Distribution Infrastructure Replacement...1 1 I. 2 INTRODUCTION 3 A. Content and Organization of Volume 4 The Distribution Grid volume describes the activities SCE performs to inspect

Application No.: A.19-08- Exhibit No.: SCE-02, Vol. 1, Part 1 Witnesses: G. Bloom R. Tucker

(U 338-E)

2021 General Rate Case

Distribution Infrastructure Replacement

Before the

Public Utilities Commission of the State of California

Rosemead, California August 30, 2019

SCE-02, Vol. 1, Part 1: Distribution Infrastructure Replacement

Table Of Contents

Section Page Witness

-i-

I. INTRODUCTION .............................................................................................1 R. Tucker

A. Content and Organization of Volume ....................................................1

B. Summary of O&M and Capital Request ................................................1

II. INFRASTRUCTURE REPLACEMENT ..........................................................4

A. Overview ................................................................................................4

1. The Need for Distribution Infrastructure Replacement ...............................................................................5

a) Impacts of Aging Infrastructure on Replacement Rates .........................................................5

b) Strategies to Address SCE’s Aging Infrastructure ..................................................................7

c) Failure Models and Predictive Analytics .......................8

2. Risk Factors, Safety, Reliability and Connection with RAMP ..............................................................................11

a) SED / Intervenor Comments ........................................12

3. Regulatory Background/Policies Driving SCE’s Request .....................................................................................13

4. Compliance Requirements .......................................................13

a) 2012 Decision ..............................................................13

b) 2018 Decision ..............................................................13

5. Impact of Wildfire Risk Mitigation Activities on Distribution IR Forecast ...........................................................14

B. 2018 Decision ......................................................................................14

1. Comparison of Authorized 2018 to Recorded .........................14

C. Capital Expenditures – Infrastructure Replacement ............................16

1. Underground (UG) Programs ..................................................16


Table Of Contents (Continued)


-ii-

a) Worst Circuit Rehabilitation Program .........................17

(1) Capital Forecast ...............................................17

(2) Program Description and Need ........................18

(3) RAMP Integration ............................................23

(4) Basis for Capital Expenditure Forecast ............................................................25

(5) Additional Compliance Requirement Discussion ........................................................29

b) Cable Life Extension Program .....................................33





(5) Activities During CLE Program Pause (2020-2023) ...........................................40

c) Cable-in-Conduit Replacement Program .....................41





d) Underground Switch Replacement Program ...............46







-iii-


e) Underground Structure Replacement Program ........................................................................53





2. Overhead Programs ..................................................................64

a) Overhead Conductor Program .....................................64





3. Overhead and Underground Programs .....................................73

a) Capacitor Bank Replacement Program ........................73




b) Distribution Automatic Recloser Replacement Program ..................................................78






-iv-


c) 4 kV Cutover Program and 4 kV Substation Elimination Program ....................................................81




d) PCB Transformer Removal Program ...........................89




III. T&D OPERATIONAL RISK MANAGEMENT PRACTICES......................95 G. Bloom

A. Introduction ..........................................................................................95

B. Process and Governance ......................................................................95

C. Connection to RAMP ...........................................................................95

D. Applications .........................................................................................96

E. Methodology Overview .......................................................................97

F. Progress to Date ...................................................................................99

G. Conclusion .........................................................................................100

1

I. 1

INTRODUCTION 2

A. Content and Organization of Volume 3

The Distribution Grid volume describes the activities SCE performs to inspect and maintain its 4

distribution system. It is broken into three parts organized by Business Planning Element (BPE): 5

Part 1: Distribution Infrastructure Replacement 6

Part 2: Distribution Inspections & Maintenance and Capital Related Expense & Other 7

Part 3: Meter Activities 8

Each part in this volume includes analyses of: (1) O&M and capital funding authorized in the 9

2018 General Rate Case (GRC) compared to recorded amounts in 2018; and (2) the 2021 Test Year 10

forecast relative to historical spending and all new requirements identified in the 2018 GRC decision 11

impacting the 2021 GRC request. 12

Part 1 also contains an overview of T&D’s risk assessment framework also known as Prioritized 13

Risk-Informed Strategic Management (PRISM). 14

B. Summary of O&M and Capital Request 15

As shown below in Figure I-1 and Figure I-2, SCE is forecasting $199 million of O&M 16

expenses1 in 2021 and $3,574 million in capital expenditures for 2019-2023 for Distribution Grid which 17

is part of the overall Exhibit SCE-2 Grid Activities. SCE needs this funding to perform necessary 18

inspections, maintenance, repairs, and replacements on its Distribution Grid that will allow SCE to 19

continue providing safe, reliable, affordable and clean power to customers. 20

1 Part 2 (Distribution Inspections & Maintenance and Capital Related Expense & Other) and Part 3 (Meters)

include O&M expenses; Part 1 (Distribution Infrastructure Replacement) has only Capital expenditures.

2

Figure I-1 Distribution Grid O&M Expenses

(Total Company Constant 2018 $Million)

3

Figure I-2 Distribution Grid Capital Expenditures 2019-2023

(Total Company Nominal $Million)

4

II. 1

INFRASTRUCTURE REPLACEMENT 2

SCE’s distribution grid includes infrastructure such as transformers, switches, capacitors, 3

automatic reclosers, underground structures, cables, and conductors. SCE’s inspection and maintenance 4

of the distribution grid allows components to remain in service for decades, but in the long run, every 5

component in the distribution grid will wear out and need to be replaced. The ongoing systematic 6

replacement of infrastructure is a necessary aspect of maintaining a reliable electric distribution system. 7

Infrastructure component replacements are typically: (1) unplanned for in-service failures; (2) 8

planned based on inspections; or (3) planned based on engineering and data analysis. The costs 9

associated with the first two categories are recorded as Distribution Preventive and Breakdown Capital 10

Maintenance activities within the Inspections & Maintenance BPE.2 The costs associated with the third 11

category are recorded as various activities within the Infrastructure Replacement (IR) BPE and 12

discussed in this chapter. 13

A. Overview 14

The Distribution IR capital activities requested in this chapter are shown in Table II-1. 15

2 See SCE-02, Vol. 1, Part 2.

5

Table II-1 Distribution Infrastructure Replacement Capital Activities

Recorded (2014 -2018) / Forecast (2019-2023) (Nominal $000)

1. The Need for Distribution Infrastructure Replacement 1

a) Impacts of Aging Infrastructure on Replacement Rates 2

Every electrical component in the distribution system will eventually wear out 3

and need to be replaced. In general, the likelihood that a component will fail depends on multiple 4

factors, including its age and the environmental and operational conditions that it encounters. If 5

environmental and operational conditions are held constant, the expected replacement rate of 6

components within a large population is described by a time-dependent replacement rate curve, as 7

shown conceptually in Figure II-3. 8

TOTAL CONSTANT AMOUNT2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

4 kV Cutovers $53,403 $79,916 $107,452 $107,349 $116,586 $48,326 $29,981 $9,982 $9,985 $10,0444 kV Substation Eliminations $1,731 $1,756 $2,643 $3,893 $5,521 $6,054 $5,643 $3,288 $2,071 $2,131Automatic Reclosers Replacement Program $1,523 $2,488 $2,136 $2,393 $1,248 $2,435 $2,448 $2,610 $2,686 $2,763Cable Life Extension (CLE) Program $13,244 $11,665 $22,858 $32,033 $31,258 $20,574 $0 $0 $0 $0Cable-in-Conduit (CIC) Replacement Program $23,042 $54,084 $33,468 $42,363 $50,723 $17,074 $13,866 $5,989 $6,162 $5,987Capacitor Bank Replacement Program $7,814 $8,684 $7,765 $6,920 $19,386 $10,318 $5,302 $2,716 $3,793 $4,641Overhead Conductor Program (OCP) $60,654 $97,330 $138,714 $181,503 $100,063 $34,992 $70,939 $83,134 $92,891PCB Transformer Removal $1,368 $1,325 $1,579 $1,479 $2,533 $1,813 $1,883 $1,943 $1,999 $2,057Underground Structure Replacements $130,644 $101,861 $76,014 $52,231 $56,730 $27,573 $21,771 $13,562 $13,867 $14,214Underground Switch Replacements $19,580 $25,890 $17,566 $19,129 $9,714 $3,389 $3,520 $2,642 $3,284 $3,495Worst Circuit Rehabilitation (WCR) $153,013 $117,673 $143,162 $135,286 $118,299 $67,291 $32,566 $6,960 $7,161 $7,734Totals $405,362 $465,995 $511,972 $541,789 $593,503 $304,910 $151,973 $120,630 $134,143 $145,958

Recorded Forecast

6

Figure II-3 Time-Dependent Replacement Rate Curve

For an individual component, the probability of failure will remain low for a long 1

period given constant operational and environmental conditions. Eventually, the component’s materials 2

weaken and its probability of failure increases. For a large population of components, the number of 3

components reaching the end of their service lives (i.e., are likely to fail) will be low when the average 4

age of the population is young. As the average age of the population increases, the amount and rate of 5

components wearing out and needing replacement will likely increase. 6

In a fixed population, the number of components failing each year will not 7

increase indefinitely. This is because the average age of a fixed population does not increase 8

indefinitely, as older components fail and are replaced by new components. At steady state, the average 9

age of a fixed population will plateau and the replacement rate will reach the “long-term steady-state 10

replacement rate” as shown in Figure II-3. While precise calculation of when the steady state 11

replacement rate will be achieved is complicated, the simple message of this curve should not be lost. 12

The need for ongoing replacement of aging assets is an unavoidable part of asset ownership and 13

operation. 14

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"long-term steady-state replacement rate"

7

b) Strategies to Address SCE’s Aging Infrastructure 1

SCE’s strategy for replacing aging components varies with component type and, 2

in general, depends on two fundamental risk factors: (1) the known or anticipated probability of in-3

service failure; and (2) the known or anticipated consequences of in-service failure. 4

For components where in-service failures have minimal consequences, a run-to-5

failure strategy is the preferred approach. For example, in-service failures of distribution capacitor banks 6

typically pose no significant safety risks, rarely result in customer interruptions, and usually pose little 7

threat to system reliability if replaced in a timely manner after they fail. Therefore, SCE’s Capacitor 8

Bank Replacement program targets failed capacitor banks identified through either scheduled 9

inspections as part of SCE’s Distribution Inspections & Maintenance program3 or ad-hoc inspections 10

from patrol or nearby work. 11

For components where in-service failures have more serious consequences, a 12

proactive replacement strategy is the preferred approach. For example, in-service failures of distribution 13

cable can result in long outages for customers and explosions in underground vaults and manholes. Such 14

risks are discussed in SCE’s November 2018 RAMP Report. To combat cable failures, SCE proactively 15

replaces mainline cable4 through the Worst Circuit Rehabilitation program and radial cable5 through the 16

Cable-In-Conduit Replacement program. The Worst Circuit Rehabilitation program seeks to improve the 17

reliability performance of SCE’s worst performing circuits and uses advanced cable failure models and 18

risk analysis to target those cables for replacement. The Cable-In-Conduit program addresses the 19

problems associated with radial cable and uses information obtained through the associated Cable Life 20

Extension program to target those cables for replacement. 21

Consequences become particularly important when probability of failure cannot 22

be completely determined by inspections alone. In many cases, inspections cannot determine the 23

probability of failure of internal components and can also miss rapid-onset conditions where component 24

deterioration occurs between inspection cycles. Subsurface oil-filled switches are an example of assets 25

that have a probability of failure that cannot be completely determined by inspections alone, and they 26

have safety and reliability consequences when in-service failures occur. SCE proactively replaces 27

3 See SCE-02, V.01 Pt. 2.

4 See Figure II-10 for an illustration of mainline cable on a typical underground distribution circuit.

5 See Figure II-15 for an illustration of radial cable on a typical underground distribution circuit.

8

subsurface oil-filled switches through the Underground Switch Replacement program, which uses 1

advanced switch failure models and risk analysis to target underground switches for replacement. 2

c) Failure Models and Predictive Analytics 3

One area where SCE’s approach to Distribution IR has evolved from previous 4

GRC cycles is in the development of improved asset-failure models. The models are used to forecast 5

failure rates for an asset population as well as the failure probability for individual assets within that 6

population. 7

For failure rates for an asset population, SCE previously used asset failure models 8

based on statistical analysis of historical failures by asset age. These models, known as “Weibull 9

curves,” show the expected failure rate as a function of age for a population of assets. From such 10

models, a population mean-time-to-failure (MTTF) can be derived. As an example, Weibull curves for 11

three different types of SCE’s primary distribution cable – Paper Insulated Lead Cable (PILC), Cross-12

Linked Polyethylene (XLPE), and Tree Retardant Cross-Linked Polyethylene (TR-XLPE) – are shown 13

in Figure II-4. From these curves, population MTTFs of 51 years (PILC), 41 years (XLPE), and 46 years 14

(TR-XLPE) have previously been derived.6 15

6 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 3-13 – Weibull Model for Distribution Cable.

