Wires Down -- Vegetation 

Injuries/Fatalities 

• 3 contacts as a result of a vegetation related wire down

Fire Ignitions 

• Number of events is decreasing. Typical event involves

less than 10 acres but the possibility of a catastrophic fire 

exists: 

o Southern California: 2008 Witch Creek, Guejito and Rice

fires (SDG&E) and Malibu Canyon Fire (SCE)

o PG&E: 2008 Whiskey Fire - 7,783 acres (Tehama county)

• The risk of catastrophic wild fire will be addressed as part

the enterprise risk management assessment

• System Protection will have a separate risk assessment

and will include a recommendation to review reclose relay

settings in UWF/OWF/SBWF areas

Property Damage 

• 4 property damage events due to vegetation related wire

down 

103

89

73

110

0

80

60

40

20

120

100

Vegetation-Relat

Fire 

≤ 10 

10 to 1

100 to 1

1,000 to 1

> 10,0

To

OH Pr

Fires by 

1 acr

4-AtchB-11 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 1 of 52
• The system average of wire down events due to equipment failure is 0.77 per 

• East Bay, San Francisco, Peninsula, Central Coast and Sacramento have val

Wire Down 

system average. Except for Sacramento, all the divisions have corrosion area

-- Equipment Failure 

0.49 

0.49 

0.51 0.54 0.58 0.59 

0.67 

0.73 0.73 0.76 

0.89 0.91 0.92 

1.00 

 -

 2.50

 2.00

 1.50

 1.00

 0.50

WD per 100 miles of OH Conductor

Wire-Down per 100 Miles of OH Conductor

(2012 - 2013 Equip Failure Related)

system average = 0.77 per 100 Mile

• Wire size, type and location are attributes

4-AtchB-12 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 2 of 52
Conductor Size 

• Small wire (< 1/0) wire down rate is 9% higher than the system ave

Conductor Type 

• The performance of copper conductor is significantly worse than th

(1.15 vs. 0.77)

Corrosion Zone 

• The performance of conductors in corrosion zones is worse than n

o 6 Cu is estimated to be 2.5 times higher in corrosion zone

o 4 ACSR is estimated to be 13 times higher in corrosion zone

• The following divisions have corrosion zones

Equipment Related Wire Down - Attributes 

 Humboldt  Peninsula

 Sonoma  Central Coast

 North Bay  Los Padres

 Mission  San Francisco

 East Bay

• Six of these divisions have wire down rates greater than the system 

4-AtchB-13 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 3 of 52
Attributes That Potentially Increase the 

Consequences of a Wire Down Event 

Attribute # 6 Cu # 4 Cu 

Other Small

Copper 

Conductors

Sub Total 

Copper 4 ACSR 2 ACS

Wild Fire Area 310 104 67 481 549 98 

Urban Population Area 7,738 1,931 660 10,329 8,409 276 

Corrosion Area 2,341 586 218 3,145 683 16 

• Asset location is an attribute that increases the negative consequence o

o Wild Fire Area (Urban, Other, Santa Barbara)

o Urban Population Areas (using GIS definition of 1,000 people/squ

o Corrosion Areas

o Major roadways and waterways

• Wire down events where conductor remains energized is another attribu

increases the consequences of wire down events

o Energized conductor data varies considerably between divisions. 

collection is needed

• Number of in-line connectors also influences likelihood of failure

Estimated Amounts of Small Wire Sizes by Attribute 

4-AtchB-14 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 4 of 52
Current Control Mitigations -- Intact Contact 

 Vegetation Management

o Routine trimming & removal (~ 1.3 million units/year)

o 99.5 % compliance with regulatory requirements

o Work at historic outage locations

o Pilot analyzing failure characteristics of otherwise

healthy trees in wildfire areas

 Design, Construction and Operating

Requirements

o Clearance requirements

o Warning signs

 Overhead Line Maintenance Program

o Visual patrols and inspections that can potentially

identify issues such as excessive sag, inadequate

clearances, vegetation problems, etc.

 Public Awareness Programs

o Wire Down awareness

o Tree Trimmers awareness

o Need awareness program for specific third parties

such as painters, roofers, cable, crane operators

4-AtchB-15 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 5 of 52
Current Control Mitigations -- Wire Down Contact 

 Vegetation Management (see prior page)

 Public Awareness Programs

o Wire Down awareness

o Tree Trimmers awareness

 Design, Construction and Operating Requirements

o Bulletins addressing the use of 6 Cu and automatic

splices

o Expanding corrosion area boundaries

o Review of minimum wire sizes

o Review of splices per span and application of shunt

splices

 OH Conductor Replacement Program

o Replaced 96 miles in 2013. 2014 plan is to replace 187

circuit miles (capacity and reliability programs)

 Infrared and Splice Inventory Program

o Assessed 10,000 miles in 2013. 2014 plan to infrared

and inventory splices on another 10,000 miles.

 System Protection

o 2012 review concluded that PG&E’s practices reflect

what is currently considered good practice in the

industry

 Line Maintenance 

o Visual patrols and in

identify issues such 

clearances, vegetat

 911 Response

o Processes and met

manner to emergen

4-AtchB-16 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 6 of 52
Current Controls Assessment - Amber 

Risk D

Current Controls

Control Description

Frequency/Im

pact 

Control Type Third-Party

Equipment 

Failure 

Veget

Public Awareness Programs (Wire Down/Tree 

Workers)

Frequency 

Preventive 

(administrative)

Vegetation Management Frequency Preventive 

Line Maintenance Program Frequency Preventive 

Design, Construction and Operating Procedures Both 

Preventive 

(administrative)

Conductor Replacement Program Frequency Preventive 

Infrared Inspection /Splice Inventory Frequency Preventive 

Site Investigation (wire down, vegetation, work 

procedure)

Frequency Preventive 

System Protection (separate risk evaluation) Impact Detective 

911 Response Impact Preventive 

Adequate Control Weak Control Strong Control 

4-AtchB-17 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 7 of 52
Recommendations – New Risk Mitigations 

Work Recommended

Risk Driver 

Affected

Addresses 

Impact/ 

Frequency

Proposed 

Action Owner

Timing 

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

3

rd

 party 

Frequency 

& Impact 

Complete plan 

by Q2 2014 

C

C

C

a

d

Review tree trimming practices 

to explore opportunities to focus 

on historical wire down locations

Vegetation Frequency

Complete 

Evaluation and 

Finalize Plan by 

Q2 2014 

F

v

a

Revise STAR Tool to assign 

additional risk to small and 

copper wires and locations with 

higher failure rates

Equipment Frequency

Complete by Q2 

2014

A

l

c

p

r

Develop a plan, including 

quantities and schedules, to 

replace certain small wire (such 

as 4 Cu, 6 Cu & ACSR) in wild 

fire areas, urban areas and high 

corrosion areas. 

Equipment 

Failure 

Frequency

Plan: Q2 2014

Implement: 

Q3 2014 

4-AtchB-18 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 8 of 52
Recommendations – New Risk Mitigations 

Work Recommended

Risk Driver 

Affected

Addresses 

Impact/ 

Frequency 

Proposed Action 

Owner 

Timing 

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.

Equipment 

Failure 

Frequency Complete Q1, 2014

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.

Third Party 

Frequency & 

Impact 

Complete Q2, 2014

Prior to executing new recommendations, we find the current residual risk of ED OH 

“amber”. Upon implementation of proposed incremental controls and continuation o

anticipate the future residual risk will continue to be “amber.” 

4-AtchB-19 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 9 of 52
Risk Scenarios – Current Residual Risk 

Typical result of an asset failure: 

A service interruption to approximately 350 customers for approximately two hours (

days) and does not result in an electric contact or fire ignition. 

