

arty

Dam

age

‒ O

RC

A L

NG

Saf

ety

Par

ked

31

143

LNG

32.1

‒ E

qpm

t ‒ C

ombi

ned

Sta

Com

pr a

nd

Com

pone

nt (R

elia

bilit

y)

30

144

GS

O2

‒ Fa

ilure

to m

eet N

on-C

ore

CW

D D

esig

n S

tand

ard

30

145

DM

S44

‒ E

xcav

atio

n D

amag

e ‒

Unl

ocat

able

Stu

bs

30

146

LNG

28 ‒

LN

G C

omm

odity

Sho

rtfal

l 30

14

7 S

TO14

‒ E

quip

men

t ‒ V

alve

s 30

14

8 M

C23

‒ E

quip

men

t Rel

ated

‒ L

oS S

impl

e S

tatio

n 29

14

9 M

C26

‒ M

anuf

actu

ring

Rel

ated

Def

ects

28

15

0 S

TO2

‒ C

onst

ruct

ion

by 3

rd P

arty

‒ R

eser

voir

28

151

LNG

29 ‒

CN

G C

omm

odity

Sho

rtfal

l (R

elia

bilit

y)

28

152

STO

31.1

‒ S

tress

Cor

rosi

on C

rack

ing

‒ P

ipel

ine

28

153

CP

4 ‒

Wea

ther

Rel

ated

/Out

side

For

ces

‒ Fl

oodi

ng

(Sys

tem

Saf

ety)

25

154

CC

E2

‒ O

ther

Out

side

For

ce ‒

Thi

rd P

arty

Dam

age

‒ V

ehic

les

25

155

CC

E6

‒ M

ater

ial o

r Wel

d ‒

Poo

r Qua

lity

Con

trol o

f R

egul

ator

/Met

er S

et M

anuf

actu

ring

25

156

LNG

30.1

‒ In

corr

ect S

tatio

n O

ps

25

157

CP

23 ‒

Ket

tlem

an S

tatio

n C

ompr

esso

r Out

age

Due

to

Any

Cau

se (S

yste

m S

afet

y)

24

5-AtchA-4

As

of A

pril

14, 2

015

Gas

Ope

ratio

ns R

isk

Reg

iste

r (5/

5)

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 20

3 TR

A7

‒ Th

ird P

arty

/Mec

hani

cal D

amag

e (P

50)

6

204

MC

11 ‒

Inco

rrec

t Ope

ratio

ns ‒

LoS

Com

plex

/Sim

ple

Sta

tion

5

205

LNG

13 ‒

Thi

rd-P

arty

Dam

age

‒ D

ispe

nser

Van

dalis

m

4

206

LNG

20 ‒

Thi

rd-P

arty

Dam

age

‒ C

NG

Bot

tle T

rlr

Tran

spo

Inci

dent

4

207

DM

S17

‒ A

tmos

pher

ic C

orro

sion

3

208

CC

E3

‒ O

ther

Out

side

For

ce ‒

Van

dalis

m

3 20

9 TR

A15

‒ In

tern

al C

orro

sion

(P50

) 3

210

DM

S6

‒ M

ater

ial o

r Wel

d ‒

T-C

aps

2

211

TRA

5 ‒

Man

ufac

turin

g R

elat

ed D

efec

ts (P

50)

2

212

LNG

21 ‒

Thi

rd-P

arty

Dam

age

‒ C

NG

Bot

tle T

rlr P

arke

d C

ollis

ion

(Saf

ety)

1

213

STO

35 ‒

Out

side

For

ces

(Geo

logi

cal)

‒ R

eser

voir

1

214

GS

O10

‒ R

isk

of M

ultip

le C

lear

ance

s in

the

Sam

e G

as

Sys

tem

0

215

GS

O11

‒ In

adeq

uate

Vis

ibili

ty in

to th

e P

ress

ures

and

Fl

ows

on th

e N

etw

orks

0

216

GS

O12

‒ G

as C

ontro

l Ope

rato

r Err

or

0 21

7 G

SO

13 ‒

SC

AD

A O

utag

e 0

218

GS

O14

‒ P

hysi

cal S

ecur

ity ‒

Gas

Con

trol C

ente

r Atta

ck

0

219

GS

O15

‒ G

OC

Sys

tem

Fai

lure

Effe

ctin

g Fi

eld

Coo

rdin

atio

n an

d R

espo

nse

0

220

MC

8.1

‒ In

corr

ect O

pera

tions

(Sys

tem

Saf

ety)

0

221

MC

10.1

‒ In

corr

ect O

pera

tions

(Sys

tem

Saf

ety)