9

Figure II-4 Weibull Curves for Distribution Cable

The use of Weibull curves is common throughout the utility industry and over the 1

years such models have played an important role in SCE’s Distribution IR strategies. However, SCE has 2

recognized two important aspects where Weibull analysis can be improved. 3

First, Weibull curves alone do not provide sufficient granularity to identify which 4

specific assets are expected to fail before or after the MTTF of the total population. This is because 5

classic Weibull curve modeling approaches do not incorporate location-specific data in the model 6

development process. The resulting Weibull curves, although useful for population-level strategy 7

development, are less useful for analyzing individual assets within a large population. 8

Second, Weibull curves cannot be developed when age data is not available. For 9

example, SCE does not have data regarding the physical age of overhead conductor installed within its 10

distribution system. Even though SCE has been tracking overhead conductor failures on the system, the 11

lack of corresponding age data means that Weibull curves for overhead conductors cannot be developed. 12

Since the 2018 GRC, SCE has been working to address these inherent limitations 13

through improved failure models. SCE refers to these models as predictive analytics models. In general, 14

predictive analytics models apply both to asset populations and to specific assets within those 15

populations. These models use multiple data sets (electrical, non-electrical, historical performance, 16

weather, environmental, and geographic) and employ machine learning algorithms that recognize 17

patterns in those data sets to predict component failures. 18

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XLPE

PILC

TR-XLPE

10

The result of a predictive analytics model is a calculated the probability of failure 1

for each individual asset within a larger asset population, based on multiple asset attributes. For 2

example, Figure II-5 shows the calculated probabilities of failure of identically aged cables – 3

specifically 40 years old – within the SCE system. 4

Figure II-5 Illustrative Example – Probabilities of Failure (40 Year Old Cables)

These results resemble a classic skewed probability distribution, with a low mean 5

as well as a long tail. Such results comport with SCE’s experience and illustrate the capabilities of the 6

predictive analytics models – they help SCE distinguish between aged cables near the mean (i.e., large 7

quantities of cable with lower probabilities of failure) and cables in the tail (i.e., smaller quantities of 8

cable but with much higher probabilities of failure). 9

The predictive analytics models are generally consistent with previous Weibull-10

based models. For example, one way to view predictive analytics model results is to view the results as a 11

function of asset age alone. An example of this view – again for distribution cable – is shown in Figure 12

II-6. Note that the predictive analytics model results for cable shown in Figure II-6 are qualitatively 13

similar to the Weibull curves for cable shown in Figure II-4. Specifically, both models show an expected 14

increase in cable failures for older cable segments. 15

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Figure II-6 Mean Probability of Failure as a Function of Age – Distribution Cable

Unlike the Weibull curves, the predictive analytics model calculates probabilities 1

of failure at the individual asset level rather than the aggregate population level. In conclusion, these 2

modeling refinements show how SCE is continuing to take meaningful steps towards more granular and 3

asset-specific risk-informed replacement decisions for Distribution IR activities.7 4

To date, SCE has developed predictive analytics models for primary distribution 5

cable, distribution switches, and distribution overhead conductors, and SCE is using the models for 6

Distribution IR activities in these three areas. Going forward, SCE intends to continue refining existing 7

predictive analytics models, developing new predictive analytics models, and seeking new and improved 8

ways to integrate the results of these models in Distribution IR activities.8 9

2. Risk Factors, Safety, Reliability and Connection with RAMP 10

The Distribution IR activities in Table II-2 address three of the top nine safety risks for 11

SCE, as addressed in SCE’s 2018 RAMP report: (1) Contact with Energized Equipment; (2) Wildfire; 12

7 Such models also address the compliance requirement from the 2018 GRC final decision (D.19-05-020),

where SCE was directed to change the “minimum age” used to select mainline cable replacement in the WCR program. For further discussion, see II.C.1.a).

8 For further information, refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 14-34 – Predictive Modeling of SCE’s Distribution Equipment.

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All Cable Types

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and (3) Underground Equipment Failure. Table II-2 summarizes the GRC activities that were included 1

in SCE’s 2018 RAMP report. More detailed descriptions of the Distribution IR activities related to these 2

three RAMP risks can be found in the respective sections for each activity below. 3

Table II-2 Distribution IR Activities Included in SCE’s 2018 RAMP Filing

There are additional Distribution IR activities included in this chapter that were not 4

included in SCE’s RAMP report. These activities also address various risks, but those risks are not 5

among the top nine safety risks for SCE. For example, the Capacitor Bank Replacement program 6

addresses reliability risks, the Distribution Automatic Recloser Replacement program addresses safety 7

and reliability risks, the non-CPRR portion of the Underground Structure Replacement program 8

addresses safety and reliability risks, and the Polychlorinated biphenyls (PCB) Transformer Removal 9

program addresses environmental risks. 10

a) SED / Intervenor Comments 11

In its comments on SCE’s RAMP report,9 Safety and Enforcement Division 12

(SED) recommends that SCE include in this GRC a discussion or proposal for system monitoring that 13

would enable the utility to identify equipment that is most likely to fail and to address problem areas 14

before they escalate into a situation similar to what transpired in 2015 in the city of Long Beach. SCE’s 15

9 See SED’s “A Regulatory Review of the Southern California Edison’s Risk Assessment Mitigation Phase

Report for the Test Case 2021 General Rate Case,” dated May 24, 2019, I18-11-006, p. 50.

GRC Activity RAMP Control / Mitigation Name RAMP ID Risk AddressedOverhead Conductor Program (OCP) C1

Overhead Conductor Program (OCP) Utiliizing Targeted Covered Conductor C1a

Overhead Conductor Program (OCP, Bare + Covered) C1

Overhead Conductor Program (OCP, Bare Only) C1a

Worst Circuit Rehabilitation (WCR) Cable Replacement Programs (WCR) C1Cable Life Extension (CLE) Program

Cable-in-Conduit (CIC) Replacement ProgramUnderground Switch Replacements UG Oil Switch Replacement Program C3

Underground Structure ReplacementsCover Pressure Relief and Restraint

(CPRR) Program M1

Contact with Energized Equipment

Underground Equipment Failure

Cable Replacement Programs (CIC) C2

Wildfire

Overhead Conductor Program (OCP)

13

development of predictive analytics models is a significant step forward towards better identification of 1

specific equipment that is most likely to fail and escalate to a larger problem. See Section II.A.1.c) for 2

further details. 3

3. Regulatory Background/Policies Driving SCE’s Request 4

The Commission has established reliability reporting requirements in D.16-01-008, 5

which closed R.14-12-014 (Order Instituting Rulemaking Regarding Policies, Procedures and Rules for 6

Reliability Reporting Pursuant to Public Utilities Code Section 2774.1). As part of these reporting 7

requirements, the Commission has directed SCE to file with the Commission its plans to improve the 8

reliability performance of repeat Worst Performing Circuits (WPCs) as part of its annual reliability 9

report. This regulatory requirement adds a driver for SCE’s Worst Circuit Rehabilitation (WCR) 10

program, which is the program that SCE uses to identify and address the WPCs within its service 11

territory. See section II.C.1.a) for further details. 12

4. Compliance Requirements 13

a) 2012 Decision 14

The Commission’s 2012 GRC Decision, D.12-11-051, required that SCE 15

document the data collection from the Cable-in-Conduit (CIC) pilot program and other efforts to 16

develop a best practice and most cost-effective method for replacements. Such information shall be 17

submitted to support future GRC requests in this category to assist the Commission and to illustrate that 18

customers achieved value from SCE’s “lessons learned.” 19

SCE has documented data and lessons learned from CIC testing in both its 2015 20

GRC Application and 2018 GRC Application. More recently, SCE has used data gathered during its 21

Cable Life Extension (CLE) program as an input to its predictive analytics model for cable failures. 22

Additional discussion of other SCE efforts to develop a best practice for CIC replacements is found in 23

section II.C.1.b)(5). 24

b) 2018 Decision 25

In D.19-05-020 (2018 GRC), the Commission gave three directions to SCE 26

regarding the Worst Circuit Rehabilitation Program. First, the Commission directed SCE to begin 27

recording cable failures by cable type. This requirement is addressed in Section II.C.1.a)(5). Second, the 28

Commission directed SCE to change the minimum age used to select mainline cable replacement. This 29

requirement is addressed in Section II.A.1.c). Third, the Commission directed SCE to perform a cost-30

benefit analysis regarding cable injections on mainline cable. In the event the cost-benefit analysis 31

14

determines that a pilot is necessary, the Commission directed SCE to report on the quantitative and 1

qualitative findings from the pilot in the next GRC. These requirements are addressed in Section 2

II.C.1.a)(5)(c). 3

5. Impact of Wildfire Risk Mitigation Activities on Distribution IR Forecast 4

In SCE-01, Volume 1, Mr. Payne describes how there are not enough available resources 5

to cost-effectively implement the scope of both Grid Hardening and Distribution IR at the levels that 6

SCE would otherwise propose. In Table II-3, SCE compares the present GRC request for Distribution IR 7

to the estimated amount that SCE would have otherwise requested in this GRC, if not for wildfire risk 8

mitigation efforts. Further details regarding individual Distribution IR activities are included within the 9

testimony for each of those activities. 10

Table II-3 Distribution IR GRC Request and Unconstrained Need10

2019 – 2023 Capital (Nominal $ Millions)

The reductions shown in Table II-3 should be considered temporary in nature. These 11

near-term deferments in Distribution IR activities do not mean that the fundamental problems associated 12

with SCE’s aging infrastructure have changed. These deferments may cause an increase in the average 13

age of SCE’s distribution infrastructure and in-service failure rates. Going forward, as wildfire-14

prevention-related work nears completion and more resources become available, SCE expects to 15

increase Distribution IR activities to compensate for the longer-term effects of these near-term 16

deferments. 17

B. 2018 Decision 18

1. Comparison of Authorized 2018 to Recorded 19

This section compares the amounts authorized by the Commission in the 2018 GRC to 20

2018 recorded capital expenditures for the Distribution IR program. 21

10 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 35-36 – Program Reduction Summary.

SCE GRC Request (2019-2023) SCE Unconstrained Need (2019-2023)$858 $2,282

15

Figure II-7 Distribution IR Program 2018 Authorized vs. Recorded11

(Nominal $ Millions)

Typically, the annual recorded cost for the 4 kV Cutovers program will vary due to the 1

specific scope of work completed in any given year. In 2018, the specific scope of work completed in 2

the 4 kV Cutovers program generally aligned to levels experienced in 2016 and 2017, although it 3

resulted in higher than authorized recorded costs. 4

In 2018, without a 2018 GRC decision, SCE managed the OCP at approximately the SCE 5

request level. SCE recorded additional costs in incremental planning (such as scoping, engineering 6

assessments, and design) for OCP scope for future years. SCE also completed approximately 10% more 7

circuit miles under OCP than originally forecasted. These two items are the primary drivers for OCP 8

recorded costs to be higher than the SCE request level. The remainder of the variance is due to a lower 9

authorized amount than requested. 10

In 2018, SCE performed fewer underground structure replacements and vault shoring 11

projects relative to the 2018 request, contributing to a reduced level of spending against authorized 12

levels. The replacements that SCE performed in 2018 were prioritized based on risk reduction. 13

11 Refer to WP SCE-07, Vol. 01 – Authorized to Recorded: (The Other category includes the following

activities: 4 kV Substation Eliminations, Automatic Recloser Replacement, Cable-in-Conduit Replacement, Capacitor Bank Replacement, PCB Transformer Removal, and Underground Switch Removal).

$26.8 $7.1

$83.4 $14.3

0

100

200

300

400

500

600

700

2018 Request 2018Authorized

4 kV Cutovers Cable LifeExtension

(CLE)Program

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UndergroundStructure

Replacements

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(WCR)

Other 2018Recorded

Other

Worst CircuitRehabilitation (WCR)

Underground StructureReplacements

Overhead ConductorProgram (OCP)

Cable Life Extension(CLE) Program

4 kV Cutovers

($17) ($9)

$617.9

$487.4

$593.5

16

C. Capital Expenditures – Infrastructure Replacement 1

There are ten different activities that make up the Distribution IR program, and each activity falls 2

into one of three categories. 3

The first category of activities focuses primarily on underground infrastructure. Five activities fit 4

into this category: (1) Worst Circuit Rehabilitation program (WCR);12 (2) Cable-In-Conduit (CIC) 5

Replacement program; (3) Underground Switch Replacement program; (4) Underground Structure 6

Replacement program; and (5) Cable Life Extension program (CLE). These activities are discussed in 7

Section II.C.1. 8

The second category of activities focuses on overhead infrastructure. One activity fits into this 9

category: the Overhead Conductor Program (OCP). This activity is discussed in Section II.C.2. 10

The third category of activities focuses on infrastructure that exists in both overhead and 11

underground configurations. Four activities fit into this category: (1) Capacitor Bank Replacement 12

program; (2) Distribution Automatic Recloser Replacement program; (3) 4 kV Cutover and Substation 13

Elimination programs; and (4) PCB-contaminated Transformer Removal program. These activities are 14

discussed in Section II.C.3. 15

1. Underground (UG) Programs 16

SCE’s underground distribution system is comprised of cable and cable components, 17

typically installed within systems of underground ducts between structures such as vaults or manholes. 18

The underground system also contains a variety of electrical components such as underground switches 19

and underground transformers, which are typically installed within underground structures. A simplified 20

representation of SCE’s underground distribution system, highlighting various types of equipment 21

replaced through Distribution IR activities, is provided in Figure II-8. 22

12 While the WCR program focuses on underground infrastructure, individual WCR projects may include

overhead scope elements on a case-by-case basis. For additional details, see II.C.1.a).

17

Figure II-8 SCE’s Underground Distribution System

SCE’s underground electrical components and the structures that contain them can 1

degrade or deteriorate from age, wear, and environmental factors. As underground components and 2

structures degrade over time, the probability of in-service failures increases. Underground systems are 3

inherently more difficult to inspect than overhead systems, and operational practices such as switching 4

and fault locating are generally more difficult and time-consuming on underground systems. 5

a) Worst Circuit Rehabilitation Program 6

(1) Capital Forecast 7

Figure II-9 provides the recorded (2014-2018) cost and the forecast (2019-8

2023) for the WCR program. 9

18

Figure II-9 Worst Circuit Rehabilitation Program13

Multiple WBS Elements14 Recorded (2014 -2018)/Forecast (2019-2023)

(Total Company – Nominal $000)

(2) Program Description and Need 1

Cable failure is a significant contributor to poor system reliability; in 2

2018, failures of cable or cable accessories (such as elbows, junction bars, or cable splices) were 3

associated with 23% of SCE customer average outage duration and 19% of SCE customer average 4

outage frequency.15 To improve the performance of the system, the WCR program typically involves 5

replacing each circuit’s most risk-significant cable. In addition, this program adds circuit enhancements 6

including, but not limited to, switches, automated devices, branch line fuses, and fault indicators on a 7

case-by-case basis. In general, the WCR program focuses on mainline distribution cable. Figure II-10 8

illustrates the application of mainline cable on a typical underground distribution circuit. Mainline cable 9

failures tend to impact more customers than radial cable failures. 10

13 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 37-38 – Capital Detail by WBS Element for Worst Circuit

Rehabilitation Program.