Extreme result of an asset failure: 

A conductor failure or tree contact causing: 

(a) A relatively small (<1000 acres) fire in a densely populated area (e.g., Oak

significant property damage, fatalities and injuries; or 

(b) A large fire in a rural area involving more than 100 square miles (approxim

resulting in limited property damage but would include fatalities and injuries

These scenarios are used to score and prioritize our relative risk in the Risk Registe

Risk 

Scenario

Frequency 

Level*

Impact Level*

Safety Environmental Compliance Reliability Reputatio

Typical 7 1 1 1 3 1 

Extreme 3 6 6 5 4 6 

Risk Evaluation Tool (7x7) scoring of scenarios: 

*Definitions of ranking levels are based on the enterprise risk management 7x7 matrix v5.

Current 

Residual 

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Targeting locations using likelihood and consequ

4-AtchB-21 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 11 of 52
Conductor Age Data 

• Conductor age data in CEDSA is inaccurate – the significant increase in conductor a

of a technology system conversion in the late 1980’s where the year installed field be

and 1988, 1989 and 1990 was entered for many previously-blank line section record

• Using distribution pole age we can estimate that:

 25% of OH conductor is over 50 years old

 50% of OH conductor is 40 years old

 75% of OH is over 27 years old

• There is no age data for splices/connectors.

0%

75%

50%

25%

100%

46 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 00 

Cumulative %

Year Installed

Distribution Poles and OH Primary Conductor by Year Installed

OH Primary Con

Distribution Poles

4-AtchB-22 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 12 of 52
Asset Performance 

Basic Cause 2008 2009 2010 2011 2012 Total

5 Year 

Avg

% of 

Total

Vegetation 2,266 2,226 2,236 2,083 2,412 11,223 2,245 41%

Equipment Failure 2,505 2,155 2,037 1,956 2,133 10,786 2,157 39%

Third-party 508 496 503 570 586 2,663 533 10%

Animal 367 403 463 633 652 2,518 504 9%

Company Initiated 47 42 40 55 60 244 49 1%

Unknown cause 43 43 56 51 34 227 45 1%

Total 5,736 5,365 5,335 5,348 5,877 27,661 5,532 100%

Sustained Outages by Basic Cause -- 2008 to 2012 (excluding major event days) 

The leadin

 Ve

 Eq

 Th

 An

OH Asset Type 2008 2009 2010 2011 2012 Total

5 Year 

Avg

% of 

Total

Conductor, Overhead 4,646 4,359 4,412 4,466 4,830 22,713 4,543 82%

Connector or splice 350 340 345 358 450 1,843 369 7%

Jumper 724 653 566 517 589 3,049 610 11%

PG's, Kearneys 16 13 12 7 8 56 11 0%

Total 5,736 5,365 5,335 5,348 5,877 27,661 5,532 100%

• Person

connec

data re

splice/c

Improv

necess

• The tables below show sustained outages by:

 Basic cause – which identifies leading risk drivers

 Asset type – which is potentially useful in understanding performance from a conductor v

Sustained Outages by Asset Type -- 2008 to 2012 (excluding major event days) 

4-AtchB-23 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 13 of 52
PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 5 

GAS OPERATIONS 

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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

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5-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 5 

3 GAS OPERATIONS 

4 A. Introduction

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

6 Gas Operations organization is using the Enterprise and Operational Risk 

7 Management (EORM) Standard, its Integrity Management program, and other 

8 tools to manage gas system risks. 

9 B. General Processes 

10 1. Organizational Structure 

11 Within Gas Operations, risk management is owned by the Risk Register, 

12 Asset Knowledge and Integrity Management, and Investment Planning 

13 departments. 

14  The Risk Register team is responsible for overseeing risk management 

15 activities driven by the EORM Program. This includes maintenance of 

16 Gas Operations’ Risk Register and implementation of the Session D 

17 process. 

18  The Asset Knowledge and Integrity Management (AK&IM) Department 

19 is responsible for overseeing PG&E’s Transmission Integrity 

20 Management Program (TIMP), Distribution Integrity Management 

21 Program (DIMP), and Facility Integrity Management Program (FIMP). 

22 These programs are driven by federal requirements1 and involve risk 

23 management programs that are focused on asset-related threats and 

24 risks. The Senior Director of AK&IM is also accountable for the asset 

25 management planning processes within Gas Operations2 and oversees 

26 the development of asset management plans for each of Gas 

 

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. 

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5-2 

1 Operations’ asset families. Asset families and asset management plans 

2 are described in more detail below. 

3  The Investment Planning team is responsible for overseeing Gas 

4 Operations’ implementation of the Risk Informed Budget Allocation 

5 (RIBA) process described in Chapter 2. 

6 In mid-2012, PG&E introduced a new paradigm into Gas Operations. 

7 PG&E divided its assets into families and designated an individual—the 

8 Asset Family Owner (AFO)—for each asset family who is accountable for 

9 managing the health of those assets. 

10 PG&E has identified eight asset families within Gas Operations. These 

11 are outlined in Figure 5-1 below. 

FIGURE 5-1 

PACIFIC GAS AND ELECTRIC COMPANY 

GAS OPERATIONS ASSET FAMILIES 

12 Risks are identified and included in the Gas Operations Risk Register 

13 based on the asset family structure, and investment decisions are made 

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5-3 

1 within and across asset families aligned with the investment planning, 

2 budgeting, and rate case frameworks. 

3 In addition, Gas Operations implemented a new risk and asset 

4 management process and strengthened senior leadership oversight through 

5 its Risk and Compliance Committee (RCC). The RCC is chaired by the 

6 Executive Vice President, who appoints representatives from Gas 

7 Operations to participate on the committee. RCC members have a broad 

8 understanding of the business, its processes, and associated risks. The 

9 RCC meets monthly to review current risk-related topics and approve items 

10 such as risk assessments, risk mitigation measures and changes to the Risk 

11 Register.

12 2. Enterprise and Operational Risk Management and Integrated Planning 

13 Processes 

14 As described in Chapter 2, PG&E’s EORM Program allows PG&E to 

15 manage assets and risks at both an enterprise and operational level. The 

16 enterprise risks are those that could threaten the viability of PG&E and 

17 typically span multiple lines of business (LOBs). Operational risks arise 

18 from assets, people, processes and technologies within specific LOBs, such 

19 as Gas Operations. By assessing and managing risks from both points of 

20 view, PG&E can better manage the interdependencies and drive for 

21 consistency among LOBs. 

22 Gas Operations has adopted a risk management process that provides 

23 a repeatable and consistent method to identify, assess, rank and mitigate 

24 risk. This risk management process is fully integrated into PG&E’s 

25 Integrated Planning Process to ensure risk informs the chosen strategies, 

26 which in turn drives the allocation of resources. Gas Operations has been 

27 advancing its risk management methodology over the last three years, and 

28 continues to (i) increase the rigor and documentation of the risk 

29 management process; (ii) use more data; (iii) expand the scope of risks 

30 assessed as part of the process; and (iv) improve consistency of risk scoring 

31 across Gas Operations. 

32 The three phases of Gas Operations’ risk management and planning 

33 process—(1) Identify threats and assess risks by Asset Family; (2) Develop 

34 proposed mitigation programs within Asset Families; and (3) Develop 

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5-4 

1 executable Investment Plan—are aligned with the PG&E’s Integrated 

2 Planning Process. The three phases are depicted in Figure 5-2.

FIGURE 5-2 

PACIFIC GAS AND ELECTRIC COMPANY 

RISK MANAGEMENT PROCESS AND PLANNING 

3 Additional information on PG&E’s Integrated Planning Process can be 

4 found in Chapters 1, 2 and 3.