0

# R

isk

Nam

e C

urre

nt

Res

idua

l R

isk

Scor

e 17

9 S

TO17

.1 ‒

Ext

erna

l Cor

rosi

on ‒

Pip

elin

e 17

180

GS

O4

‒ Lo

ss o

f Sup

ply

from

Inte

rcon

nect

ed P

ipel

ines

an

d Th

ird P

arty

Sto

rage

14

181

DM

S12

‒ M

ater

ial o

r Wel

d ‒

Mec

hani

cal F

ittin

gs

14

182

CP

23.1

‒ K

ettle

man

Sta

tion

Out

age

Due

to P

ower

O

utag

e 14

183

LNG

17.1

‒ T

hird

-Par

ty D

amag

e ‒

LNG

Tan

ker P

arke

d (R

elia

bilit

y)

13

184

DM

S3

‒ E

xter

nal C

orro

sion

on

Ste

el P

ipin

g

12

185

DM

S49

‒ M

ater

ial o

r Wel

d ‒

Isol

atio

n V

alve

Fai

lure

11

18

6 G

SO

5 ‒

Por

tfolio

Man

agem

ent R

isk

11

187

STO

5.1

‒ C

orro

sion

‒ W

ell C

asin

g 11

18

8 S

TO1‒

Thi

rd P

arty

Dam

age

‒ R

eser

voir

10

189

LNG

14 ‒

Thi

rd-P

arty

Dam

age

‒ Fu

el T

heft

10

19

0 D

MS

25 ‒

Mat

eria

l and

Wel

d ‒

Cur

b V

alve

s

10

191

CC

E23

‒ N

atur

al F

orce

s ‒

Set

tlem

ent o

f Soi

l 10

192

DM

S11

‒ In

corr

ect O

pera

tions

‒ R

egul

ator

(Sem

i-Hig

h or

Hig

h P

ress

ure)

10

193

MC

20 ‒

Equ

ipm

ent R

elat

ed ‒

LoS

Com

plex

/Sim

ple

Sta

tion

10

194

CC

E16

‒ O

ther

Out

side

For

ce ‒

Inop

erab

le o

r In

acce

ssib

le S

ervi

ce V

alve

9

195

DM

S7

‒ N

atur

al F

orce

s ‒

Cas

t Iro

n M

ater

ial

8 19

6 G

SO

7 ‒

Pric

e R

isk

8 19

7 D

MS

48 ‒

Inte

rnal

Cor

rosi

on ‒

Mai

nlin

e D

rips

7 19

8 C

CE

21 ‒

Oth

er O

utsi

de F

orce

‒ F

ire

7 19

9 C

CE

1 ‒

Inco

rrec

t Ope

ratio

ns

7 20

0 M

C8

‒ In

corr

ect O

pera

tion

‒ Te

rmin

al/L

arge

Com

plex

6

201

MC

5 ‒

Inco

rrec

t Ope

ratio

ns ‒

Bac

kbon

e (P

LS) S

tatio

ns

6 20

2 TR

A2

‒ E

xter

nal C

orro

sion

(P50

) 6

5-AtchA-5

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 6

RISK LEXICON

6-1

PACIFIC GAS AND ELECTRIC COMPANY 1

CHAPTER 6 2

RISK LEXICON 3

This chapter provides a Risk Lexicon (Attachment A) that was developed in 4

collaboration with the other utilities participating in this proceeding. The Lexicon 5

includes terms that are used in risk management activities. Pacific Gas and Electric 6

Company (PG&E) views this Lexicon as a potentially valuable tool that can assist in 7

facilitating the discussion of risk and risk management. 8

PG&E’s opinion is that this Lexicon should be viewed as a living document that 9

can be added to and modified over time. To this end, PG&E proposes that this 10

Lexicon, and other terms as well, be made the subject of a workshop in this Safety 11

Model Assessment Proceeding. PG&E also proposes that the Commission publish 12

the Lexicon in a manner that provides for easy public access and use, and that it be 13

updated periodically. 14

Finally, there are two caveats that PG&E wishes to identify. First, it is not 15

always possible or practical to agree on only one definition for a term. The same 16

term is sometimes used somewhat differently in different companies or even within 17

the same company. Thus, it may be advisable in some circumstances to publish 18

more than one definition for a term. Second, the Commission should not mandate 19

the use of a particular definition or consider any penalties for the “misuse” of a term. 20