14 WBS elements include: CET-PD-IR-CR, CET-PD-IR-WC.

15 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 39-40 – Reliability Data.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $153,013 $117,673 $143,162 $135,286 $118,299 $67,291 $32,566 $6,960 $7,161 $7,734

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

Forecast

19

Figure II-10 SCE’s Underground Distribution System: Mainline Cable

Cable systems also include a variety of cable components or accessories 1

such as elbows, splices, and junction bars. These associated cable components age and deteriorate, and 2

the failures of deteriorated components can be just as problematic as failures of the cable itself. The 3

WCR program replaces aging mainline cable components and accessories at the same time that it 4

replaces mainline cable. 5

SCE utilized the T&D risk assessment framework, referred to as 6

Prioritized Risk Informed Strategic Management (PRISM), to evaluate the safety, reliability, 7

environmental, and financial risks associated with in-service failures of mainline cable.16 For mainline 8

cable failure frequency, the PRISM analysis was based on SCE’s predictive analytics model for 9

mainline cable. For mainline cable failure consequences, the PRISM analysis was based on data sets 10

such as ODRM. The results of PRISM analysis provided SCE with an understanding of the relative risk 11

prioritization of all mainline cable within the total mainline cable population. The WCR program has 12

two primary objectives: (1) mitigate the safety and reliability risks associated with mainline cable 13

failures; and (2) improve the reliability performance of Worst Performing Circuits (WPCs) within the 14

SCE system. 15

16 See Chapter III for details on the PRISM framework.

20

(a) Mitigating Risks Associated with Aging Mainline Cable 1

SCE’s underground distribution system consists of a large amount 2

of aging cable. The largest population of underground cable installed on SCE’s distribution system is 3

known as cross-linked polyethylene (XLPE) cable. This cable type was the typical utility distribution 4

cable installed from the 1970s through the 1990s and represents approximately half of all primary 5

voltage underground distribution cable installed in SCE’s system. Table II-4 and Figure II-11 show 6

details of the current inventory of underground cable by cable type. 7

Table II-4 Inventory Details of Underground Cable by Cable Type

Type of Insulation

DescriptionEstimated Dates of Installation

Average Age (YE 2019)

Conductor Miles

PILCPaper Insulated Lead Covered

Prior to 1986 55 1,661

HMWHigh Molecular Weight Polyethylene

1968-1970 50 1,041

XLPECross-Linked Polyethylene

1970-1998 33 26,874

TR-XLPETree Retardant Cross-Linked Polyethylene

Since 1999 11 25,232

EPREthylene Propylene Rubber

2002-2019 8 331

LCCLead-Covered Cable

1920-1968 60 318

Unknown* NA NA NA 1,271

Total 56,727

*Approximately 2% of cable inventory is of unknown type and age. This population is assumed to consist of a relative distribution of the known inventory (e.g. XLPE represents 48.5% of cable inventory, therefore 48.5% of unknown cable is assumed to be XLPE)

21

Figure II-11 Inventory of Underground Cable by Type as of 2019

For older cable, breakdown of the insulation over time causes 1

cable failure. Typically, external moisture around the cable penetrates through the polyethylene 2

insulation, causing electrical tracking (a typical failure mechanism for insulators) along voids and 3

contaminants in the insulation and forming patterns that look like “trees.” Images of two different types 4

of “trees” found during laboratory analysis of cross-sections of field-aged cable are shown in Figure II-5

12. The phenomenon of “treeing” causes failures of underground cable, particularly older XLPE cables. 6

When the WCR program replaces such cables, SCE installs a newer type of cable known as tree-7

retardant cross-linked polyethylene (TR-XLPE) cable, which is more resistant to this phenomenon than 8

earlier predecessor types of distribution cable. 9

22

Figure II-12 Water Tree (left) and Electrical Tree (right) in Field-Aged Distribution Cable

When cables fail, electricity breaks through the insulation and 1

results in a fault, which causes an upstream protective device (such as a fuse, automatic recloser, or 2

substation circuit breaker) to operate and cut off power to all customers downstream of the protective 3

device. Because mainline cable failures impact a relatively large number of customers, they represent a 4

reliability risk to the SCE system. 5

In addition, heat associated with current flow contributes to 6

thermal decomposition of polymers in the cable, generating combustible gases. In extreme 7

circumstances, the high current flow from fault conditions can result in the release of a large amount of 8

uncontrolled energy (an explosion) from underground structures. Therefore, mainline cable failures also 9

represent a safety risk to the public due to the potential for such explosions. 10

(b) Improving the Reliability Performance of Worst Performing 11

Circuits 12

SCE must comply with annual reliability reporting requirements 13

established in D.16-01-008. Part of this annual reporting requirement is to provide a list of WPCs, 14

defined as those circuits in the bottom one percent of the SCE system based on System Average 15

Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) 16

performance. In the annual report, SCE is required to include a description of its plans to mitigate the 17

poor reliability performance for “repeat” WPCs, defined as circuits on the WPC list for more than one 18

reporting year. 19

23

The WCR program mitigates the poor reliability performance of 1

repeat WPCs as defined in D.16-01-008. Through the WCR program, SCE implements circuit 2

rehabilitation projects that typically involve replacing each circuit’s most risk-significant cable and, on a 3

case-by-case basis, add circuit enhancements such as switches, automated devices, branch line fuses, 4

and fault indicators. 5

(3) RAMP Integration 6

In Chapter 11 of SCE’s 2018 RAMP report, the WCR program was 7

identified as a control to the Underground Equipment Failure risk. SCE focused the RAMP risk analysis 8

on primary distribution underground electrical equipment failures that could potentially cause a vault or 9

manhole explosion event. To further characterize this risk and structure the risk analysis, SCE 10

constructed a “risk bowtie,”17 as shown in Figure II-13 below. 11

Figure II-13 RAMP Underground Equipment Failure Risk Bowtie

The WCR program addresses risks associated with underground 12

equipment failures by replacing aging mainline cable and cable accessories before they fail. Therefore, 13

the WCR program reduces one of the key drivers in the risk bowtie: Cable and Cable Accessories (D1a). 14

In addition, the WCR program targets mainline cable that has a higher reliability consequence of failure. 15

Therefore, the WCR program also reduces the reliability consequences associated with underground 16

equipment failures. 17

17 Please see Exhibit SCE-01, Vol. 02, for further detail on the RAMP “risk bowtie” approach.

24

(a) SED Comments 1

In its comments on SCE’s RAMP report,18 SED recommends that 2

SCE include in this GRC a discussion or proposal for system monitoring that would enable the utility to 3

identify equipment that is most likely to fail and to address problem areas before they escalate into a 4

situation similar to what occurred in 2015 in Long Beach. SCE’s development of a predictive analytics 5

model for underground cable is a significant step forward towards better identification of specific cable 6

segments that are most likely to fail and escalate to a larger problem. See Section II.A.1.c) for further 7

discussion. 8

(b) Reconciliation Between RAMP and GRC 9

A comparison of the WCR forecast as shown in RAMP versus the 10

WCR forecast in this GRC is shown in Table II-5. The WCR program was modeled in RAMP as control 11

C1 “Cable Replacement Programs (WCR).” 12

Table II-5 Worst Circuit Rehabilitation (WCR)

RAMP vs GRC Capital Forecast Comparison (Nominal 2018 $000)

The GRC forecast for the WCR program is significantly lower than 13

the RAMP forecast. The RAMP forecast, developed in 2018, represented SCE’s plan for the WCR 14

program to mitigate risks associated with underground cable failures, absent the additional resource 15

constraints identified for wildfire mitigation after the RAMP report date. SCE has reduced the GRC 16

forecast in the WCR program from the RAMP forecast levels to help ensure adequate resources to 17

address wildfire risks and the need for grid resiliency activities during this GRC cycle. 18



RAMP Risk RAMP

ID RAMP Control NameFiling Name 2019 2020 2021 2022 2023RAMP 103,681$ 93,370$ 93,367$ 93,367$ 99,702$ GRC 67,291$ 32,566$ 6,960$ 7,161$ 7,734$

Variance (36,389)$ (60,804)$ (86,408)$ (86,206)$ (91,968)$ Underground Equipment Failure C1 Cable Replacement Programs (WCR)

25

(4) Basis for Capital Expenditure Forecast 1

In previous GRCs, SCE forecast WCR program costs in units of conductor 2

miles of cable replacement (i.e. cost per mile). SCE has modified the forecast method to better account 3

for the dual nature of the WCR program to address aging distribution cable and WPC remediation. SCE 4

has built the forecast for the WCR program for 2019-2023 in two parts. The first part is a forecast of 5

mainline distribution cable replacements on a conductor-mile basis. The second part is a forecast of the 6

number of non-cable circuit enhancement projects on WPCs on a per-project basis. SCE’s recorded 7

costs (2014-2018) and forecast (2019-2023) for the WCR program are shown in Table II-6 for cable 8

replacements and Table II-7 for WPC projects. 9

Table II-6 Cable Replacements Under WCR Program19 Recorded (2014-2018)/ Forecast (2019-2023)

(Nominal $000)

19 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 41-42 – Cost of Worst Circuit Rehabilitation.

Year

Historical/Forecast Units (Cable Replacements

Completed by the WCR/Cable Replacement

Program: Conductor-Miles)

Forecast Unit Cost (WCR/Cable Replacement Program: Nominal $000)

Recorded/Forecast Cost(WCR/Cable ReplacementProgram: Nominal $000)*

2014 280 $153,0132015 414 $117,6732016 399 $143,1622017 251 $135,2862018 137 $118,2992019 177 $323 $57,1552020 73 $335 $24,4862021 15 $346 $5,1912022 15 $356 $5,3412023 16 $366 $5,861

*Recorded 2014-2018 includes both cable replacement and WPC

26

Table II-7 WPC Projects Under WCR Program20

Recorded (2014-2018)/Forecast (2019-2023) (Nominal $000)

The forecast for the WCR program was developed through several steps. 1

First, SCE evaluated the risks associated with underground cable failure, using the risk management 2

methods described in Chapter III of this testimony to develop risk scores. That scoring was then 3

validated through internal challenge sessions and informed the Distribution IR unconstrained need 4

reflected in Table II-3. This unconstrained need was modeled in RAMP, and the details for the WCR 5

program are shown in the RAMP row of Table II-5. 6

In 2019, SCE updated unit costs based on analysis of available 2014-2018 7

recorded data. SCE also significantly reduced the WCR program forecast in response to resource 8

constraints for SCE’s grid resiliency program.21 The reduced forecast shown in Table II-6 and Table II-7 9

combined reflects a total of approximately 250 conductor miles in 2019-2020 (approximately 125 10

conductor miles per year) and 46 conductor miles total in 2021-2023 (approximately 15 conductor miles 11

per year). 12

The reduced forecast for the WCR program is reasonable for three 13

reasons. First, the forecast level is sized to allow SCE to execute its grid resiliency priorities in light of 14

20 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 43-44 – Cost of Worst Circuit Rehabilitation – WPC.

21 See Exhibit SCE-01, Vol. 01 - Policy.

YearHistorical/Forecast Units

(Number of WPC Projects)Forecast Unit Cost

(WPC: Nominal $000)Recorded/Forecast Cost(WPC: Nominal $000)*

2014 2572015 1402016 1252017 1112018 892019 43 $236 $10,1362020 33 $245 $8,0802021 7 $253 $1,7692022 7 $260 $1,8202023 7 $267 $1,872

*Recorded 2014-2018 is included in WCR/Cable Replacement Program table

27

anticipated resource constraints. Second, the forecast level is sized to allow a minimal funding level for 1

repeat WPCs within the 2019-2023 horizon, consistent with D.16-01-008. Third, the forecast level 2

allows SCE to leverage the new predictive analytics model as a WCR program scoping tool for better 3

targeting of proactive cable replacements. Each of these factors is discussed below. 4

(a) Resource Requirements for Grid Resiliency 5

The WCR forecast in this GRC is sized to allow SCE to execute its 6

grid resiliency priorities in light of anticipated resource constraints. The 2019-2023 WCR forecast is a 7

significant reduction from prior GRC authorized levels and from the level of unconstrained need. This 8

reduction is reasonable in the near-term because it is based on the importance of mitigating wildfire 9

risks.22 10

(b) Minimum Funding Level for Repeat WPCs 11

The WCR program forecast will allow a minimal funding level for 12

“repeat WPCs” during this GRC cycle, consistent with D.16-01-008. With approximately 4,600 13

distribution circuits in the SCE system, SCE’s annual WPC list (i.e., the bottom 1% circuits in two 14

reliability metrics based on three-year performance history) includes forty-six circuits for poor SAIDI 15

performance and forty-six circuits for poor SAIFI performance. Because circuits can appear on both 16

lists, SCE averages approximately seventy unique circuits on one or both WPC lists each year. Among 17

these seventy circuits, SCE has averaged approximately thirty “repeat WPCs” each year since 18

implementation of the D.16-01-008 reporting requirements. 19

In previous years, SCE’s WCR program would identify and initiate 20

remediation projects for WPCs when they first appeared on the annual WPC list.23 As a result, SCE’s 21

experience has been that circuits that reappear on the WPC list the following year already have 22

remediation projects identified and in progress. Beginning in 2019, SCE has reduced the WCR program 23

forecast below historical and previously authorized levels due to design and construction resource 24

constraints resulting from wildfire mitigation work. Ultimately, by 2021-2023, SCE’s forecast for the 25

22 See Exhibit SCE-01, Vol. 01 and Exhibit SCE-01, Vol. 02 for discussions of wildfire risks and resource

constraints.

23 While the WPC list is an “annual” list, it is in fact based on a rolling 3-year performance history. Therefore, when a circuit first appears on the annual WPC list, it has essentially demonstrated poor performance for three years; if it appears on the “repeat WPC” list the following year, it has essentially demonstrated poor performance for a fourth consecutive year.