5 3. Risk-Based Prioritization Methodologies 

6 To support decision making in the Integrated Planning Process, Gas 

7 Operations uses several methodologies to prioritize programs and projects. 

8 Some examples of these approaches are outlined in this section. 

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5-5 

1 a. DIMP

2 Federal regulations3 require Gas Operators to develop an approach 

3 to ensure the integrity of its distribution system. PG&E’s overarching 

4 DIMP framework is outlined in Figure 5-3 below: 

FIGURE 5-3 

PACIFIC GAS AND ELECTRIC COMPANY 

DIMP CONTINUOUS IMPROVEMENT CYCLE 

5 Consistent with other gas operators within California, PG&E uses a 

6 leak-based risk model to assess the risk of distribution pipelines. 

7 This model considers five years of historical leak data to identify 

8 geographical areas with elevated risk. A negative trend of leak repairs 

9 for a geographic area for each threat helps identify where additional 

10 mitigation may be applied. 

11 The California Public Utilities Commission (CPUC) oversees DIMP 

12 and periodically performs audits in accordance with State and Federal 

 

3 49 CFR, Part 192-Transportation of Natural and Other Gas by Pipeline: Minimum 

Federal Standards, Subpart P – Gas Distribution Pipeline Integrity Management. 

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5-6 

1 Guidelines.4 Some of the topics addressed in the audits include a 

2 review of how operators identify threats, perform risk evaluation, and 

3 identify mitigation.5

4 Each of the seven steps in PG&E’s DIMP cycle is summarized 

5 below. 

6 1) Know the PG&E System 

7 System knowledge is the core foundation of DIMP and improves 

8 the overall safety and reliability of the distribution pipeline system. 

9 At the beginning of each DIMP cycle, the DIMP Mitigation and DIMP 

10 Risk teams review the data sources. Consideration is given to 

11 information gained from design records, operations, and 

12 maintenance as well as knowledge gained from the DIMP Steering 

13 Committee, which is comprised of members of the DIMP team and 

14 is supplemented with subject matter experts (SME) in each of the 

15 DIMP threat categories. 

16 PG&E’s DIMP Risk team uses the data, outlined in Figure 5-4, 

17 to provide a comprehensive dataset for risk evaluation. As shown in 

18 Figure 5-4, a majority of the data used is entered into SAP.6 

19 This data is entered by field personnel conducting leak surveys, 

20 excavation activities, or other field activities along the pipeline. 

21 PG&E uses 20 attribute data fields for its risk analysis. 

 

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.

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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

1 Other data fields extracted from SAP are reviewed and help in 

2 determining appropriate mitigation activities. 

3 2) Identify Threats 

4 PG&E uses leak data and SME input for threat identification and 

5 risk evaluation. The DIMP Risk team reviews the collected dataset 

6 and assigns one of eight threat categories (identified in 49 CFR 

7 Part 192, Subpart P) to each leak. The DIMP Risk team then 

8 applies sub threats, which identify risk drivers and determines if 

9 accelerated actions are needed to mitigate risk. 

10 Additionally, PG&E monitors potential threats. These threats 

11 are identified by data sources independent from leak repair 

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5-8 

1 (Figure 5-5). This includes reviewing internal, industry and 

2 government data sources to generate a potential threat list which is 

3 annually reviewed and evaluated for risk. The identified potential 

4 threat list, its validity and any action required is reviewed and 

5 approved by the DIMP Steering Committee.

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

6 3) Evaluate and Rank Risks 

7 The risk assessment for the gas distribution system is informed 

8 from its leak history. In the assessment, each leak receives a score 

9 based on its Likelihood of Failure (LoF) and Consequence of Failure 

10 (CoF). The LoF for each leak is equal to 1 since the failure has 

11 already occurred. The CoF portion of the risk model is based on the 

12 following components: Impact on Life; Consequence Potential; 

13 Leak Magnitude; and Injury/Fatality statistics. Figure 5-6 outlines 

14 the variables considered in each of these components. The 

15 variables of each component are identified and the relative severity 

16 of a variable’s points determines the contribution to the 

17 consequence of a leak. 

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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)]

1 As shown in the equation below, the total consequence 

2 associated with each threat is the sum of the applicable leak 

3 consequence scores. 

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 

4 The risk scores from this equation are aggregated by 

5 geographical area to develop a relative risk ranking of all threats and 

6 geographical areas. 

7 Following the calculation of the risk scores, the DIMP Risk team 

8 analyzes risk at the appropriate level of aggregation for each threat. 

9 Excavation is a threat that varies at a local level, and therefore must 

10 be managed and mitigated at the local level. Because of this, PG&E 

11 separates out excavation threats from this analysis, and reviews this 

12 risk at the city level. Figures 5-7 and 5-8 below show the risk 

13 analysis done for excavation at the city level, and the analysis done 

14 for all other threats at the district (subset of a PG&E division) level. 

15 Values to the right of the vertical lines represent high risk, and the 

16 values within the two lines define medium risk areas. 

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5-10

FIGURE 5-7 

PACIFIC GAS AND ELECTRIC COMPANY 

RISK FOR EXCAVATION – CITY LEVEL 

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5-11

FIGURE 5-8 

PACIFIC GAS AND ELECTRIC COMPANY 

RISK FOR ALL CAUSES EXCEPT EXCAVATION – DISTRICT LEVEL 

1 The DIMP Risk team uses standard deviations to define 

2 distribution bands in determining geographic areas of low, medium, 

3 or high risk for each of the two risk analyses shown in Figures 5-7 

4 and 5-8.

5 System performance is identified based on a 5-year linear trend 

6 of leak repairs for the same geographic area for each threat. The 

7 leak data gathered (as summarized in Figure 5-4) is reviewed for 

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5-12

1 this analysis. Good performance is indicated by a decreasing 

2 5-year linear trend. Fair performance is indicated by a flat (slope 

3 equals zero) 5-year linear trend. Poor performance is indicated by 

4 an increasing 5-year linear trend. 

5 The combination of risk scores and system performance, 

6 outlined below, determine if a Root Cause Analysis (RCA) is 

7 needed. RCAs help determine the appropriate mitigation activities 

8 for each threat. PG&E performs RCAs in cases as shown in 

9 Figure 5-9.

FIGURE 5-9 

PACIFIC GAS AND ELECTRIC COMPANY 

NEED FOR ROOT CAUSE ANALYSIS DETERMINATION

Performance

Good Fair Poor

Risk

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

10 4) Implement Measures to Address Risks 

11 The DIMP Mitigation team considers all current and applicable 

12 mitigation measures. During this review the DIMP Mitigation team 

13 will identify new mitigation measures or changes to the program that 

14 will reduce risk.7 If existing programs and activities do not 

15 adequately address the risk, the team will work to develop a new 

16 program or project to mitigate the risk. Program specific mitigation 

17 actions such as the Aldyl-A Replacement program and the Gas 

18 Pipeline Replacement Program are reviewed to ensure work is 

19 prioritized accordingly. These programs and projects are included in 

20 the Session 1 and Session 2 processes to be prioritized and 

21 funded accordingly. 

 

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. 

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5-13

1 5) Measure Performance, Monitor Results and Evaluate 

2 Effectiveness 

3 In accordance with the program evaluation requirements,8

4 PG&E performs reviews and evaluations annually. The review 

5 includes refreshing leak data to incorporate new risks into the risk 

6 management process. The process described above is applied to 

7 the refreshed data, and included in the risk prioritization of the gas 

8 distribution system. Additionally, the DIMP Risk team evaluates 

9 existing algorithms and statistical methodologies used to derive the 

10 overall risk score. 

11 6) Conduct Complete Program Evaluations and Make 

12 Improvements 

13 PG&E performs reviews and evaluations of its threat 

14 identification, risk analysis, and mitigation performance on a periodic 

15 basis. PG&E also participates in internal quality assurance audits 

16 as well as external audits performed by regulatory agencies to 

17 ensure the program is meeting legal requirements. 