Rather these definitions should only be viewed as a tool with educational value that 21

over time will promote a common language about risk management. 22

PACIFIC GAS AND ELECTRIC COMPANY

CHAPTER 6

ATTACHMENT A

RISK LEXICON

6-AtchA-1

CHAPTER 6 ATTACHMENT A RISK LEXICON

Overview Based on the Refined Straw Proposal’s recommendations, PG&E, SCE, and

Sempra have developed a set of core key risk terms and definitions to be used “for

defining, acquiring, and disseminating risked-based information,”1 known as the Risk

Lexicon. The Risk Lexicon consists of a common set of terms and definitions to allow

for ease of communicating the risk-management activities described in this filing. In

addition to this set of core terms, each of the utilities may have additional risk terms and

definitions to describe their specific processes. As with the other tools, we expect the

Risk Lexicon to evolve as the ERM programs mature.

To develop the Risk Lexicon, PG&E, SCE, and Sempra looked first to the terms

and definitions in the ISO 31000 and DHS Risk Lexicon terminology documents. The

defined terms were further validated amongst a broader list of external sources common

in the risk community to ensure consistency. Below is the defined list of key terms

developed for the Risk Lexicon.

Terms Definitions

Alternatives Analysis Evaluation of different alternatives available to mitigate risk

Control Currently established measure that is modifying risk

Current Residual Risk Risk remaining after current controls

Enterprise Risk Management

Comprehensive approach to risk management that engages

organizational systems and processes together to improve the

quality of decision making for managing risks in order for an

organization to be able to achieve its objectives

1 Refined Straw Proposal, p. 10.

6-AtchA-2

Terms Definitions

Event Occurrence or change of a particular set of circumstances

Frequency Number of events generally defined per unit of time

Impact (or Consequence)

Result of an event, incident, or occurrence affecting objectives

Mitigation Measure or activity taken prior to the occurrence of an event,

designed to reduce impact and/or frequency of an event

Planned Residual Risk (or Forecasted Residual Risk)

Risk remaining after implementation of proposed mitigations

Risk Potential for an event that can impact company’s ability to achieve

its objectives

Risk-based Decision Making

Determination of a course of action predicated primarily on the

assessment of risk and the expected impact of that course of action

on that risk

Risk-informed Decision Making

Determination of a course of action predicated on the assessment

of risk, the expected impact of that course of action on that risk, as

well as other relevant factors

Risk Assessment Process

Overall process of risk identification, risk analysis and risk

evaluation

Risk Driver (or Risk Trigger)

Factor(s) that could cause risk to occur

Risk Response Plan (or Mitigation Plan)

Collection of Mitigations

Risk Score Numerical representation of a quantitative and/or qualitative risk

evaluation methodology

Risk Taxonomy A structure used to classify different types of risks across the

company at multiple levels of aggregation

PACIFIC GAS AND ELECTRIC COMPANY

APPENDIX A

STATEMENTS OF QUALIFICATIONS

EB-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF ERIC BACK 2

Q 1 Please state your name and business address. 3

A 1 My name is Eric Back, and my business address is Pacific Gas and Electric 4

Company, 245 Market Street, San Francisco, California. 5

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6

(PG&E). 7

A 2 I am the director of the Compliance & Risk Management organization within 8

Electric Operations. 9

Q 3 Please summarize your educational and professional background. 10

A 3 I am the director for Risk Management, Compliance, and Vegetation 11

Management in Electric Operations. I joined PG&E in 2008 and worked in 12

the Utility Performance Improvement group focusing on electric transmission 13

and substation facilities and processes. Since then, I have been a 14

substation maintenance superintendent and a director in Transmission 15

Operations. Prior to joining PG&E, I worked in management and operations 16

consulting. I am a registered professional engineer in the state of California. 17

I have a bachelor of science degree in mechanical engineering from 18

University of California, Davis, a master of science degree in mechanical 19

engineering from Colorado State University and a master in business 20

administration degree from the London Business School. 21

Q 4 What is the purpose of your testimony? 22

A 4 I am sponsoring Chapter 4, “Electric Operations and Nuclear Power 23

Generation,” with the exception of Sections B.2. and C.2., in PG&E’s S-MAP 24

proceeding. Sections B.2. and C.2. relate to the risk processes and 25

programs at PG&E’s nuclear facilities and are sponsored by Cary D. Harbor. 26

Q 5 Does this conclude your statement of qualifications? 27

A 5 Yes, it does. 28

CCC-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF CHRISTINE C. CHAPMAN 2