28

WCR program is sized to approximately one-quarter of “repeat WPCs” each year. With this forecast 1

level, SCE will prioritize a small number of “repeat WPCs” each year and then defer mitigation of other 2

“repeat WPCs” to years 2024 and beyond. 3

This is reasonable in the short-term based on the D.16-01-008 4

requirements. These requirements state, in part, that “any circuit appearing on this list of ‘deficient’ 5

(WPC) circuits that also appeared on the previous year's list would be marked by an asterisk. For each 6

asterisked circuit, each utility shall provide . . . an explanation of what is being done to improve the 7

circuit's future performance and the anticipated timeline for completing those activities (or an 8

explanation why remediation is not being planned) . . .” [emphasis added]. In other words, while D.16-9

01-008 establishes an expectation that SCE will improve the performance of repeat WPCs, the decision 10

allows SCE to defer, with explanation, specific remediation projects on a case-by-case basis. 11

(c) Predictive Analytics Models 12

In general, the 2019-2020 WCR program forecast is based on 13

scope already in the design or construction process.24 However, the scope for 2021 and beyond has not 14

yet been identified or submitted for design. The 2021-2023 WCR program forecast will allow SCE to 15

leverage the new predictive analytics model as a WCR program scoping tool for better targeting of 16

proactive cable replacements. 17

As opposed to WPC projects, which are inherently reactive, SCE’s 18

predictive analytics model allows for a proactive approach that will address high-risk circuits in advance 19

of poor performance. However, because this predictive analytics model for cable is relatively new, SCE 20

has not yet fully developed the process of incorporating predictive analytics model results into existing 21

WCR scoping processes. The 2021-2023 forecast of 15-16 conductor miles per year allows for a 22

reasonable test of SCE’s predictive analytics model as a cable replacement scoping tool in combination 23

with PRISM risk analysis. The knowledge that will be gained in years 2021-2023 will be valuable as 24

SCE continues to evolve its infrastructure replacement models and processes. 25

Using the predictive analytics model in this fashion also helps 26

address one of the WCR program compliance requirements from the 2018 GRC decision where SCE 27

was directed to change the minimum age used to select mainline cable replacement. SCE’s new 28

24 WCR projects typically take two years from initiation to completion, one year to design and one year to

construct.

29

predictive analytics model addresses this compliance requirement, in that it accommodates the scoping 1

of cable replacements at the age (plus other operating conditions) that statistically predicts an increased 2

probability of failure at the cable segment level. For example, the new predictive analytics model would 3

be able to distinguish between a 50-year old cable segment with a lower probability of failure and a 30-4

year old cable segment with a higher probability of failure. The capability to make more granular and 5

asset-specific decisions based on age plus other data is an important aspect of SCE’s plan to address this 6

compliance requirement from the 2018 GRC decision. 7

(5) Additional Compliance Requirement Discussion 8

(a) Recording Cable Failures by Cable Type 9

In D.19-05-020 (2018 GRC), the Commission directed SCE to 10

begin recording cable failures by cable type as part of the WCR program. 11

SCE has an existing process known as the Material Performance 12

Failure Report (MPFR) process, which is intended to allow communication and engagement between 13

field personnel and engineering regarding equipment failures. In this process, field personnel are able to 14

send failed equipment to engineering for review and analysis. In 2018, SCE investigated and piloted the 15

use of this process to collect and record information about cable failures by cable type. However, the 16

results of this pilot showed that the MPFR process is not suitable for this purpose. SCE concluded that 17

the MPFR process is well-suited for analysis of specific failure types (such as a specific manufacturing 18

defect in a production line of cable) or anomalous failures (such as failures of newly installed cable). 19

However, the MPFR process is not able to support the volume of data needed for systematic analysis of 20

all cable failures without becoming unduly burdensome on both field crews and engineering staff, as 21

SCE experiences over 1,000 cable failures per year. 22

At this time, SCE is evaluating whether modifications to another 23

process known as the Repair Order process would be better suited for recording cable failures by cable 24

type. A Repair Order (RO) is a form initiated by field personnel as they first respond to circuit 25

interruptions or other trouble calls. The form is used by field personnel to identify the type and size of 26

needed repair crews, and to provide a detailed list of material and equipment required to make repairs. 27

While this form is intended to identify material needed for repairs, it is possible that the form can be 28

modified to also include some basic information about the failed equipment itself, such as cable type. 29

Therefore, in 2019 SCE intends to evaluate whether field inspections documented in ROs can be 30

leveraged to help track cable failures by cable type. In either case, this compliance requirement was 31

30

identified at a time when SCE’s only failure models for distribution cable were separate Weibull curves 1

for each cable type. The predictive analytics model for cable is an improvement over previous models 2

and is applicable for all types of installed cable. For additional discussion, see Section II.A.1.c). 3

Minimum Age of Cable Replacement. 4

(b) Minimum Age Threshold of Cable Replacements 5

In D.19-05-020 (2018 GRC), SCE was directed to change the 6

“minimum age” used to select mainline cable replacement. For clarification, the final decision language 7

anticipated a simple update to the “minimum age” threshold for mainline cable replacements from 34 8

years to 41 years based on Weibull curve parameters. Predictive analytics modeling addresses this 9

requirement as it is a refinement of Weibull curve modeling that does not depend on “minimum age” 10

cable replacement thresholds. For additional discussion of predictive analytics modeling, please see 11

II.A.1.c). 12

(c) Economic Evaluation of Mainline Cable Injection 13

SCE previously re-evaluated the potential use of testing as part of 14

its WCR program to reduce the likelihood of replacing cable unnecessarily. SCE presented the results of 15

this analysis in the 2018 GRC. Based on this analysis, SCE concluded that testing of mainline cable is 16

not cost-justified as part of the cable-replacement decision process in the WCR program. 17

As directed by the Commission in D.19-05-020, SCE has 18

performed a similar cost-benefit economic analysis regarding cable injections on mainline cable.25 The 19

Commission stated that if this economic analysis determined that a mainline cable injection pilot was 20

necessary, SCE was to report on the quantitative and qualitative findings in the 2021 GRC. 21

(i) Differences between Mainline Cable and CIC 22

Because SCE has historically used cable injection on CIC 23

but not on mainline cable, any discussion of mainline cable injection must begin with a relative 24

comparison of the differences between mainline cable and CIC. 25

CIC is typically installed on “radial” portions of 26

distribution circuits and connected to mainline cable through fused underground switches, dedicated 27

positions on mainline switches, junction bars, or similar techniques. These provide convenient switching 28

25 Cable injection is a cable rejuvenation activity that provides life extension benefits through the physical

injection of a silicone-based fluid along the strands of aging underground primary distribution cable. For further discussion of cable injection, see II.C.1.b)(2).

31

points for de-energizing a single radial for purposes of cable injection without affecting other 1

downstream radials on the circuit. However, mainline switches, installed at less frequent intervals along 2

the circuit, divide circuits into “load blocks.” These load blocks can be de-energized by using mainline 3

switches for planned work on mainline cable, but doing so will de-energize all downstream load blocks, 4

not just the load block targeted for planned work. This means that scheduled outages for mainline cable 5

injection will impact a larger number of customers than scheduled outages for CIC injection. 6

(ii) Economic Analysis of Mainline Testing 7

SCE performed an economic analysis to determine the cost 8

effectiveness of a conceptual mainline injection program.26 The analysis focused on the life-cycle cost of 9

one year of WCR cable replacements on a per-mile basis under two options for mainline cable injection. 10

The first option (Option 1) determined the per-mile costs to replace all identified cables in the first year 11

with no mainline cable injection. The second option (Option 2) assumed that all identified cables that 12

were not successfully injected would be replaced in year one, and the remaining cables that were 13

successfully injected would be replaced in a future year. 14

Cables that are successfully injected will still fail in the 15

future and need to be replaced, but SCE does not yet have statistical information about future failure 16

rates of injected cable. Therefore, for this analysis, we assumed a mean-time-to-future-failure concept 17

for injected cable. Analysis was performed to determine the breakeven point of the mean-time-to-future-18

failure of injected cable compared to replacing all cable in year one. To account for timing differences, 19

SCE compared the two scenarios using a Present Value of Revenue Requirement (PVRR) analysis. 20

The economic analysis was based on three key 21

assumptions: cable injection yield rates (i.e., effectiveness); cable injection costs (i.e., efficiency); and 22

cable replacement costs. The assumptions used in this analysis were: 23

Cable injection yield rates (i.e., effectiveness) were 24

based on SCE’s experience for CIC injection. 25

Specifically, SCE assumed a 65% yield rate of 26

successful injections (i.e., 35% failure-to-inject rate); 27

26 For a full summary of the economic analysis, refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 45-48 – Economic

Evaluation of Mainline Cable Injection.

32

Cable injection costs (i.e., efficiency) for mainline 1

injection were based on radial injection costs, adjusted 2

to account for the slower pace of mainline testing based 3

on switching requirements and operational 4

complexities; and 5

Cable replacement costs were based on unit costs from 6

this 2021 GRC cycle for the WCR program. 7

Figure II-14 summarizes the PVRR for Option 1 and 8

Option 2 scenarios described above and shows when Option 2 breaks even with Option 1. On a PVRR 9

basis, Option 1 requires mainline cable that is successfully injected to last an average of approximately 10

another twenty years to be cost-effective. 11

Figure II-14 Summary of Mainline Injection Cost/Benefit Analysis

These results are not conclusive regarding whether 12

mainline cable injection would be cost-effective for two reasons. First, SCE does not know whether 13

mainline cable that is injected will see a twenty-year life extension benefit. Second, the results are highly 14

sensitive to mainline cable injection costs, which can vary widely depending on circuit-specific design 15

details. 16

Breakeven Analysis

–

100

200

300

400

500

600

700

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39

PVRR per M

ile ($

000s)

Years Until Replacement After Injection

Wtd Avg PVRR of Injection & Future Replacement PVRR of Replacing Now

33

(iii) Mainline Injection Next Steps 1

Based on the inconclusive results of the economic analysis, 2

SCE will perform further analysis. During the near-term pause in the CLE Program described in 3

II.C.1.b)(4), SCE is planning the following two steps: 4

SCE will analyze performance of the CIC cables 5

successfully injected by SCE to date. This analysis will 6

help SCE develop a better expectation of the mean life 7

expectancy of successfully injected field-aged cable and 8

understand the causes of post-injection failures; and 9

SCE will continue to refine unit cost assumptions for 10

mainline cable injection. 11

SCE will share the results of these efforts as they become 12

available and discuss any next steps at that time. 13

b) Cable Life Extension Program 14


Table II-8 provides the recorded (2014-2018) cost and the forecast (2019-16

2023) cost for the Cable Life Extension (CLE) Program. 17

34

Table II-8 Cable Life Extension Program27

CET-PD-IR-LE Recorded (2014 -2018)/Forecast (2019-2023)



In the late 1960s, SCE began installing a type of underground cable 2

known as “cable-in-conduit,” or CIC. CIC is distinguished not by its insulation material (although its 3

insulation is typically XLPE), but by its construction. While mainline cable is typically installed in rigid 4

PVC duct, CIC was installed in relatively thin-walled polypropylene tubing. CIC came from the 5

manufacturer with the conductor already inside the polypropylene tubing and coiled up on a large reel. It 6

was installed primarily in radial branches of circuits serving residential customers. Figure II-15 7

illustrates the application of radial cable in a typical underground distribution circuit. 8

27 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 49-51 – Capital Detail by WBS Element for Cable Life Extension

Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $13,244 $11,665 $22,858 $32,033 $31,258 $20,574 ($0) ($0) ($0) ($0)

($5,000)

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

Forecast

35

Figure II-15 SCE’s Underground Distribution System: Radial Cable

CIC was very attractive at the time of initial installation due to its: (1) ease 1

of installation which shortened the construction time of residential developments; (2) lower cost relative 2

to cable installed in rigid duct; and (3) greater durability than direct buried cable. 3

However, decades later CIC was found to be very difficult to replace. 4

While cable installed in rigid PVC duct can be removed relatively easily, CIC cable resists being pulled 5

out from its polypropylene tubing. This is particularly true when the polypropylene tubing has been 6

damaged, as is usually the case when a CIC cable faults to ground. The tight clearances between the 7

conductor and the tubing wall, the tendency of the tubing to crush and impinge on the conductor, and the 8

tendency of the concentric neutral wires to break and “ball up” all make removal of the CIC conductor 9

difficult. As a result, outages to replace failed CIC can be long in duration. 10

Approximately 13,000 conductor-miles, or one-fourth of SCE’s cable 11

population, is CIC. The challenge of an aging cable population cannot be adequately met without 12

addressing CIC. 13

36

The CLE program performs two types of life-extension activities for CIC: 1

(1) testing and (2) injection. The first activity in the CLE program is a partial discharge28 testing activity 2

(“testing”), which provides life extension benefits by identifying those cable segments at greatest risk 3

for imminent failure. Cable segments that test “good” are those segments shown to be partial discharge-4

free at expected operating voltage levels and therefore expected to have minimal risk of imminent 5

failure. Cable segments that test “bad” are those segments found to exhibit partial discharge activity that 6

would continue to compromise the cable insulation in normal operation. These segments are scheduled 7

for replacement through the CIC Replacement program. The second activity in the CLE program is a 8

cable rejuvenation activity (“injection”) that provides life extension benefits by improving the insulation 9

characteristics of aged cable. Cable is first assessed to see whether it can be injected. Degraded 10

concentrics, critical bends, and an inability to withstand the pressure of the injection make a cable 11

unable to be injected. These segments are also scheduled for replacement through the CIC Replacement 12

program. For cable that can be injected, a silicone-based fluid is physically injected along the strands of 13

the cable. This fluid migrates into the conductor insulation, modifying its chemistry and improving its 14

dielectric strength. Cable injection provides an aggregate life extension benefit for all injected cable 15

regardless of present insulation condition. 16

SCE first began cable testing on CIC in 2012, as a means of distinguishing 17

between cables in good condition and cables in poor condition and needing replacement. This program 18

focuses SCE’s CIC Replacement program efforts on those segments with the highest probability of 19

failure. This program has also provided data that has been used in the development of SCE’s predictive 20

analytics model for cable failures. SCE first began cable injection in 2016 as an additional approach to 21

cable life extension. At this time, SCE has gathered only three years of injection data, and because this 22

data is less extensive than the data obtained from cable testing, SCE has not incorporated this data into 23

its predictive analytics model for cable failures. 24

At this time, resource-related constraints on the CIC Replacement program 25

necessitates the reduction of the forecast for the CLE program in this GRC. This reduction is discussed 26

in Section II.C.1.b)(4). However, the near-term forecast reduction should not be interpreted as 27

28 Partial discharge is the localized degradation of cable insulation that can develop over time due to

manufacturing imperfections, installation errors, environmental conditions, or abnormal operating conditions. It can lead to possible micro arcing inside the insulation, which can enlarge over time until eventual failure of the cable.