18 7) Report Results 

19 PG&E communicates the status of its reviews to key internal 

20 stakeholders on an annual basis. Additionally PG&E completes 

21 the following PHMSA forms: PHMSA F 7100.1-1 (Annual Report 

22 Form)9 and PHMSA F 7100.1-2 (Mechanical Fitting Failure 

23 Report Form). 

24 b. Program-Specific Prioritization Methodologies 

25 For most risk-based programs, it is necessary to have a prioritization 

26 methodology that allows for risk ranking at the granular asset level to 

27 allow for implementation of the program over multiple years while 

28 maximizing risk reduction in the short term. Each program has either a 

 

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. 

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5-14

1 relative risk calculation methodology including components related to 

2 likelihood of failure and consequence of failure, or a decision tree 

3 methodology that prioritizes projects into tranches of equivalent risk. 

4 Below are some of the risk mitigation programs included in the 

5 Integrated Planning Process: 

6  Aldyl-A Replacement Program – replacement of Aldyl-A pipe based 

7 on vintage, material properties, leak history, and other factors. 

8  Gas Pipeline Replacement Program – replacement of cast iron and 

9 pre-1940 steel based on leak history, vintage, material properties, 

10 corrosion potential, and other factors. 

11  High-Pressure Regulator (HPR) Replacement Program – 

12 replacement of HPRs based on vintage, material properties, and 

13 other factors. 

14 4. Gas Operations Integrated Planning Process 

15 Gas Operations follows the PG&E Integrated Planning process for 

16 identifying risks, developing mitigation programs, and prioritizing work to 

17 address risks. The details of Gas Operations’ approach to this process are 

18 outlined below. 

19 a. Session D and Risk Register 

20 Each AFO with the assistance of SMEs, is responsible for identifying 

21 the risks associated with their asset family and scoring each risk based 

22 on system knowledge, available data, and SME knowledge. The 

23 categorization and evaluation of threats and risks are driven by 

24 industry-adopted integrity management principles,10 PG&E’s obligation 

25 to serve—both in terms of ensuring reliable delivery of natural gas and 

26 increasing capacity to meet demand—as well as risks posed by an 

27 inadequate response to and recovery from emergencies. 

28 As stated above, PG&E has strengthened and advanced its risk 

29 management methodology. By implementing the process improvements 

30 noted below, PG&E has been able to effectively identify and score risks 

31 within Gas Operations: 

 

10 For transmission assets, threats follow American Society of Mechanical 

Engineers B31.8S. For distribution assets, threats follow 49 CFR 192 Subpart P.

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5-15

1  Greater Utilization and Integration of Data: Gas Operations has 

2 increased visibility into potential risks by integrating Corrective 

3 Action Plan (CAP) and process hazard analysis data into the risk 

4 identification and scoring processes. 

5  Increased Rigor and Documentation: SME input is used for 

6 identification and validation of risks. Additionally, SME review and 

7 sign-off is required for each asset family’s risk register. 

8  Expanded Scope of Risk Assessment: Risks that fall outside the 

9 asset families’ risk registers, such as Gas System Operations and 

10 Employee Qualification risks, are identified, scored, and calibrated 

11 against asset risks and are included in the Risk Register for 

12 Gas Operations. 

13  External Review: PG&E has leveraged the use of third-party 

14 industry experts to validate Gas Operations’ risk methodology and 

15 scoring. 

16  Calibration of Risk: This is achieved through the consistent 

17 application and calibration of risk categories and the risk scoring 

18 across Gas Operations risks. 

19 After identifying and scoring the risks, AFOs meet with the Gas 

20 Operations’ Risk Register team to calibrate and validate ranking of each 

21 threat. The AFOs document this ranking in a Risk Register 

22 (Attachment A), which is updated and refined as additional information is 

23 obtained and evaluated. Gas Operations communicates its top risks 

24 (based on the Risk Register scoring) to PG&E leadership in Session D 

25 of the Integrated Planning Process. Each risk is evaluated to determine 

26 if existing mitigations are effectively managing the risk. During this step, 

27 the AFOs also identify any interdependencies with other LOBs to 

28 effectively manage the risk. As described below, to the extent that 

29 additional mitigations are necessary, asset management plans and work 

30 plans are built out in order to mitigate or reduce the risks. 

31 In addition to the Session D effort, risk is also tracked within Gas 

32 Operations during monthly RCC meetings described above. At these 

33 meetings, AFOs highlight progress made on key risks and the status of 

34 those risks. Furthermore, all Gas Operations risks included in the Risk 

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5-16

1 Register are stored in the Enterprise Compliance Tracking System for 

2 further updates, review and reporting. 

3 b. Session 1 and Risk Informed Budget Allocation 

4 Based on the risks identified and scored during Session D, AFOs 

5 then analyze and develop the proposed scope and pace of mitigation 

6 programs. Each of the mitigation programs is designed to address the 

7 identified threats and risks within the asset families to reduce those 

8 risks. The AFOs submit the list of mitigation programs to the Investment 

9 Planning team for further assessment and prioritization using the 

10 RIBA process. 

11 The RIBA risk scores are then used to develop the 5-year strategic 

12 investment plan for Gas Operations, which is submitted for 

13 consideration at the enterprise level as part of Session 1. Additional 

14 details about RIBA can be found in Chapter 3.

15 c. Session 2 and a Risk-Informed, Executable Work Plan 

16 In Session 2, individual projects are identified within the programs 

17 identified in Session 1 and the RIBA framework is applied to assist in 

18 developing an executable plan and scope of work for the following year. 

19 The investment plan developed in Session 2 includes refinement and 

20 additional details to inform execution plans. After the total portfolio of 

21 proposed projects has been prioritized using a risk score, Investment 

22 Planning applies additional factors such as constraints to the total 

23 portfolio to ensure the work can be accomplished effectively. 

24 Constraints include, for instance, resource constraints such as 

25 availability of trained and qualified personnel, execution constraints such 

26 as the time necessary to obtain required permits, and system 

27 constraints such as the ability to deliver gas to customers while 

28 performing the total portfolio of work. 

29 Investment Planning then works with the AFOs to finalize the 

30 proposed investment plan based on the risks and constraints identified. 

31 This process requires discussion and rationalization among mitigation 

32 programs across asset families. 

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5-17

1 C. Areas of Focus and Improvement

2 Gas Operations is exploring opportunities within its risk management 

3 processes to develop a more structured optimization model that can enhance 

4 prioritization based on risk, resource, budget, and system constraints as part of 

5 the integrated planning process. Gas Operations will also continue to improve 

6 asset data quality including integration of asset health condition assessments for 

7 more informed risk assessments. Additionally, data gathered from root cause 

8 analyses, CAP, quality assurance/quality control, monitoring of compliance 

9 activities, and audit findings will help drive more informed risk processes. 

10 In addition, in 2013, PG&E began working on the Pathfinder Program which 

11 will establish a single database for gas distribution asset information. Pathfinder 

12 will provide a “system of record” for all gas distribution asset data to facilitate risk 

13 assessments required for DIMP and will provide the foundation for a new unified 

14 Geographic Information System (GIS)/SAP model for storing gas distribution 

15 asset data. Additionally, the DIMP team will be using Riskfinder, which is a set 

16 of tools that helps automate the gathering of additional data streams. Another 

17 tool embedded in Riskfinder is the Uptime tool, which performs GIS-based risk 

18 analysis. This data will be used by the DIMP team to drive risk decisions and 

19 identify appropriate mitigations. 

20 The DIMP team will also be expanding their review to regulator stations and 

21 meter sets. Regulator stations can potentially impact the integrity of 

22 downstream assets. This provides additional data that the DIMP Team will use 

23 to identify threats, assign a risk scoring, and develop mitigation work. 