Q 1 Please state your name and business address. 3

A 1 My name is Christine C. Chapman, and my business address is Pacific Gas 4

and Electric Company, 6111 Bollinger Canyon Road, San Ramon, 5

California. 6

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 7

(PG&E). 8

A 2 As senior director of Asset Knowledge and Integrity Management, within 9

Gas Operations, I am responsible for the leadership and oversight of an 10

organization focused on assessing the integrity of the transmission, 11

distribution, and facilities assets utilizing traceable, verifiable, and complete 12

asset knowledge and technological tools. I am also responsible for the 13

development of a strategic integrity management plan for the entirety of 14

these assets. In addition, I oversee Gas Operations’ Research and 15

Development Program. 16

Q 3 Please summarize your educational and professional background. 17

A 3 I received a bachelor of science degree in mechanical engineering from 18

University of California, Berkeley and a master’s degree in business 19

administration from UC Berkeley, Haas School of Business. I am also a 20

registered professional mechanical engineer in the state of California. 21

I started with PG&E in 2001 as a summer intern in the gas distribution 22

organization and after graduating from UC Berkeley began a full-time 23

position as a gas engineer. Since then, I have held a variety of positions 24

with increasing levels of responsibility in the Gas Engineering and 25

Operations organization, mainly focused on gas distribution functions. 26

In 2008, I transitioned to PG&E’s Human Resources Department where 27

I held various leadership roles. I returned to Gas Operations in 28

January 2012 as the director of Distribution Integrity Management. In 29

November 2013, I transitioned to the director of Transmission Integrity 30

Management, and in May 2014, I was promoted to the senior director of 31

Asset Knowledge and Integrity Management. 32

CCC-2

Q 4 What is the purpose of your testimony? 1

A 4 I am sponsoring Chapter 5, “Gas Operations,” in PG&E’s S-MAP 2

proceeding. 3

Q 5 Does this conclude your statement of qualifications? 4

A 5 Yes, it does. 5

CDH-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF CARY D. HARBOR 2

Q 1 Please state your name and business address. 3

A 1 My name is Cary D. Harbor, and my business address is Pacific Gas and 4

Electric Company, Diablo Canyon Power Plant. 5

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6

(PG&E). 7

A 2 I am the director of Compliance, Alliance and Risk for the Diablo Canyon 8

Power Plant; in this capacity I am responsible for company compliance and 9

risk program oversight, matrixed organizations including business finance 10

and supply chain, and the PG&E management council representative to the 11

STARS LLC. 12

Q 3 Please summarize your educational and professional background. 13

A 3 I received a bachelor of science degree in nuclear engineering from 14

University of California, Santa Barbara, California, in 1989. I joined PG&E in 15