37

diminishing the long-term need for the CLE program. Cable testing and cable injection, as implemented 1

through the CLE program, provide valuable life extension benefits to SCE’s aging radial cable systems. 2

As long as SCE has CIC nearing end-of-life, the CLE program will continue to play an important role in 3

managing these aging cable systems. 4


In Chapter 11 of SCE’s 2018 RAMP report, the CLE program was 6

identified as a control to risks associated with underground equipment failures. SCE focused the RAMP 7

risk analysis on primary distribution underground electrical equipment failures that could potentially 8

cause a vault or manhole explosion event. To further characterize this risk and structure the risk analysis, 9

SCE constructed a “risk bowtie,”29 as shown in Figure II-16. 10


The CLE program, in concert with the CIC Replacement program, 11

addresses the risks of radial cable failures. The CLE and CIC Replacement programs impact Driver D1a 12

(Cable and Cable Accessories). These two programs either extend the life of aging radial cables or 13

replace radial cables and cable accessories prior to failure. In general, the CLE and CIC Replacement 14

programs target aging radial cable based on probability of failure and not consequence of failure. 15

Therefore, while the CLE and CIC Replacement programs impact the frequency of Driver D1a, they do 16

not impact outcomes or consequences associated with failures. 17

29 Please see SCE-01, Vol. 02, for further detail on the RAMP “risk bowtie” approach.

38

(a) Reconciliation Between RAMP and GRC 1

A comparison of the CLE program forecast as shown in RAMP 2

versus the CLE program forecast in this GRC is shown in Table II-9. The CLE and CIC Replacement 3

programs were modeled together in RAMP as part of control C2 “Cable Replacement Programs (CIC).” 4

Table II-9 Cable Life Extension (CLE) Controls


The GRC forecast for the CLE Program is significantly lower than 5

the RAMP forecast of the CLE portion of control C2. The RAMP forecast, developed in 2018, 6

represented what SCE planned to spend for the CLE program to mitigate risks associated with 7

underground cable failures, absent the additional resource constraints identified for the wildfire 8

mitigations after the RAMP report date. SCE has reduced the GRC forecast in the CLE program from 9

the RAMP forecast levels to help ensure adequate resources to address wildfire risks and the need for 10

grid resiliency activities during this GRC cycle. 11


SCE’s recorded (2014-2018) and forecast (2019-2023) for the CLE 13

program are shown in Table II-10 and Table II-11. To develop the 2019-2023 Forecast Cost, SCE 14

analyzed 2014-2018 recorded cost data to develop 2019-2023 Forecast Unit Costs, and then multiplied 15

these by 2019-2023 Forecast Units. 16

RAMP Risk RAMP

IDRAMP Control

NameFiling Name 2019 2020 2021 2022 2023RAMP 21,751$ 20,278$ 20,278$ 20,278$ 20,278$ GRC 20,574$ -$ -$ -$ -$

Variance (1,177)$ (20,278)$ (20,278)$ (20,278)$ (20,278)$

Underground Equipment

FailureC2

Cable Replacement Programs (CIC)

39

Table II-10 Cable Testing Under CLE Program30

Recorded (2014-2018)/ Forecast (2019-2023) (Nominal $000)

Table II-11 Cable Injection Under CLE Program31


The forecast for the CLE program was developed through two steps. First, 1

SCE developed the unconstrained need for the CLE program through internal challenge sessions, based 2

on SCE’s experience with the program. This informed the Distribution IR unconstrained need reflected 3

in Table II-3; the details for the CLE program are in the RAMP row of Table II-9. Next, SCE reduced 4

30 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 52-53 – Cost of Cable Testing.

31 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 54-55 – Cost of Cable Injection.


(Cable Testing: Conductor-Miles)

Forecast Unit Cost (Cable Testing: Nominal

$000)

Recorded/Forecast Cost(Cable Testing: Nominal

$000)2014 309 $12,7682015 150 $6,8522016 277 $10,4782017 394 $19,9962018 422 $18,3862019 224 $49 $10,7522020 0 $51 $02021 0 $52 $02022 0 $54 $02023 0 $55 $0


(Cable Injection: Conductor-Miles)

Forecast Unit Cost (Cable Injection: Nominal

$000)

Recorded/Forecast Cost(Cable Injection: Nominal

$000)2014 $4742015 $4,8132016 115 $12,3802017 120 $12,0372018 138 $12,8722019 92 $106 $9,8222020 0 $111 $02021 0 $114 $02022 0 $117 $02023 0 $121 $0

40

the forecast for the CLE program based on the reduced forecast for the CIC Replacement program. SCE 1

has reduced its CIC Replacement program forecast to 151 conductor miles during years 2019-2023 in 2

response to resource constraints for SCE’s grid resiliency program.32,33 However, based on CLE 3

activities executed in 2019 and previous years, SCE will have more than twice this amount of pending 4

CIC replacement scope already identified by year-end 2019. 5

Therefore, the CIC Replacement program forecast reduction has resulted 6

in a near-term situation where there is enough CLE-identified scope to support the CIC Replacement 7

program through this GRC period. In light of this situation, SCE has chosen to pause the CLE program 8

from 2020 through 2023 and focus on CIC replacements already identified by CLE program activities 9

through 2019. SCE expects to resume the CLE program when identification of additional CIC 10

Replacement program scope is once again needed. 11

(5) Activities During CLE Program Pause (2020-2023) 12

Even with the temporary pause in the CLE Program for 2020-2023, SCE 13

is mindful of the 2012 compliance requirement regarding efforts undertaken to develop a best practice 14

and most cost-effective method for CIC replacements. This pause creates an opportunity to perform 15

additional analysis on the data gathered from both cable testing and cable injection in order to further 16

refine SCE’s CIC-related strategies. Three examples are provided below. 17

First, SCE has now gathered multiple years of data for both testing and 18

injection. During the pause in the CLE Program, SCE intends to analyze the data gathered from both 19

activities to better understand the long-term comparative performance characteristics of cable that tests 20

“good” versus cable that is successfully injected. SCE expects this analysis will help optimize the 21

relative mix of testing versus injection levels in future years of the CLE program. 22

Second, SCE has used testing data to help build its predictive analytics 23

model for cable failures but has not yet used more recent injection data for that purpose. During the 24

pause in the CLE program, SCE intends to explore ways to incorporate injection data into future 25

iterations of its predictive analytics model for cable failures. 26

Third, SCE is aware of various technological alternatives to both testing 27

and injection. For example, some cable testing vendors in the industry advocate for the use of energized 28

32 See SCE-01, Vol. 01 - Policy.

33 The CIC Replacement program forecast is discussed in II.C.1.c)(4).

41

partial discharge testing; SCE’s current CLE practice involves the use of de-energized partial discharge 1

testing. SCE intends to explore the latest industry advances in both testing and injection techniques 2

during the pause in the CLE program to evaluate whether alternative CLE technologies are worth 3

consideration in future years of the program. 4

c) Cable-in-Conduit Replacement Program 5


Table II-12 provides the recorded (2014-2018) cost and the forecast 7

(2019-2023) cost for the CIC Replacement program. 8

42

Table II-12 Cable-in-Conduit Replacement Program

CET-PD-IR-CC34 Recorded (2014 -2018)/Forecast (2019-2023)



The CIC Replacement program proactively replaces segments of SCE’s 2

cable-in-conduit (CIC) population approaching the end of their service life. The objective of the 3

program is to reduce the number of in-service failures of CIC cable and thus drive down the number of 4

unplanned outages to SCE customers. This program is closely related to the CLE program described in 5

II.C.1.b); the scope for SCE’s CIC Replacement program is generated from the activities associated with 6

SCE’s CLE program. 7

34 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 56-57 – Capital Detail by WBS Element for Cable-in-Conduit

Replacement Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $23,042 $54,084 $33,468 $42,363 $50,723 $17,074 $13,866 $5,989 $6,162 $5,987

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

Forecast

43


In Chapter 11 of SCE’s 2018 RAMP report, the CLE program was 2

identified as a control to risks associated with underground equipment failures. SCE focused the RAMP 3

risk analysis on primary distribution underground electrical equipment failures that could potentially 4

cause a vault or manhole explosion event. To further characterize this risk and structure the risk analysis, 5

SCE constructed a “risk bowtie,” as shown in Figure II-17. 6


The CIC Replacement program, in concert with the CLE program, 7

addresses the risks of radial cable failures. The CLE and CIC Replacement programs impact Driver D1a 8

(Cable and Cable Accessories). These two programs either extend the life of aging radial cables or 9

replace radial cables and cable accessories prior to failure. In general, the CLE and CIC Replacement 10

programs target aging radial cable based on probability of failure and not consequence of failure. 11

Therefore, while the CLE and CIC Replacement programs impact the frequency of Driver D1a, these 12

two programs do not impact outcomes or consequences associated with failures. 13


A comparison of the CIC Replacement program forecast as shown 15

in RAMP versus the CIC Replacement program forecast in this GRC is shown in Table II-13. The CLE 16

and CIC Replacement programs were modeled together in RAMP as part of control C2 “Cable 17

Replacement programs (CIC).” 18

44

Table II-13 Cable-in-Conduit Replacement (CIC) Program Controls

RAMP vs. GRC Capital Forecast Comparison (Nominal $000)

The GRC forecast for the CIC Replacement program is 1

significantly lower than the RAMP forecast of the CIC Replacement portion of control C2. The 2018 2

RAMP forecast represented what SCE planned to forecast for the CIC Replacement program to mitigate 3

risks associated with underground switch failures, absent the resource constraints for wildfire 4

mitigations identified after the RAMP report date. SCE has reduced the GRC forecast in the CIC 5

Replacement program from the RAMP forecast levels to help ensure adequate resources to address the 6

growing wildfire risks and the need for grid resiliency activities during this GRC cycle. 7


SCE’s recorded costs (2014-2018) and forecast (2019-2023) for the CIC 9

Replacement program are shown in Table II-14. 10

RAMP Risk RAMP

IDRAMP Control

NameFiling Name 2019 2020 2021 2022 2023RAMP 42,828$ 40,000$ 40,000$ 40,000$ 40,000$ GRC 17,074$ 13,866$ 5,989$ 6,162$ 5,987$

Variance (25,754)$ (26,134)$ (34,011)$ (33,838)$ (34,013)$


FailureC2

Cable Replacement Programs (CIC)

45

Table II-14 CIC Replacement Program35


The forecast for the CIC Replacement program was developed through 1

several steps. First, SCE developed the unconstrained need for the CIC Replacement program through 2

internal challenge sessions, based on SCE’s experience with the program. This informed the Distribution 3

IR unconstrained need reflected in Table II-3; the details for the CIC Replacement program are in the 4

RAMP row of Table II-13. In 2019, SCE updated unit costs based on analysis of available 2014-2018 5

recorded data. Next, SCE reduced the forecast for the CIC Replacement program in response to resource 6

constraints for SCE’s grid resiliency program.36 7

The reduced forecast for the CIC Replacement program is reasonable for 8

two reasons. First, the forecast level is sized to allow SCE to execute its grid resiliency priorities in light 9

of anticipated resource constraints. Second, the forecast level is consistent with a minimal funding level 10

to address the amount of scope-in-hand for CIC Replacements within the 2019-2023 horizon, based on 11

CLE Program activities to date. Each of these reasons is discussed below. 12


The CIC Replacement program forecast in this GRC is sized to 14

allow SCE to execute its grid resiliency priorities in light of anticipated resource constraints. The 2019-15

2023 CIC Replacement program forecast is a significant reduction from prior GRC authorized levels and 16

35 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 58-59 – Cost of Cable in Conduit Replacement.



(CIC Replacement: Conductor-Miles)

Forecast Unit Cost (CIC Replacement:

Nominal $000)

Recorded/Forecast Cost(CIC Replacement:

Nominal $000)2014 57 $23,0422015 218 $54,0842016 125 $33,4682017 176 $42,3632018 113 $50,7232019 55 $310 $17,0742020 43 $322 $13,8662021 18 $333 $5,9892022 18 $342 $6,1622023 17 $352 $5,987

46

from the level of unconstrained need. This reduction is reasonable in the near-term because it is based on 1

the importance of mitigating wildfire risks.37 2

(b) Previously Identified CIC Replacement Program Scope 3

The CIC Replacement program forecast will allow for a 4

meaningful reduction in the amount of previously identified CIC Replacement program scope through 5

the end of this GRC cycle. SCE estimates that 250 conductor miles of CIC Replacement program scope 6

may still be in hand by the end of this GRC cycle at forecast rates. This will leave approximately one to 7

two years of CIC replacement scope still remaining beyond 2023 based on historical replacement rates. 8

In other words, this GRC forecast will allow SCE the time needed to resume CLE activities after this 9

GRC cycle without interruptions to ongoing CIC replacement activities. 10

d) Underground Switch Replacement Program 11



(2019-2023) for the Underground Switch Replacement program. 14

37 See SCE-01, Vol. 01 and SCE-01, Vol. 02 for discussions of wildfire risks and resource constraints.

47

Table II-15 Underground Switch Replacement Program38

CET-PD-IR-SR Recorded (2014 -2018)/Forecast (2019-2023)



The Underground Switch Replacement program removes old oil-filled 2

underground distribution switches located in underground structures and replaces them with newer 3

technology switches. This program has historically focused on mainline oil switches, and in recent years 4

the program has begun to shift focus to also address radial oil switches. The primary reason for SCE’s 5

program to remove old oil-filled switches is that failures of oil-filled switches can be violent. Violent 6

failures of oil-filled equipment can damage adjacent electrical equipment (e.g., cable, transformers, 7

switches). Property damage and injuries can also result from violent oil switch failures. Because oil-8

filled subsurface switches are typically contained in relatively small concrete structures, violent failures 9

38 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 60-61 – Capital Detail by WBS Element for Underground Switch


2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $19,580 $25,890 $17,566 $19,129 $9,714 $3,389 $3,520 $2,642 $3,284 $3,495

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

Forecast

48

of oil switches can release enough energy to displace the lids of such structures which in turn can cause 1

great bodily harm and property damage. 2

SCE’s goal is to continue replacing subsurface oil-filled distribution 3

switches until all such switches are removed from the SCE system and replaced with newer technology 4

gas or vacuum switches. Because the present population of oil-filled radial switches is so much larger 5

than the present population of oil-filled mainline switches, and because approximately 70% of SCE’s 6

underground switch failures are radial switch failures,39 SCE will replace more radial switches than 7

mainline switches during this GRC cycle. An illustration of underground switches in both mainline and 8

radial applications is shown in Figure II-18. 9

Figure II-18 SCE’s Underground Distribution System: Underground Switches

Switches are a vital piece of equipment used on the distribution system for 10

opening and closing circuit connections. They are found in both overhead and underground circuits, with 11

underground circuits containing both subsurface and pad-mounted switches. As of year-end 2018, the 12

SCE distribution system contained about 48,000 underground switches, including approximately 7,600 13

subsurface oil-filled radial switches and about 800 subsurface oil-filled mainline switches. The age 14

39 See SCE’s 2018 RAMP report, Chapter 11, page 11-12. Note that in the RAMP report, SCE referred

to radial switches as Buried Underground Residential Distribution (BURD) switches.