24 By leveraging technology and developing more consistent risk 

25 methodologies for diverse assets, programs will be prioritized based on risk 

26 across the system by making an asset-to-asset comparison rather than 

27 prioritization occurring within individual programs. This change in methodology 

28 will allow PG&E to ensure the highest risk assets, regardless of asset type, are 

29 replaced first, thus maximizing risk reduction. 

30 PG&E plans on additional benchmarking within and outside the industry to 

31 validate and enhance its risk management framework and process. PG&E will 

32 also continue to seek external review from industry experts and academic 

33 research teams to help its risk management process validation and 

34 improvement journey. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 5 

ATTACHMENT A 

GAS OPERATIONS RISK REGISTER 

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of 52
As of April 14, 2015 

Gas Operations Risk Register (1/5)

# Risk Name 

21

DMS39 ‒ Excavation Damage, Third P

Non At-Fault 

22 TRA11 ‒ Incorrect Operations ‒ Over 

23 TRA9 ‒ Stress Corrosion Cracking 

24 Gas Compliance Performance Risk 

25

MC14 ‒ Welding/Fabrication ‒ Overpr

Station

26 MC10 ‒ Incorrect Operation ‒ Termina

27 MC4 ‒ Incorrect Operations ‒ Comple

28 MC6 ‒ Incorrect Operations ‒ Backbo

29 STO17 ‒ External Corrosion ‒ Pipelin

30 MC3 ‒ Incorrect Operations ‒ LoC Sim

31 MC13 ‒ Welding/Fabrication ‒ LoC Si

32 STO20 ‒ Manufacturing ‒ Pipeline 

33 STO12 ‒ Erosion ‒ Meters 

34 STO15 ‒ Erosion ‒ Valves 

35 STO18 ‒ Fatigue ‒ All Segments 

36 DMS42 ‒ Incorrect Operations ‒ Emp

37 TRA16 ‒ Equipment Related ‒ Over-P

38

MC18 ‒ Equipment Related ‒ LoC Co

Simple Station 

39 MC36 ‒ Equipment Related ‒ Termina

40 MC19 ‒ Equipment Related ‒ Backbo

41

DMS8 ‒ Incorrect Operations ‒ Cross 

Area

42 CP1 ‒ External/Internal Corrosion 

43 CP2 ‒ External Corrosion ‒ Under Pip

44 CP10 ‒ Internal Corrosion and Erosio

45 CP18 ‒ Stress Cracking Corrosion 

46 DMS5 ‒ Material or Weld ‒ Plastic (Sy

# Risk Name 

Current 

Residual 

Risk Score 

1 GO ‒ Cybersecurity 811

2

TRA4 ‒ Catastrophic Pipeline Failure ‒ Manufacturing 

Related Defects 

807

3

TRA1 ‒ Catastrophic Pipeline Failure ‒ External 

Corrosion 

807

4

TRA8 ‒ Catastrophic Pipeline Failure ‒ Internal 

Corrosion 

807

5

TRA3 ‒ Catastrophic Pipeline Failure ‒ Welding/ 

Fabrication Related ‒ Pre-1962 Construction with Land 

Movement 

806

6 STO16 ‒ Internal Corrosion and/or Erosion ‒ Pipeline 804

7

DMS45 ‒ Incorrect Operations ‒ Cross Bore in Urban 

Area

617

8 CP19 ‒ Third Party/Mechanical Damage ‒ Vandalism 596

9

CP22 ‒ Weather Related/Outside Forces ‒ Seismic 

(Manned)

596

10

DMS40 ‒ Records Management ‒ Distribution Mains and 

Services

591

11

TRA12 ‒ Catastrophic Pipeline Failure ‒ Weather 

Related and Outside Forces ‒ Land Movement 

579

12 MC32 ‒ Weather Related/Outside Forces ‒ Seismic 573

13

MC15 ‒ Equipment Related ‒ LoC Complex/ 

Simple Station 

573

14 MC1 ‒ Incorrect Operations ‒ LoC LP Distribution 551

15 CP12 ‒ Manufacturing Defects 551

16 CP8 ‒ Welding/Fabrication Related 551

17 STO26 ‒ Weather and Outside Forces ‒ Seismic 551

18 MC16 ‒ Equipment Related ‒ LoC LP Distribution 548

19 CP6 ‒ Incorrect Operations 548

20

GSO1 ‒ Failure to Meet Core Customer Demand for 

Design Standard Abnormal Peak Day (APD) 

537

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As of April 14, 2015 

Gas Operations Risk Register (2/5) 

# Risk Name 

70 CCE11 ‒ Natural Forces (Flood) 

71 LNG15 ‒ Third-Party Damage ‒ NGV 

72

DMS54 ‒ Other Outside Forces ‒ Inac

Equipment

73 CCE33 ‒ Other Outside Force ‒ Inacc

74 STO21 ‒ Construction ‒ Pipeline 

75 STO29 ‒ Third Party Damage ‒ All Se

76

DMS10 ‒ Incorrect Operations ‒ Regu

(Low Pressure) 

77 MC30 ‒ 3rd Party/Mechanical Damag

78 STO23 ‒ Weather and Outside Force 

79

CP21 ‒ Weather Related/Outside For

(Unmanned)

80 MC33 ‒ BTU Heating Value 

81

LNG25 ‒ Equipment ‒ CNG Injection 

Failure (Safety) 

82 MC25 ‒ External Corrosion 

83 DMS52 ‒ Material Traceability 

84

MC30.1 ‒ 3rd Party/Mechanical Dama

Damage

85 DMS38 ‒ Outside Force ‒ Land Move

86 DMS51 ‒ Co-Location of Gas and Ele

87 MC2 ‒ Incorrect Operations ‒ LoC HP 

88 DMS37 ‒ Overbuilds 

89

CP29 ‒ Equipment Related ‒ Hinkley 

Compressor Reciprocating Engine 

90 MC7 ‒ Incorrect Operations ‒ LoS LP 

91 MC21 ‒ Equipment Related ‒ LoS LP 

92

CCE5 ‒ Material or Weld ‒ Inadequat

Regulator Design 

93 STO13 ‒ Incorrect Operations ‒ Valve

# Risk Name 

Current 

Residual 

Risk Score 

47 TRA6 ‒ Third Party/Mechanical Damage 310

48 STO3 ‒ Construction by 1st and 2nd Party ‒ Reservoir 310

49 STO30 ‒ 1st, 2nd, 3rd Party ‒ All Segments 310

50 CP5 ‒ Manufacturing Defects ‒ Pipe Quality 310

51 STO19 ‒ Third Party Damage ‒ Pipeline 310

52

DMS1 ‒ Excavation Damage, Third Party ‒ Rupture 

At-Fault Due to Mismarking by PG&E 

308

53 CP7 ‒ Incorrect Operations ‒ Odorization 308

54 DMS14 ‒ Natural Forces 245

55 CCE29 ‒ Material 237

56 CCE30 ‒ Material Traceability 237

57

DMS53 ‒ Incorrect Operations (Workmanship 

Traceability)

235

58 GSO3 ‒ Risk of Using Manual Operations 235

59 CP13 ‒ Equipment Related ‒ Electrical Systems 235

60

LNG18 ‒ Third-Party Damage ‒ CNG Trailer 

Transportation Incident 

235

61

CCE31 ‒ Other Outside Forces ‒ Building and Meter 

Interaction

235

62 DMS15 ‒ External Corrosion ‒ Unprotected Steel Pipe 234

63

DMS23 ‒ Material and Weld ‒ Steel Installed Through 

the 1950s 

234

64 CCE20 ‒ Equipment ‒ Indoor Meter Sets 234

65

DMS46 ‒ Incorrect Operations ‒ Applicant Installed 

Facilities

234

66 DMS4 ‒ Internal Corrosion 234

67

DMS43 ‒ Outside Force ‒ Land Movement Due to 

Erosion or Subsidence

234

68

CCE7 ‒ Equipment or Other Outside Force ‒ End of Life 

Failure 

234

69 DMS22 ‒ Material and Weld ‒ Composite Risers 234

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As of April 14, 2015 

Gas Operations Risk Register (3/5) 