1989 as a power production engineer in the Engineering Department. 16

I have since held positions as the supervisor of Regulatory Services, 17

operations shift foreman/manager (senior reactor operator licensed by the 18

Nuclear Regulatory Commission), performance improvement manager, 19

quality verification director, and the Maintenance and Construction Services 20

director. Most recently I became the director of Compliance, Alliance and 21

Risk in 2012. 22

Q 4 What is the purpose of your testimony? 23

A 4 I am sponsoring Sections B.2. and C.2. of Chapter 4, “Electric Operations 24

and Nuclear Power Generation,” in PG&E’s S-MAP proceeding. 25

Q 5 Does this conclude your statement of qualifications? 26

A 5 Yes, it does. 27

JM-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF JANAIZE MARKLAND 2

Q 1 Please state your name and business address. 3

A 1 My name is Janaize Markland, and my business address is Pacific Gas and 4

Electric Company, 111 Stony Circle, Santa Rosa, California. 5

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6

(PG&E). 7

A 2 I am the director of PG&E’s Enterprise and Operational Risk and Insurance 8

Department. My department is responsible for overseeing PG&E’s 9

Enterprise and Operational Risk Management (EORM) Program and for 10

procuring insurance to transfer PG&E’s residual financial risks that could 11

result from catastrophic property or casualty losses. 12

Q 3 Please summarize your educational and professional background. 13

A 3 I earned a bachelor of science degree in chemistry from the University of 14

British Columbia and a master of science degree in Environmental 15

Management from Royal Roads University in Victoria, British Columbia. 16

I am a member of the Enterprise Risk Management Utilities Roundtable 17

and serve as chair of the Edison Electric Institute Enterprise Risk 18

Management Task Force Steering Committee. 19

Prior to my career in the EORM and Insurance Department, I held a 20

variety of roles at PG&E, including manager of Compliance and Ethics and 21

positions in the Safety and Shared Services organization, where I provided 22

direct environmental compliance support to PG&E’s operating units. Before 23

joining PG&E, I worked at BC TEL, a telephone utility based in Burnaby, 24

British Columbia, and its successor company, Alberta-based TELUS 25

Corporation, where I developed an environmental program governing the 26

newly merged companies. 27

Q 4 What is the purpose of your testimony? 28

A 4 I am sponsoring the following testimony in PG&E’s S-MAP proceeding: 29

Chapter 2, “Companywide Models and Approaches for Assessing Risk.” 30

Chapter 6, “Risk Lexicon.” 31

Q 5 Does this conclude your statement of qualifications? 32

A 5 Yes, it does. 33

JLM-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF JAMIE L. MARTIN 2

Q 1 Please state your name and business address. 3

A 1 My name is Jamie L. Martin, and my business address is Pacific Gas and 4

Electric Company, 77 Beale Street, San Francisco, California. 5

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6

(PG&E). 7

A 2 I currently hold the position of director of Economic and Project Analysis. In 8

this capacity, I supervise: 9

Financial analysis and economic evaluations concerning a range of 10

investment matters. 11

The Risk Informed Budget Allocation process as part of the Company’s 12

Integrated Planning Process. 13

Business case guidance and reviews of major capital project proposals. 14

I report to the Vice President, Finance, of PG&E. 15

Q 3 Please summarize your educational and professional background. 16

A 3 I graduated from the University of San Francisco, in 2004, with a bachelor of 17

science degree in finance. I joined PG&E in 2007 as a senior business 18

analyst in the Finance organization, specifically in Project Finance. I have 19

since held a succession of positions in the finance organization. In 2009, 20

I was promoted to supervisor in the Gas & Electric Transmission and 21

Distribution Business Finance organization, responsible for operational 22

financial planning, budgeting and forecasting. In 2010, I was promoted to 23

manager in the Power Generation Business Finance organization, where 24

I was responsible for managing a team that supported operational financial 25

planning, budgeting and forecasting. In 2012, I completed a 6-month 26

rotation as manager of Investor Relations, where I was responsible for 27

communication with the investment community and prepared senior 28

leadership for quarterly earnings calls and expectations for future 29

performance. In late 2012, I became manager of the Financial Forecasting 30

& Reporting team, where I was responsible for enterprise-level earnings 31

forecasts, year-over-year and long-term budgets and forecasts, functional 32

JLM-2

area income statement analysis and board of director financial materials. 1

I assumed my current position in March 2014. 2

Q 4 What is the purpose of your testimony? 3

A 4 I am sponsoring Chapter 3, “Companywide Models and Approaches to Risk 4

Informed Budget Allocation,” in PG&E’s S-MAP proceeding. 5

Q 5 Does this conclude your statement of qualifications? 6

A 5 Yes, it does. 7

SJS-1

PACIFIC GAS AND ELECTRIC COMPANY 1

STATEMENT OF QUALIFICATIONS OF SHELLY J. SHARP 2

Q 1 Please state your name and business address. 3

A 1 My name is Shelly J. Sharp, and my business address is Pacific Gas and 4

Electric Company, 77 Beale, San Francisco, California. 5

Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 6

(PG&E). 7

A 2 I am currently the senior director, General Rate Case and Regulatory 8

Support. My responsibilities include overseeing the development of General 9

Rate Cases (GRC) as well as various other applications before the 10

California Public Utilities Commission, ensuring compliance with items from 11

prior GRCs, and directing the efforts of PG&E’s regulatory support functions. 12

Q 3 Please summarize your educational and professional background. 13

A 3 I graduated with a bachelor of science degree in business administration/ 14

finance from California State University, Sacramento, in 1984. In 1985, 15

I graduated from Golden Gate University in San Francisco, with a master’s 16

degree in business administration/finance. 17

I joined PG&E in 1985. From 1985 until 1997, I held various analyst and 18

supervisory positions within the regulatory area including: regulatory affairs 19

analyst, rates analyst, resource analyst, supervisor – Gas Rates, and 20

manager – Electric Rates. In 1997, I took over as the director of the Rates 21

Department, responsible for both gas and electric revenue allocation and 22

rate design. In 2003, I became the director of Billing, Revenue and 23

Records. In 2007, I became the senior director of Service and Sales in the 24

Customer Care organization. In February 2008, I became the senior 25

director of Customer Field Service within the Customer Care organization. 26

Q 4 What is the purpose of your testimony? 27

A 4 I am sponsoring Chapter 1, “Overview and Summary,” in PG&E’s S-MAP 28

proceeding. 29

Q 5 Does this conclude your statement of qualifications? 30

A 5 Yes, it does. 31