49

distribution of these underground switches is shown in Figure II-19. Newer switches in the SCE system 1

are predominantly gas switches, and older switches are predominantly oil-filled switches, based on 2

design standards applicable at the time of installation. 3

Figure II-19 Age Distribution of Switches

Subsurface switches are inspected every three years in compliance with 4

GO 165. These inspections include visual examination of the enclosure for corrosion, leaks, and other 5

external problems. Every six years, every oil-filled switch is subjected to an oil test to check for water 6

ingress and other problems. Unfortunately, inspections cannot detect deterioration of internal 7

components such as electrical contacts, and inspections do not detect all imminent failures of switches. 8


Prioritized Risk Informed Strategic Management (PRISM), to evaluate the safety, reliability, 10

environmental, and financial risks associated with in-service failures of underground switches.40 For 11

switch failure frequency, the PRISM analysis was based on SCE’s predictive analytics model for 12

underground switches. For switch failure consequences, the PRISM analysis was based on data sets such 13

as population density, downstream customers, outage durations, and volume of oil or gas within each 14


0

500

1,000

1,500

2,000

2,500

3,000

1960

1966

1969

1972

1975

1978

1981

1984

1987

1990

1993

1996

1999

2002

2005

2008

2011

2014

2017

Number of UG Switches

Year of Installation

50

switch. The results of PRISM analysis provided SCE with an understanding of the risks associated with 1

all underground switches within the total switch population. Through this analysis, SCE observed that in 2

addition to risks associated with underground oil switch failures, there are some existing risks associated 3

with underground gas switch failures as well. While SCE is currently prioritizing infrastructure 4

replacement efforts on underground oil switches, SCE anticipates that as the inventory of underground 5

oil switches reduces over time, the program will shift to address the risks associated with gas switches in 6

future GRC cycles. 7


In Chapter 11 of SCE’s 2018 RAMP report, the Underground Switch 9

Replacement program was identified as a control to the Underground Equipment Failure risk. SCE 10

focused this RAMP risk analysis on primary distribution underground electrical equipment failures that 11

could potentially lead to a vault or manhole explosion event. To further characterize this risk and 12

structure the risk analysis, SCE constructed a “risk bowtie,”41 as shown in Figure II-20. 13


The Underground Switch Replacement program addresses the risks 14

associated with underground switch failures leading to explosions in underground structures. The 15

program will impact Switches (D1c) by removing older oil-filled switches that are particularly prone to 16

violent failure and replacing them with newer gas or vacuum switches. Therefore, this program reduces 17


51

underground equipment failure risks by reducing the driver frequency of underground equipment failure 1

events. 2

(a) SED Comments 3

In its comments on SCE’s RAMP report,42 SED recommends that 4

SCE include in this GRC a discussion or proposal for system monitoring that would enable the utility to 5

identify equipment that is most likely to fail and to address problem areas before they escalate into a 6

situation similar to what occurred in 2015 in Long Beach. SCE’s development of a predictive analytics 7

model is a significant step forward towards better identification of specific switches that are most likely 8

to fail and escalate to a larger problem. See Section II.A.1.c) for further discussion. 9

(b) Reconciliation Between RAMP and GRC 10

A comparison of the Underground Switch Replacement program 11

forecast as shown in RAMP versus the forecast in this GRC is shown Table II-16. The Underground 12

Switch Replacement program was modeled in RAMP as control C3 “UG Oil Switch Replacement 13

program.” 14

Table II-16 Underground Switch Replacement Program Controls


The GRC forecast for the Underground Switch Replacement 15

program is significantly lower than the RAMP forecast. The 2018 RAMP forecast represented what SCE 16

planned to forecast for the Underground Switch Replacement program to mitigate risks associated with 17

underground switch failures, absent the resource constraints for wildfire mitigations identified after the 18

RAMP report date. SCE has reduced the GRC forecast in the Underground Switch Replacement 19



RAMP Risk RAMP

IDRAMP Control / Mitigation Name

Filing Name 2019 2020 2021 2022 2023RAMP 16,690$ 17,388$ 17,789$ 22,017$ 23,092$ GRC 3,389$ 3,520$ 2,642$ 3,284$ 3,495$

Variance (13,301)$ (13,868)$ (15,147)$ (18,733)$ (19,596)$


FailureC3

UG Oil Switch Replacement

Program

52

program from the RAMP forecast levels to help ensure adequate resources to address the growing 1

wildfire risks and the need for grid resiliency activities during this GRC cycle. 2


SCE’s recorded costs (2014-2018) and forecast (2019-2023) for the 4

Underground Switch Replacement program are shown in Table II-17. 5

Table II-17 Underground Switch Replacement Program43 Recorded (2014-2018)/ Forecast (2019-2023)

(Nominal $000)

In 2018, SCE evaluated the risks associated with underground switch 6

failure, using the risk management methods described in Chapter III of this testimony to develop risk 7

scores. That scoring was then validated through internal challenge sessions and informed the 8

Distribution IR unconstrained need reflected in Table II-3. This unconstrained need was modeled in 9

RAMP, and the details for the Underground Switch Replacement program are shown in the RAMP row 10

of Table II-16. 11


recorded data. SCE also reduced the Underground Switch Replacement program forecast in response to 13

resource constraints for SCE’s grid resiliency program.44 The reduced forecast shown in Table II-17 14

reflects a total of 149 switch replacements in 2019-2023. 15

43 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 62-63 – Cost of Underground Switch Replacements.


YearHistorical/Forecast Units (Number of Underground

Switch Replacements)

Forecast Unit Cost (Underground Switch

Replacement: Nominal $000)

Recorded/Forecast Cost(Underground Switch


2014 232 $19,5802015 251 $25,8902016 164 $17,5662017 221 $19,1292018 166 $9,7142019 33 $103 $3,3892020 33 $107 $3,5202021 24 $110 $2,6422022 29 $113 $3,2842023 30 $117 $3,495

53

The reduced forecast for the Underground Switch Replacement program is 1

reasonable for two reasons. First, the forecast level appropriately accounts for SCE’s grid resiliency 2

priorities and resulting resource constraints. Second, the forecast allows SCE to leverage the new 3

predictive analytics model as an Underground Switch Replacement program scoping tool for better 4

targeting of proactive cable replacements. Each of these factors is discussed below. 5


The Underground Switch Replacement program forecast in this 7

GRC is sized to account for SCE’s grid resiliency priorities and the resulting resource constraints. The 8

2019-2023 Underground Switch Replacement program forecast is a significant reduction from prior 9

GRC authorized levels and from the level of unconstrained need. This reduction is reasonable in the 10

near-term because it is based on the importance of mitigating wildfire risks.45 11

(b) Predictive Analytics Models and PRISM Risk Analysis 12

The 2019-2023 Underground Switch Replacement program 13

forecast, sized to replace a much smaller number of switches than in previous years, allows SCE the 14

opportunity to test implementation of its new Predictive Analytics model for switches as a scoping tool 15

in combination with PRISM risk analysis. 16

SCE’s predictive analytics model for switches uses multiple data 17

sets that leverage the predictive value of multiple variables in modeling failure probabilities for 18

individual assets. SCE has just recently begun using this new predictive analytics model for switch 19

failures as an input to PRISM risk analysis for underground switches. The 2019-2023 forecast of 20

approximately 30 switches per year allows for a reasonable test of the implementation of PRISM risk 21

analysis, specifically informed by SCE’s predictive analytics model, as a switch replacement scoping 22

tool. The knowledge that will be gained will be valuable as SCE continues to evolve its infrastructure 23

replacement models and processes. 24

e) Underground Structure Replacement Program 25



(2019-2023) for the Underground Structure Replacement program. The related O&M expenses are 28

included in Inspections & Maintenance section of SCE-02, Volume 1, Chapter 2. 29


54

Table II-18 Underground Structure Replacement Program46

CET-PD-IR-UG Recorded (2014 -2018)/Forecast (2019-2023)



Underground vaults are concrete structures used to house energized 2

equipment, including switches, transformers, cable, and cable components. Underground manholes are 3

concrete structures that are similar to, but are slightly smaller than, underground vaults, and typically 4

contain cable and cable components only. An illustration of these underground structures is shown in 5

Figure II-21 and Figure II-22. 6

46 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 64-66 – Capital Detail by WBS Element for Underground Structure


2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $130,644 $101,861 $76,014 $52,231 $56,730 $27,573 $21,771 $13,562 $13,867 $14,214

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

Forecast

55

Figure II-21 SCE’s Underground Distribution System: Vaults and Manholes

Figure II-22 Vault and Manhole Structures

The Underground Structure Replacement program consists of three 1

different activities: (1) structure replacements; (2) shoring; and (3) Cover Pressure Relief and Restraint 2

(CPRR). Each of these are described below. 3

(a) Structure Replacements and Shoring 4

Structural engineering standards, manufacturing processes, and 5

maintenance practices have changed over the years with advancements in technology. Precast reinforced 6

56

concrete structures were first used in the industry in the 1960s as an alternative to cast-in-place 1

construction practices. However, a significant problem with these early precast concrete structures was 2

the use of calcium chloride admixture to the concrete mix. This admixture was used from the 1960s to 3

the 1980s to accelerate the curing time, which allowed for rapid production needed for the development 4

boom in these decades. The industry has since determined this practice is a cause for steel reinforcing 5

(rebar) to corrode. By the 1990s, the calcium chloride additive was removed from the concrete mix. 6

The structures manufactured during the decades of the 1960s, 7

1970s, and 1980s make up nearly half of SCE’s existing vaults and manholes. These structures will 8

continue to deteriorate in the foreseeable future, making necessary a program of structural replacement 9

and shoring to address these degradation problems. 10

General Order 165 requires periodic inspections of underground 11

equipment. This requirement is met by the Underground Detailed Inspection (UDI) process. During 12

these underground detailed inspections, UDI inspectors determine whether there is evidence of 13

deterioration of the underground structure that warrants an in-depth assessment. If such evidence is 14

found, a field investigation (FI) of the structure is conducted by a certified concrete inspector. The FI 15

consists of evaluating the structural condition of the floor, walls, ceiling, and access according to a 16

modified American Society of Civil Engineers (ASCE) infrastructure report card system. The system 17

assigns grades ranging from A (excellent) to F (at risk of failing). Based on the assigned grades, a 18

remediation recommendation is prepared with options including: replacement, shoring, monitoring, or 19

no action required. The report is reviewed and signed by a State of California licensed professional civil 20

engineer. 21

When the remediation recommendation is replacement, typical 22

vault replacements are completed by using a “shoo-fly” method. In this method, electrical equipment is 23

de-energized, removed from the vault, and then re-energized outside. While the equipment is outside, 24

the new structure is installed in the same location as the old structure, then the equipment is replaced 25

inside the new structure. This method allows the crews to complete the vault replacement while 26

minimizing customer outages. 27

As opposed to full structural replacement, vault shoring consists of 28

cedar and/or treated laminated wood support columns, adjustable steel brackets, and wood support 29

beams to reinforce a deteriorated vault ceiling. Vault shoring is less costly than a structure replacement, 30

but is only installed when existing walls are structurally sound. The purpose of vault shoring is to extend 31

57

the life of the structure by supporting the deteriorated vault ceiling. Vault shoring is adjustable and can 1

be modified in the field to accommodate different vault sizes and equipment configurations. It is 2

installed by lowering components through the vault access and then assembled inside the structure. 3

Current vault shoring is an improvement over previous shoring technologies because it minimizes the 4

shoring footprint within the vault and restores the strength of the structure to current structural code 5

requirements (AASHTO H-20 loading capacity47). An illustration of vault shoring is shown in Figure II-6

23. 7

Figure II-23 Vault Without and With Shoring

(b) Cover Pressure Relief and Restraint (CPRR) 8

The CPRR activity mitigates public safety risks associated with 9

explosions in underground structures by replacing older conventional vault covers with SCE’s newer 10

CPRR standard. The CPRR is a self-restraining pressure relieving cover combined with shackles and 11

chains connected to the ceiling of the structure as shown in Figure II-24. In the event of an explosion, 12

the CPRR is designed to relieve pressure inside the structure, restrain the cover from becoming a 13

projectile, and reseat the cover back on the access frame. An illustration of the CPRR system is shown in 14

Figure II-24. 15

47 http://www.dot.ca.gov/des/techpubs/manuals/bridge-design-specifications/page/section3.pdf; (as of

7/29/2019).