# Risk Name 

116 STO25 ‒ Equipment ‒ Storage Field 

117 TRA22 ‒ Incorrect Operations 

118

LNG12 ‒ Third-Party Damage ‒ Fue

Away

119

LNG24.1 ‒ Equipment ‒ LNG Vapori

(Reliability)

120 GSO9 ‒ Scheduling Risk 

121 CP15 ‒ Records Management (P50) 

122

TRA20 ‒ Weather Related and Outs

Tree Damage 

123

TRA10 ‒ Weather-Related Outside F

Water Crossings and Exposed Pipe 

124

CP24 ‒ Hinkley Station Non-Retrofitt

Outage Due to Any Cause

125

CP25 ‒ Delevan Station Compresso

Any Cause

126

CP32 ‒ Santa Rosa Station Compres

Any Cause

127 CCE13 ‒ Natural Forces (Seismic) 

128 CCE32 ‒ Other Outside Force ‒ Spa

129 CP9 ‒ Equipment Related ‒ Air Emis

130 STO20.1 ‒ Manufacturing ‒ Pipeline 

131 LNG31 ‒ Insufficient Portable Equipm

132

CCE4 ‒ Other Outside Force ‒ Third 

Construction and Redevelopment 

133 STO27 ‒ Incorrect Operations ‒ Stor

134 TRA25 ‒ Equipment Related ‒ Inope

135

DMS47 ‒ Other Outside Forces ‒ Tre

Plastic Pipe

136 STO16.1 ‒ Internal Corrosion and/or 

137 CCE26 ‒ Equipment Failure ‒ Meter/

# Risk Name 

Current 

Residual 

Risk Score 

94

TRA19 ‒ Mechanical Damage ‒ Electric Substation 

Damage 

144

95 TRA21 ‒ Material Traceability 144

96

MC34 ‒ Records Management ‒ Inadequate Records 

(P50)

143

97

TRA26 ‒ Equipment Related ‒ Component Failure 

(Drips, Fittings) 

138

98 STO5 ‒ Corrosion ‒ Well Casing 114

99 STO31 ‒ Stress Corrosion Cracking ‒ Pipeline 108

100 STO10 ‒ Incorrect Operations ‒ Wells 107

101 STO11 ‒ Erosion ‒ Wells 107

102

TRA14 ‒ Mechanical Damage ‒ First and Second Party 

Damage 

103

103 STO4 ‒ Incorrect Operations ‒ Reservoir 103

104

LNG24.0 ‒ Equipment ‒ LNG Vaporizer Operations 

Failure (Safety)

103

105

LNG17.0 ‒ Third-Party Damage ‒ LNG Tanker Parked 

(Safety) 

102

106

LNG16 ‒ Third-Party Damage ‒ LNG Tanker 

Transportation Incident 

102

107 MC29 ‒ Internal Corrosion 98

108 MC28 ‒ Stress Cracking Corrosion 98

109 STO22 ‒ Weather and Outside Force ‒ LM and PC 98

110

MC12 ‒ Welding/Fabrication ‒ Overpressure Event 

(System Safety)

98

111 MC17 ‒ Equipment Related (System Safety) 98

112 MC9 ‒ Incorrect Operations (System Safety) 98

113 MC22 ‒ Equipment Related ‒ LoS HP Distribution 98

114 TRA23 ‒ Third Party/Mechanical Damage ‒ Vandalism 97

115

LNG26 ‒ Third-Party Damage ‒ ORCA Trlr Transpo 

Incident

97

5-AtchA-3 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 36 of 52
As of April 14, 2015 

Gas Operations Risk Register (4/5) 

# Risk Name 

158

CP26 ‒ Tionesta Station Compressor 

Any Cause (System Safety) 

159

CP27 ‒ Burney Station Compressor O

Cause (System Safety) 

160

CP28 ‒ Gerber Station Compressor O

Cause

161

CP31 ‒ Bethany Station Compressor 

Any Cause

162

CP33 ‒ Topock Station Compressor O

Cause

163 CCE28 ‒ Other Outside Force ‒ Grou

164

LNG22 ‒ Incorrect Operations ‒ CNG 

Bottle Safety 

165 GSO6 ‒ Market Liquidity Risk 

166 GSO8 ‒ Demand Risk 

167

LNG19.1 ‒ Third-Party Damage ‒ CN

Parked (Reliability) 

168 MC24 ‒ Equipment Related ‒ LoS Co

169 MC27 ‒ Equipment Related ‒ Termin

170 MC35 ‒ Equipment Related ‒ Backbo

171 STO30.1 ‒ 1st, 2nd, 3rd Party ‒ All S

172 STO24 ‒ Weather and Outside Forces 

173

DMS2 ‒ Excavation Damage Third P

(P50)

174 CP30 ‒ Incorrect Operations 

175 CP17 ‒ Equipment Related ‒ Deferre

176

DMS41 ‒ Incorrect Operations ‒ Fus

(P50)

177 STO33 ‒ Disposal Well ‒ Gill Ranch 

178

STO34 ‒ Internal/External Corrosion 

Gill Ranch 

# Risk Name 

Current 

Residual 

Risk Score 

138

LNG30 ‒ Incorrect Operations ‒ Station Documentation 

Safety 

32

139

LNG32.0 ‒ Equipment ‒ Station Compressor and 

Component (Safety) 

32

140

LNG19.0 ‒ Third-Party Damage ‒ CNG Tube Trailer 

Parked (Safety) 

32

141 DMS50 ‒ Military Facilities 31

142

LNG27 ‒ Third-Party Damage ‒ ORCA LNG Safety 

Parked 

31

143

LNG32.1 ‒ Eqpmt ‒ Combined Sta Compr and 

Component (Reliability) 

30

144

GSO2 ‒ Failure to meet Non-Core CWD Design 

Standard

30

145 DMS44 ‒ Excavation Damage ‒ Unlocatable Stubs 30

146 LNG28 ‒ LNG Commodity Shortfall 30

147 STO14 ‒ Equipment ‒ Valves 30

148 MC23 ‒ Equipment Related ‒ LoS Simple Station 29

149 MC26 ‒ Manufacturing Related Defects 28

150 STO2 ‒ Construction by 3rd Party ‒ Reservoir 28

151 LNG29 ‒ CNG Commodity Shortfall (Reliability) 28

152 STO31.1 ‒ Stress Corrosion Cracking ‒ Pipeline 28

153

CP4 ‒ Weather Related/Outside Forces ‒ Flooding 

(System Safety)

25

154

CCE2 ‒ Other Outside Force ‒ Third Party Damage ‒ 

Vehicles 

25

155

CCE6 ‒ Material or Weld ‒ Poor Quality Control of 

Regulator/Meter Set Manufacturing 

25

156 LNG30.1 ‒ Incorrect Station Ops 25

157

CP23 ‒ Kettleman Station Compressor Outage Due to 

Any Cause (System Safety) 

24

5-AtchA-4 Case: 19-30088 Doc# 2021-2 Filed: 05/15/19 Entered: 05/15/19 15:59:18 Page 37 of 52
As of April 14, 2015 

Gas Operations Risk Register (5/5) 