58

Figure II-24 Cover Pressure Relief and Restraint (CPRR) System

An early driver for SCE to explore alternative vault cover 1

technologies was the Long Beach network incidents in 2015. During outages on two separate days, 2

SCE’s system experienced as many as eight vault events (i.e. reports of fire or smoke) and two vault 3

explosions, according to City of Long Beach 911 records. Since that time, there have been other 4

observed vault explosion events within the SCE system. SCE began tracking vault and manhole 5

explosion events in 2018, and in that year, 20 such incidents were observed. The severity of these events 6

will vary, and can include damage to the structure access, pavement, automobiles, walls, adjacent 7

buildings, landscaping, or sidewalks. 8

Following the Long Beach event, SCE initiated a pilot in 2016 to 9

install vault and manhole cover tethers. Tethers are steel cables that connect the cast iron cover to the 10

concrete structure below. Because of limitations associated with tethers, SCE then analyzed several 11

design variations and cover types from 2016 through 2018. During that period, SCE also participated in 12

Electric Power Research Institute (EPRI) supplemental programs where peer utilities participated in 13

developing and testing various covers and designs. Based on knowledge gained from these efforts, in 14

2018 SCE changed its standard for new vault and manhole cover installations to the current CPRR 15

standard. 16

SCE utilized the PRISM risk assessment framework to evaluate the 17

risks associated with explosions in underground structures leading to vault cover or manhole cover 18

projectile events.48 For event frequency, the PRISM analysis was based on equipment location, age, and 19

type, and the results from SCE’s predictive analytics models as applicable. For event consequences, the 20 48 See Chapter III for details on the PRISM framework.

59

PRISM analysis was based on population density, severity of pubic injuries, and property damage. The 1

results of the PRISM analysis provided SCE with an understanding of the relative risk prioritization of 2

all vault and manhole covers within its system. 3


In Chapter 11 of SCE’s 2018 RAMP report, the CPRR portion of the 5

Underground Structure Replacement program was identified as a mitigation to risks associated with 6

underground equipment failures. SCE focused this RAMP risk analysis on primary distribution 7

underground electrical equipment failures that could potentially lead to a vault or manhole explosion 8

event. To further characterize this risk and structure the risk analysis, SCE constructed a “risk bowtie,”49 9

as shown in Figure II-25. 10


The CPRR portion of the Underground Structure Replacement program 11

addresses the consequences of underground equipment failures leading to explosions in SCE vaults. The 12

program will reduce the serious injury and fatality consequences associated with Outcome O1 13

(Explosion in a Manhole or Vault) by allowing a more controlled release of energy during such 14

explosions. 15


A comparison of the CPRR forecast as shown in RAMP to the 17

CPRR forecast in this GRC is shown in Table II-19. The CPRR portion of the Underground Structure 18


60

Replacement program was modeled in RAMP as mitigation M1 “Cover Pressure Relief and Restraint 1

(CPRR) Program.” 2

Table II-19 CPRR Portion of Underground Structure Replacement Program Mitigation


The GRC forecast for the CPRR portion of the Underground 3

Structure Replacement program is consistent with the RAMP forecast in 2019 but lower in years 2020-4

2023. The RAMP row in the table above shows what SCE estimated for CPRR at the time of the RAMP 5

report, which included a near doubling of CPRR installations from 2019 to 2020. After publication of 6

the RAMP report, SCE decided that the GRC forecast installation rate for 2019 – approximately 350 7

CPRR installations – is a more appropriate rate of installations to maintain throughout this GRC cycle. 8

Therefore, SCE has reduced the 2020 to 2023 forecast for CPRR installations to be consistent with the 9

2019 forecast level. 10



Underground Structure Replacement program is shown in Table II-20 (structure replacements), Table II-13

21 (shoring) and Table II-22 (CPRR). 14

RAMP Risk RAMP

IDRAMP

Mitigation NameFiling Name 2019 2020 2021 2022 2023RAMP 8,000$ 15,000$ 15,000$ 15,000$ 15,000$ GRC 8,016$ 8,216$ 8,422$ 8,632$ 8,848$

Variance 16$ (6,784)$ (6,578)$ (6,368)$ (6,152)$


FailureM1

Cover Pressure Relief and Restraint (CPRR) Program

61

Table II-20 Underground Structure Replacement Program – Replacements50


Table II-21 Underground Structure Replacement Program – Shoring51


50 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 67-68 – Cost of Underground Structure Replacements.

51 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 69-70 – Cost of Capital Shoring.

YearHistorical/Forecast Units (Number of Underground Structure Replacements)

Forecast Unit Cost (Underground Structure


Recorded/Forecast Cost(Underground Structure


2014 302 $130,6442015 221 $102,0562016 199 $73,2482017 161 $48,8672018 116 $45,6512019 45 $369 $16,6242020 30 $384 $11,5122021 11 $396 $4,3552022 11 $407 $4,4812023 11 $419 $4,610

YearHistorical/Forecast Units (Number of Underground

Structures Shored)

Forecast Unit Cost (Underground Structure

Shoring: Nominal $000)

Recorded/Forecast Cost(Underground Structure

Shoring: Nominal $000)

201420152016 $2,7532017 67 $3,3642018 75 $5,3802019 57 $52 $2,9352020 38 $54 $2,0522021 14 $55 $7862022 13 $57 $7472023 13 $59 $768

62

Table II-22 Underground Structure Replacement Program – CPRR52


The forecast for the Underground Structure Replacement program was 1

developed through several steps. First, SCE established a forecast for structure replacements and shoring 2

based on historical rates and SCE’s expected rates of identification through this GRC cycle. SCE also 3

established a forecast for CPRR based on evaluation of the risks associated with explosions in vaults and 4

manholes, using the risk management methods described in Chapter III of this testimony to develop risk 5

scores. These efforts informed the Distribution IR unconstrained need reflected in Table II-3. 6


recorded data. Next, SCE significantly reduced the forecast for structure replacements and shoring in 8

response to resource constraints for SCE’s grid resiliency program. SCE also reduced the forecast for 9

CPRR to make the 2020 to 2023 forecast levels be in alignment with the 2019 forecast level. These 10

combined efforts resulted in the reduced forecasts shown in Table II-20 (replacements), Table II-21 11

(shoring), and Table II-22 (CPRR). 12

The reduced forecast for the Underground Structure Replacement program 13

is reasonable for three reasons. First, the forecast level is sized to allow SCE to execute its grid 14

resiliency priorities in light of anticipated resource constraints. Second, the forecast level is informed by 15

52 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 71-72 – Cost of Cover Pressure Relief Lid Replacements.


(Number of CPRR Systems Deployed)

Forecast Unit Cost (CPRR: Nominal $000)

Recorded/Forecast Cost(CPRR: Nominal $000)

20142015201620172018 255 $5,6992019 354 $23 $8,0152020 349 $24 $8,2082021 347 $24 $8,4202022 346 $25 $8,6392023 344 $26 $8,836

63

a risk-ranking approach for structure replacements. Third, the forecast level is informed by asset-level 1

PRISM risk analysis for CPRR. 2


The Underground Structure Replacement program forecast in this 4

GRC is sized to allow SCE to execute its grid resiliency priorities considering anticipated resource 5

constraints. The 2019-2023 Underground Structure Replacement program forecast for structure 6

replacements and shoring is a significant reduction from prior GRC forecast levels and from the level of 7

unconstrained need. This reduction is reasonable in the near-term because it is based on the importance 8

of mitigating wildfire risks.53 9

(b) Structure Replacement Risk-Ranking 10

The need for underground structure replacements is based on 11

SCE’s Underground Detailed Inspections (UDI) process, inspections by certified concrete inspectors, 12

and review by licensed civil engineers. After each structure is assigned a grade and a remediation code, 13

structures receiving a grade of “F” (i.e., at risk of failing) and remediation code of “1” (i.e., replacement 14

needed) are further evaluated through a relative risk-ranking process. This process prioritizes structure 15

replacements based on various factors including traffic rate, population proximity, and potential hazard 16

from falling concrete.54 17

Through these efforts, SCE can identify structures that need 18

replacement and prioritize such replacements in terms of relative risk. This is important because SCE is 19

presently identifying structures needing replacement at a rate of 135 per year, but forecasting 20

replacements of only 22 structures per year through 2023. The structure replacements identified by SCE 21

but not able to be executed under this forecast will be deferred to later years. 22

(c) PRISM Risk Analysis for CPRR 23

The forecast rate of installations of CPRR is reasonable in that it is 24

in alignment with SCE’s underlying PRISM analysis. This analysis has provided SCE a profile view of 25

the present risk across all underground vault and manhole covers in the system, and has helped validate 26

SCE’s current strategy for mitigating risks by targeted CPRR installations. Through a combination of 27


54 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 73-76 – Underground Structures Risk Ranking Process.

64

PRISM risk scoring and SCE’s internal challenge session process, SCE’s forecast will bring 1,740 of the 1

riskiest structures in the SCE system up to the current CPRR standard in years 2019 through 2023. 2

2. Overhead Programs 3

SCE’s overhead distribution system includes overhead conductor typically installed in 4

between distribution poles, as well as a variety of electrical components installed on distribution poles, 5

such as overhead switches and transformers. SCE’s Overhead Conductor Program (OCP) is the 6

Distribution IR activity focused entirely on SCE’s overhead distribution system. 7

a) Overhead Conductor Program 8


Table II-23 provides both the recorded (2014-2018) cost and the forecast 10

(2019-2023) for the Overhead Conductor Program. 11

65

Table II-23 Overhead Conductor Program55

CET-PD-IR-OC Recorded (2014 -2018)/Forecast (2019-2023)



The Overhead Conductor Program (OCP) was introduced in SCE’s 2018 2

GRC to address public safety risks associated with overhead conductor. Every year, SCE experiences 3

over 1,000 distribution conductor wire-down events within its territory. To mitigate these risks, SCE 4

replaces small conductor and installs protective devices through the OCP. This helps limit the amount of 5

damage that conductor may experience during fault conditions and lessens the probability of overhead 6

conductor failure. 7

There are two types of OCP projects, proactive and reactive. Proactive 8

OCP projects are not initiated by any specific wire-down event, but are scoped on an annual scoping 9

cycle and prioritized based on the amount of risk each project can mitigate and the cost to mitigate those 10

55 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 77-78 – Capital Detail by WBS Element for Overhead Conductor

Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $60,654 $97,330 $138,714 $181,503 $100,063 $34,992 $70,939 $83,134 $92,891

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

$200,000

Forecast

66

risks. This allows for the most risk-efficient work to be completed first. Reactive OCP projects are 1

initiated after a specific wire-down event occurs. In reactive OCP projects, the immediate priority is 2

restoration of customers impacted by the wire-down event. After restoration, a project is initiated to 3

replace and protect the damaged conductor from the wire-down event. Reactive projects are typically 4

smaller than proactive OCP projects, and the smallest of these reactive projects are constructed on an 5

accelerated basis. 6

(a) Short Circuit Duty and Small Wire 7

The concept of Short Circuit Duty (SCD) is essential to 8

understanding the need for OCP. SCD is an indication of the strength of an electrical system, typically 9

measured by the fault current (in amps) that the system can supply at any given location. For older 10

overhead wire installations, high SCD can increase the probability of conductor damage during fault 11

conditions. This is a particular problem for “small wire” installations where the wire was sized based on 12

the design standards applicable at the time of construction but is now undersized relative to current 13

standards. Today’s design standards specify a minimum wire size of 1/0 American Wire Gauge (AWG) 14

for new overhead construction in the SCE system, but many existing overhead installations have wire 15

sizes smaller than this standard. Small wire is less able than larger wire to withstand fault current levels 16

without damage. Small wire is also more likely to have been weakened during the life of the asset due to 17

the fault history experienced during the asset life. 18

The fundamental problem with small wire is that it is susceptible to 19

damage at typical SCD levels and fault clearing times. Table II-24 shows the relationship between SCD 20

levels and conductor susceptibility to damage, assuming typical distribution system protective relay 21

settings and no reclosing. These results are shown for three types of small wire – #6 copper, #4 22

Aluminum Conductor Steel-Reinforced (ACSR) and #4 copper – as well as SCE’s present standard 23

minimum wire size (1/0 ACSR). Under these conditions, #6 copper and #4 ACSR is susceptible to 24

damage at all SCD levels, and #4 copper is susceptible to damage at SCD levels above 2,000 amps. In 25

contrast, 1/0 ACSR is able to withstand SCD levels up to 8,000 amps without damage. 26

67

Table II-24 Conductor Susceptibility to Damage at Various Short Circuit Duty Levels

As of year-end 2018, SCE had approximately 18,000 circuit miles 1

of small wire throughout the service territory. This accounts for approximately half of all of SCE’s 2

overhead primary conductor. The goal of OCP is to mitigate the risks associated with wire-down events 3

by prioritizing the replacement of high-risk small wire in the SCE distribution system. 4


PRISM, to evaluate the risks associated with wire-down events.56 For wire-down event frequency, the 6

PRISM analysis was based on historical wire-down events and SCE’s predictive analytics model for 7

overhead conductor. For event consequences, the PRISM analysis was based on data sets such as 8

population density, outage durations, and other types of historical data.57 The results of PRISM analysis 9

provided SCE with an understanding of the risks associated with all overhead conductor within its 10

distribution system. SCE prioritizes its proactive OCP work based on the results of this PRISM analysis. 11

56 See Chapter III for details on the PRISM framework. Note that in addition to wire-down events, the OCP risk

assessment also evaluated risks associated with intact conductor failure events and human contact with intact conductor events.

57 Wildfire consequence assumptions were based on historical events from 2007 to 2016. Following wildfire events in 2017, SCE developed wildfire-specific risk assessments. See SCE 01 Vol. 02 and SCE-04 Vol. 05 for additional detail.