# Risk Name 

203 TRA7 ‒ Third Party/Mechanical Dam

204

MC11 ‒ Incorrect Operations ‒ LoS C

Station

205 LNG13 ‒ Third-Party Damage ‒ Disp

206

LNG20 ‒ Third-Party Damage ‒ CNG 

Transpo Incident 

207 DMS17 ‒ Atmospheric Corrosion 

208 CCE3 ‒ Other Outside Force ‒ Vand

209 TRA15 ‒ Internal Corrosion (P50) 

210 DMS6 ‒ Material or Weld ‒ T-Caps 

211 TRA5 ‒ Manufacturing Related Defec

212

LNG21 ‒ Third-Party Damage ‒ CNG 

Collision (Safety)

213 STO35 ‒ Outside Forces (Geologica

214

GSO10 ‒ Risk of Multiple Clearances 

System

215

GSO11 ‒ Inadequate Visibility into th

Flows on the Networks

216 GSO12 ‒ Gas Control Operator Erro

217 GSO13 ‒ SCADA Outage 

218 GSO14 ‒ Physical Security ‒ Gas Co

219

GSO15 ‒ GOC System Failure Effec

Coordination and Response 

220 MC8.1 ‒ Incorrect Operations (Syste

221 MC10.1 ‒ Incorrect Operations (Syst

# Risk Name 

Current 

Residual 

Risk Score 

179 STO17.1 ‒ External Corrosion ‒ Pipeline 17

180

GSO4 ‒ Loss of Supply from Interconnected Pipelines 

and Third Party Storage

14

181 DMS12 ‒ Material or Weld ‒ Mechanical Fittings 14

182

CP23.1 ‒ Kettleman Station Outage Due to Power 

Outage

14

183

LNG17.1 ‒ Third-Party Damage ‒ LNG Tanker Parked 

(Reliability) 

13

184 DMS3 ‒ External Corrosion on Steel Piping 12

185 DMS49 ‒ Material or Weld ‒ Isolation Valve Failure 11

186 GSO5 ‒ Portfolio Management Risk 11

187 STO5.1 ‒ Corrosion ‒ Well Casing 11

188 STO1‒ Third Party Damage ‒ Reservoir 10

189 LNG14 ‒ Third-Party Damage ‒ Fuel Theft 10

190 DMS25 ‒ Material and Weld ‒ Curb Valves 10

191 CCE23 ‒ Natural Forces ‒ Settlement of Soil 10

192

DMS11 ‒ Incorrect Operations ‒ Regulator (Semi-High 

or High Pressure) 

10

193

MC20 ‒ Equipment Related ‒ LoS Complex/Simple 

Station

10

194

CCE16 ‒ Other Outside Force ‒ Inoperable or 

Inaccessible Service Valve 

9 

195 DMS7 ‒ Natural Forces ‒ Cast Iron Material 8 

196 GSO7 ‒ Price Risk 8 

197 DMS48 ‒ Internal Corrosion ‒ Mainline Drips 7 

198 CCE21 ‒ Other Outside Force ‒ Fire 7 

199 CCE1 ‒ Incorrect Operations 7 

200 MC8 ‒ Incorrect Operation ‒ Terminal/Large Complex 6 

201 MC5 ‒ Incorrect Operations ‒ Backbone (PLS) Stations 6 

202 TRA2 ‒ External Corrosion (P50) 6 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 6 

RISK LEXICON 

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6-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 CHAPTER 6 

3 RISK LEXICON 

4 This chapter provides a Risk Lexicon (Attachment A) that was developed in 

5 collaboration with the other utilities participating in this proceeding. The Lexicon 

6 includes terms that are used in risk management activities. Pacific Gas and Electric 

7 Company (PG&E) views this Lexicon as a potentially valuable tool that can assist in 

8 facilitating the discussion of risk and risk management. 

9 PG&E’s opinion is that this Lexicon should be viewed as a living document that 

10 can be added to and modified over time. To this end, PG&E proposes that this 

11 Lexicon, and other terms as well, be made the subject of a workshop in this Safety 

12 Model Assessment Proceeding. PG&E also proposes that the Commission publish 

13 the Lexicon in a manner that provides for easy public access and use, and that it be 

14 updated periodically. 

15 Finally, there are two caveats that PG&E wishes to identify. First, it is not 

16 always possible or practical to agree on only one definition for a term. The same 

17 term is sometimes used somewhat differently in different companies or even within 

18 the same company. Thus, it may be advisable in some circumstances to publish 

19 more than one definition for a term. Second, the Commission should not mandate 

20 the use of a particular definition or consider any penalties for the “misuse” of a term. 

21 Rather these definitions should only be viewed as a tool with educational value that 

22 over time will promote a common language about risk management. 

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PACIFIC GAS AND ELECTRIC COMPANY 

CHAPTER 6 

ATTACHMENT A 

RISK LEXICON 

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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.

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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

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PACIFIC GAS AND ELECTRIC COMPANY 

APPENDIX A 

STATEMENTS OF QUALIFICATIONS 

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EB-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF ERIC BACK 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Eric Back, and my business address is Pacific Gas and Electric 

5 Company, 245 Market Street, San Francisco, California. 

6 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

7 (PG&E). 

8 A 2 I am the director of the Compliance & Risk Management organization within 

9 Electric Operations. 

10 Q 3 Please summarize your educational and professional background. 

11 A 3 I am the director for Risk Management, Compliance, and Vegetation 

12 Management in Electric Operations. I joined PG&E in 2008 and worked in 

13 the Utility Performance Improvement group focusing on electric transmission 

14 and substation facilities and processes. Since then, I have been a 

15 substation maintenance superintendent and a director in Transmission 

16 Operations. Prior to joining PG&E, I worked in management and operations 

17 consulting. I am a registered professional engineer in the state of California. 

18 I have a bachelor of science degree in mechanical engineering from 

19 University of California, Davis, a master of science degree in mechanical 

20 engineering from Colorado State University and a master in business 

21 administration degree from the London Business School. 

22 Q 4 What is the purpose of your testimony? 

23 A 4 I am sponsoring Chapter 4, “Electric Operations and Nuclear Power 

24 Generation,” with the exception of Sections B.2. and C.2., in PG&E’s S-MAP 

25 proceeding. Sections B.2. and C.2. relate to the risk processes and 

26 programs at PG&E’s nuclear facilities and are sponsored by Cary D. Harbor. 

27 Q 5 Does this conclude your statement of qualifications? 

28 A 5 Yes, it does. 

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CCC-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF CHRISTINE C. CHAPMAN 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Christine C. Chapman, and my business address is Pacific Gas 

5 and Electric Company, 6111 Bollinger Canyon Road, San Ramon, 

6 California. 

7 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

8 (PG&E). 

9 A 2 As senior director of Asset Knowledge and Integrity Management, within 

10 Gas Operations, I am responsible for the leadership and oversight of an 

11 organization focused on assessing the integrity of the transmission, 

12 distribution, and facilities assets utilizing traceable, verifiable, and complete 

13 asset knowledge and technological tools. I am also responsible for the 

14 development of a strategic integrity management plan for the entirety of 

15 these assets. In addition, I oversee Gas Operations’ Research and 

16 Development Program. 

17 Q 3 Please summarize your educational and professional background. 

18 A 3 I received a bachelor of science degree in mechanical engineering from 

19 University of California, Berkeley and a master’s degree in business 

20 administration from UC Berkeley, Haas School of Business. I am also a 

21 registered professional mechanical engineer in the state of California. 

22 I started with PG&E in 2001 as a summer intern in the gas distribution 

23 organization and after graduating from UC Berkeley began a full-time 

24 position as a gas engineer. Since then, I have held a variety of positions 

25 with increasing levels of responsibility in the Gas Engineering and 

26 Operations organization, mainly focused on gas distribution functions. 

27 In 2008, I transitioned to PG&E’s Human Resources Department where 

28 I held various leadership roles. I returned to Gas Operations in 

29 January 2012 as the director of Distribution Integrity Management. In 

30 November 2013, I transitioned to the director of Transmission Integrity 

31 Management, and in May 2014, I was promoted to the senior director of 

32 Asset Knowledge and Integrity Management. 

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CCC-2 

1 Q 4 What is the purpose of your testimony? 

2 A 4 I am sponsoring Chapter 5, “Gas Operations,” in PG&E’s S-MAP 

3 proceeding. 

4 Q 5 Does this conclude your statement of qualifications? 

5 A 5 Yes, it does. 

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CDH-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF CARY D. HARBOR 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Cary D. Harbor, and my business address is Pacific Gas and 

5 Electric Company, Diablo Canyon Power Plant. 

6 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

7 (PG&E). 

8 A 2 I am the director of Compliance, Alliance and Risk for the Diablo Canyon 

9 Power Plant; in this capacity I am responsible for company compliance and 

10 risk program oversight, matrixed organizations including business finance 

11 and supply chain, and the PG&E management council representative to the 

12 STARS LLC. 

13 Q 3 Please summarize your educational and professional background. 

14 A 3 I received a bachelor of science degree in nuclear engineering from 

15 University of California, Santa Barbara, California, in 1989. I joined PG&E in 

16 1989 as a power production engineer in the Engineering Department. 

17 I have since held positions as the supervisor of Regulatory Services, 

18 operations shift foreman/manager (senior reactor operator licensed by the 

19 Nuclear Regulatory Commission), performance improvement manager, 

20 quality verification director, and the Maintenance and Construction Services 

21 director. Most recently I became the director of Compliance, Alliance and 

22 Risk in 2012. 

23 Q 4 What is the purpose of your testimony? 

24 A 4 I am sponsoring Sections B.2. and C.2. of Chapter 4, “Electric Operations 

25 and Nuclear Power Generation,” in PG&E’s S-MAP proceeding. 

26 Q 5 Does this conclude your statement of qualifications? 

27 A 5 Yes, it does. 

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JM-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF JANAIZE MARKLAND 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Janaize Markland, and my business address is Pacific Gas and 

5 Electric Company, 111 Stony Circle, Santa Rosa, California. 

6 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

7 (PG&E). 

8 A 2 I am the director of PG&E’s Enterprise and Operational Risk and Insurance 

9 Department. My department is responsible for overseeing PG&E’s 

10 Enterprise and Operational Risk Management (EORM) Program and for 

11 procuring insurance to transfer PG&E’s residual financial risks that could 

12 result from catastrophic property or casualty losses. 

13 Q 3 Please summarize your educational and professional background. 

14 A 3 I earned a bachelor of science degree in chemistry from the University of 

15 British Columbia and a master of science degree in Environmental 

16 Management from Royal Roads University in Victoria, British Columbia. 

17 I am a member of the Enterprise Risk Management Utilities Roundtable 

18 and serve as chair of the Edison Electric Institute Enterprise Risk 

19 Management Task Force Steering Committee. 

20 Prior to my career in the EORM and Insurance Department, I held a 

21 variety of roles at PG&E, including manager of Compliance and Ethics and 

22 positions in the Safety and Shared Services organization, where I provided 

23 direct environmental compliance support to PG&E’s operating units. Before 

24 joining PG&E, I worked at BC TEL, a telephone utility based in Burnaby, 

25 British Columbia, and its successor company, Alberta-based TELUS 

26 Corporation, where I developed an environmental program governing the 

27 newly merged companies. 

28 Q 4 What is the purpose of your testimony? 

29 A 4 I am sponsoring the following testimony in PG&E’s S-MAP proceeding: 

30  Chapter 2, “Companywide Models and Approaches for Assessing Risk.” 

31  Chapter 6, “Risk Lexicon.” 

32 Q 5 Does this conclude your statement of qualifications? 

33 A 5 Yes, it does. 

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JLM-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF JAMIE L. MARTIN 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Jamie L. Martin, and my business address is Pacific Gas and 

5 Electric Company, 77 Beale Street, San Francisco, California. 

6 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

7 (PG&E). 

8 A 2 I currently hold the position of director of Economic and Project Analysis. In 

9 this capacity, I supervise: 

10  Financial analysis and economic evaluations concerning a range of 

11 investment matters. 

12  The Risk Informed Budget Allocation process as part of the Company’s 

13 Integrated Planning Process. 

14  Business case guidance and reviews of major capital project proposals. 

15 I report to the Vice President, Finance, of PG&E. 

16 Q 3 Please summarize your educational and professional background. 

17 A 3 I graduated from the University of San Francisco, in 2004, with a bachelor of 

18 science degree in finance. I joined PG&E in 2007 as a senior business 

19 analyst in the Finance organization, specifically in Project Finance. I have 

20 since held a succession of positions in the finance organization. In 2009, 

21 I was promoted to supervisor in the Gas & Electric Transmission and 

22 Distribution Business Finance organization, responsible for operational 

23 financial planning, budgeting and forecasting. In 2010, I was promoted to 

24 manager in the Power Generation Business Finance organization, where 

25 I was responsible for managing a team that supported operational financial 

26 planning, budgeting and forecasting. In 2012, I completed a 6-month 

27 rotation as manager of Investor Relations, where I was responsible for 

28 communication with the investment community and prepared senior 

29 leadership for quarterly earnings calls and expectations for future 

30 performance. In late 2012, I became manager of the Financial Forecasting 

31 & Reporting team, where I was responsible for enterprise-level earnings 

32 forecasts, year-over-year and long-term budgets and forecasts, functional 

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JLM-2 

1 area income statement analysis and board of director financial materials. 

2 I assumed my current position in March 2014. 

3 Q 4 What is the purpose of your testimony? 

4 A 4 I am sponsoring Chapter 3, “Companywide Models and Approaches to Risk 

5 Informed Budget Allocation,” in PG&E’s S-MAP proceeding. 

6 Q 5 Does this conclude your statement of qualifications? 

7 A 5 Yes, it does. 

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SJS-1 

1 PACIFIC GAS AND ELECTRIC COMPANY 

2 STATEMENT OF QUALIFICATIONS OF SHELLY J. SHARP 

3 Q 1 Please state your name and business address. 

4 A 1 My name is Shelly J. Sharp, and my business address is Pacific Gas and 

5 Electric Company, 77 Beale, San Francisco, California.

6 Q 2 Briefly describe your responsibilities at Pacific Gas and Electric Company 

7 (PG&E). 

8 A 2 I am currently the senior director, General Rate Case and Regulatory 

9 Support. My responsibilities include overseeing the development of General 

10 Rate Cases (GRC) as well as various other applications before the 

11 California Public Utilities Commission, ensuring compliance with items from 

12 prior GRCs, and directing the efforts of PG&E’s regulatory support functions. 

13 Q 3 Please summarize your educational and professional background. 

14 A 3 I graduated with a bachelor of science degree in business administration/ 

15 finance from California State University, Sacramento, in 1984. In 1985, 

16 I graduated from Golden Gate University in San Francisco, with a master’s 

17 degree in business administration/finance.

18 I joined PG&E in 1985. From 1985 until 1997, I held various analyst and 

19 supervisory positions within the regulatory area including: regulatory affairs 

20 analyst, rates analyst, resource analyst, supervisor – Gas Rates, and 

21 manager – Electric Rates. In 1997, I took over as the director of the Rates 

22 Department, responsible for both gas and electric revenue allocation and 

23 rate design. In 2003, I became the director of Billing, Revenue and 

24 Records. In 2007, I became the senior director of Service and Sales in the 

25 Customer Care organization. In February 2008, I became the senior 

26 director of Customer Field Service within the Customer Care organization. 

27 Q 4 What is the purpose of your testimony? 

28 A 4 I am sponsoring Chapter 1, “Overview and Summary,” in PG&E’s S-MAP 

29 proceeding. 

30 Q 5 Does this conclude your statement of qualifications? 

31 A 5 Yes, it does. 

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