68

(b) Other System Needs Addressed by OCP 1

OCP also helps meet other system needs as well. For example, it 2

helps address problems associated with overhead splices. As conductor spans have failed over time or 3

needed to be cut as part of planned work, prior practice has been to use compression or non-compression 4

splices to reconnect existing conductor. This reduced outage times for affected customers, but has led to 5

conditions where some spans have excessive numbers of splices, each of which are a possible failure 6

point. Further, it also has led to situations where older overhead conductor, subject to a long history of 7

operational stresses, is still left installed and operating in the system. 8

As SCE has learned more about risks associated with splices, 9

SCE’s standards and practices regarding splices have changed. Non-compression splices are no longer 10

used for new installations due to their higher frequency of failure, and reconductoring through OCP 11

removes non-compression splices. Spans with large numbers of splices (regardless of type) have 12

multiple weak points that indicate higher probability of failure, and reconductoring though OCP 13

removes such splices and replaces such spans. 14

OCP also helps improve system protection. In addition to 15

reconductoring, OCP installs protective devices such as branch line fuses. Such fuses provide reliability 16

benefit for the system and protection benefit for overhead conductor by clearing faults faster than 17

upstream protective devices such as circuit breakers or automatic reclosers. 18


(a) Contact with Energized Equipment – RAMP Chapter 5 20

In Chapter 5 of SCE’s 2018 RAMP report, the OCP program was 21

identified as a control to risks associated with contact with energized overhead wire. To further 22

characterize this risk and structure the risk analysis, SCE constructed two different “risk bowties,” as 23

shown in Figure II-26. 24

69

Figure II-26 RAMP Contact With Energized Risk Bowtie

The OCP program with bare conductor (C1) mitigates risks 1

associated with wire down events by reducing the frequency of driver D1 (Equipment Caused). This is 2

because OCP replaces small, spliced, or damaged conductor with larger, more resilient conductor. OCP 3

will also reduce the frequency of wire-down events associated with driver D2 (Equipment/Facility 4

Contact) by creating a more resilient system that will be less susceptible to damage as a result of such 5

external faults. 6

The OCP program with targeted covered conductor (C1a) also 7

mitigates risks associated with wire-down events by reducing driver frequency. In RAMP, SCE 8

anticipated that there would be instances in OCP where covered conductor would be an appropriate 9

design alternative to bare conductor – for example, an OCP project scoped on a circuit with a high 10

contact from object (CFO) fault history. The OCP program with targeted covered conductor would also 11

reduce the driver frequency of drivers D1 and D2. However, OCP using targeted covered conductor 12

would be more effective in reducing driver D2 than OCP using bare conductor, because covered 13

conductor is designed to reduce the frequency of CFO faults. 14

The OCP program with targeted covered conductor (C1a) would 15

also have an impact on the safety consequences associated with outcome O1 (energized wire down). 16

This is because contact with covered conductor is less likely to result in serious injury or fatality than 17

contact with bare conductor in a wire-down event. 18

70

(b) Wildfire – RAMP Chapter 10 1

While OCP was not designed to directly address wildfire risks, the 2

RAMP analysis accounted for the wildfire risk reduction benefit that OCP will provide when deployed 3

in SCE’s High Fire Risk Areas (HFRA). In Chapter 10 of SCE’s 2018 RAMP report, the OCP program 4

was identified as a control to risks associated with wildfire. The risk statement in Chapter 10 of RAMP 5

includes the risks of ignition associated with SCE’s HFRA. To further characterize this risk and 6

structure the risk analysis, SCE constructed a “risk bowtie,”58 as shown in Figure II-27 7

Figure II-27 RAMP Wildfire Risk Bowtie

In RAMP Chapter 10, OCP was modeled as control C1 with the 8

anticipation that OCP would involve some projects constructed in HFRA, and that such projects would 9

be constructed with bare conductor in years 2018-2020 and covered conductor in years 2021-2023. C1 10

was modeled to impact driver D1 in years 2021-2023 because covered conductor would reduce the 11

frequency of CFO faults. C1 was modeled to impact driver D2 in years 2018-2023 because 12

reconductoring small-wire to a larger size will reduce the frequency of equipment-related faults. 13

(c) Reconciliation Between RAMP and GRC 14

A comparison of the OCP forecast as shown in RAMP versus the 15

forecast in this GRC is shown in Table II-25. OCP was modeled as a combination of C1 and C1a in the 16


71

RAMP Contact with Energized Equipment chapter. Note that OCP was also modeled in the RAMP 1

Wildfire chapter as control C1, but this only included a subset of OCP work for HFRA areas. Therefore, 2

the differences between OCP in the RAMP Wildfire chapter and OCP in this GRC forecast are not 3

shown. 4

Table II-25 Contact With Energized Risk Control: Overhead Conductor Program


The GRC forecast for OCP is lower than the RAMP forecast. The 5

RAMP forecast, developed in 2018, represented SCE’s plan for OCP to mitigate risks associated with 6

wire-down events, absent the additional resource constraints identified for the wildfire mitigations after 7

the RAMP report date. SCE has reduced the GRC forecast in OCP from the RAMP forecast levels to 8

help ensure adequate resources are available to address wildfire risks and the need for grid resiliency 9

activities during this GRC cycle. 10


SCE’s recorded costs (2014-2018) and forecast (2019-2023) for OCP are 12

shown in Table II-26. 13

RAMP Risk RAMP

ID RAMP Control NameFiling Name 2019 2020 2021 2022 2023

RAMP 139,000$ 127,926$ 113,840$ 110,534$ 119,427$ GRC 100,063$ 34,992$ 70,939$ 83,134$ 92,891$

Variance (38,937)$ (92,934)$ (42,900)$ (27,400)$ (26,535)$

Contact with Energized Equipment

Overhead Conductor Program (OCP) and Covered Conductor

C1 / C1A

72

Table II-26 Overhead Conductor Program

Recorded (2014-2018)/Forecast (2019-2023)59 (Nominal $000)

In 2018, SCE evaluated the risks associated with OCP, using the risk 1

management methods described in Chapter III of this testimony to develop risk scores. That scoring was 2

then validated through internal challenge sessions and informed the Distribution IR unconstrained need 3

reflected in Table II-3. This unconstrained need was modeled in RAMP, and the details for OCP are 4

shown in the RAMP row of Table II-25. 5


recorded data. SCE also reduced the OCP forecast in response to resource constraints for SCE’s grid 7

resiliency program.60 The reduced forecast shown in Table II-29 reflects a total of approximately 2,000 8

conductor miles in 2019-2023. 9

The reduced forecast for OCP is reasonable for three reasons. First, the 10

forecast level appropriately accounts for SCE’s grid resiliency priorities and resulting resource 11

constraints. Second, the forecast level is reasonable in that it addresses contact with energized equipment 12

risks which were identified as one of SCE’s biggest safety risks in RAMP. Third, the forecast level is 13

reasonable in that it was informed by a process based on asset-specific risk scoring. 14

59 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 79-80 – Cost of Overhead Conductor Rebuilds.


YearHistorical/Forecast Units (OCP: Conductor-Miles)

Forecast Unit Cost (OCP: Nominal $000)

Recorded/Forecast Cost(OCP: Nominal $000)

20142015 $60,6542016 526 $97,3302017 627 $138,7142018 780 $181,5032019 556 $180 $100,0632020 187 $187 $34,9922021 367 $193 $70,9392022 418 $199 $83,1342023 454 $205 $92,891

73


The OCP forecast in this GRC is sized to account for SCE’s grid 2

resiliency priorities and the resulting resource constraints. The 2019-2023 OCP forecast is a significant 3

reduction from prior GRC authorized levels and from the level of unconstrained need. This reduction is 4

reasonable in the near-term because it is based on the importance of mitigating wildfire risks.61 5

(b) Safety Risks Addressed by OCP 6

The RAMP results showed that the contact with energized 7

equipment risk score was the highest of all nine baseline risk scores on a mean basis.62 The OCP 8

forecast level addresses contact with energized equipment risks, one of SCE’s biggest safety risks. 9

(c) Predictive Analytics Models and PRISM Risk Analysis 10

The OCP forecast was informed by a process based on asset-11

specific risk scoring, allowing SCE to target specific projects from 2019-2023 to maximize the risk 12

reduction. This is one of the central features of PRISM analysis, which is designed to assess risks in the 13

electric system on a granular basis. This forecast is also informed by SCE’s new predictive analytics 14

model for overhead conductor, which uses multiple data sets that leverage the predictive value of 15

multiple variables in modeling failure probabilities. This is a significant improvement over previous 16

GRC cycles, because prior to this SCE did not have any statistical models for overhead conductor 17

performance such as Weibull curves. 18

3. Overhead and Underground Programs 19

This group of Distribution IR activities is focused on assets that are typically found in 20

both overhead and underground installations, such as capacitor banks, automatic reclosers, 4 kV 21

infrastructure, and PCB transformers. 22

a) Capacitor Bank Replacement Program 23



(2019-2023) for the Capacitor Bank Replacement program. 26


62 See SCE’s 2018 RAMP Report, Figure II-3, pp. 1-33.

74

Table II-27 Capacitor Bank Replacement Program63

CET-PD-IR-CB Recorded (2014 -2018)/Forecast (2019-2023)



The Capacitor Bank Replacement program replaces or removes failed and 2

obsolete distribution capacitor banks and their associated capacitor switches. Each capacitor bank is 3

composed of three capacitor units, fuses, a rack, and mounting hardware. For switched capacitor banks, 4

capacitor switches (either two or three) and a capacitor control are also included. Capacitor banks are 5

identified for replacement through either cyclic or ad hoc field inspections. 6

There are two types of capacitor banks on our system, switched and fixed. 7

Switched capacitor banks turn on and off to accommodate changes in customer load. Fixed capacitor 8

banks do not switch on and off and are continuously providing reactive power to our system. There are 9

13,679 capacitor banks in SCE’s distribution system as of year-end 2018. Of these, about 80 percent are 10

63 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 81-82 – Capital Detail by WBS Element for Capacitor Bank


2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $7,814 $8,684 $7,765 $6,920 $19,386 $10,318 $5,302 $2,716 $3,793 $4,641

$5,000

$10,000

$15,000

$20,000

$25,000

Forecast

75

installed in the overhead system. The other 20 percent are installed in the underground system. A graph 1

showing the age distribution of all existing capacitor banks is provided in Table II-28. SCE’s inventory 2

of distribution capacitor banks has a large number of relatively young capacitor banks, and small 3

number of older capacitor banks. This is due to efforts by SCE in recent years to replace older and 4

obsolete capacitor banks with new ones. 5

Table II-28 Age Distribution of Distribution Capacitor Banks

Distribution capacitor banks supply reactive power to the distribution 6

system to maintain an acceptable power factor. In order to maintain an acceptable power factor, 7

engineers must plan for sufficient reactive power supply to meet system reactive power needs. 8

Replacement of non-functioning capacitor banks helps SCE meet the overall reactive power need of the 9

system. Distribution capacitor banks also provide voltage support as a secondary benefit, helping SCE 10

meet nominal service voltage level requirements per SCE’s tariff Rule 2.64 11

The expected average time to wear-out of an overhead capacitor bank is 12

assumed to be about 30 years. As of year-end 2018, approximately 10% of the population are older than 13

64 https://www1.sce.com/NR/sc3/tm2/pdf/Rule2.pdf; (as of 7/29/2019).

0

100

200

300

400

500

600

700

800

900

1,000

1960

1963

1966

1969

1972

1975

1978

1981

1984

1987

1990

1993

1996

1999

2002

2005

2008

2011

2014

2017

Number of Cap

acitorBan

ks

Year of Installation

76

30 years and the average age of our capacitors combined population is roughly 12 years. Based on a 1

combined population of 13,679 capacitor banks with a mean time to wear-out of 30 years, the long-term-2

steady-state replacement rate would be about 450 replacements per year. 3

Once every five years, each capacitor bank in our system is inspected for 4

proper operation, corrosion, leaking oil, and loose connections. Capacitor bank issues may also be 5

identified on an ad hoc inspection basis as a result of patrol and nearby work. Capacitor banks requiring 6

replacement or repair are recorded and prioritized for follow-up work. Problems with newer capacitor 7

banks usually result in repairs. Problems with older banks, where parts are no longer available or where 8

repairs cannot be made effectively, often result in replacement. 9



Capacitor Bank Replacement program are shown in Table II-29. 12

Table II-29 Capacitor Bank Replacement Program

Recorded (2014-2018)/Forecast (2019-2023)65 (Nominal $000)


recorded data. The unconstrained need for the Capacitor Bank Replacement program is based on the 14

five-year average historical replacement rates. SCE has reduced the Capacitor Bank Replacement 15

program forecast from the unconstrained need in response to resource constraints for SCE’s grid 16

65 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 83-84 – Cost of Capacitor Bank Replacements.


(Number of Capacitor Bank Replacements)

Forecast Unit Cost (Capacitor Bank


Recorded/Forecast Cost(Capacitor Bank


2014 309 $7,8142015 257 $8,6842016 158 $7,7652017 247 $6,9202018 571 $19,3862019 285 $36 $10,3182020 141 $38 $5,3022021 70 $39 $2,7162022 95 $40 $3,7932023 113 $41 $4,641

77

resiliency program.66 The reduced forecast shown in Table II-29 reflects a total of 704 capacitor bank 1

replacements in 2019-2023 and is approximately half of SCE’s unconstrained need. 2

The reduced forecast shown above is reasonable for two reasons. First, the 3

forecast appropriately accounts for SCE’s grid resiliency priorities and resulting resource constraints. 4

Second, the short-term risks associated with this forecast reduction are manageable by SCE as 5

distribution engineers monitor system performance and assuming that future capacitor bank replacement 6

rates are adjusted to compensate for near-term deferred replacements. Each of these reasons is discussed 7

below. 8


The Capacitor Bank Replacement program forecast in this GRC is 10

sized to account for SCE’s grid resiliency priorities and the resulting resource constraints. The 2019-11

2023 Capacitor Bank Replacement program forecast is a significant reduction from prior GRC 12

authorized levels and from the level of unconstrained need. This reduction is reasonable in the near-term 13

because it is based on the importance of mitigating wildfire risks.67 14

(b) Short Term Risks are Manageable with Engineering Review 15

In-service failures of distribution capacitor banks typically pose no 16

significant safety risks, rarely result in customer interruptions, and usually pose little threat to system 17

reliability if replaced in a timely manner after they fail. This is why SCE’s Capacitor Bank Replacement 18

program is not a preemptive replacement program but is based on the identification of failed capacitor 19

banks through inspections. 20

As part of SCE’s reactive power planning efforts, SCE distribution 21

engineers review the list of failed capacitor banks and then define the appropriate scope for capacitor 22

bank replacement projects in that scoping year. The failed capacitor banks that are not replaced due to 23

the reduced forecast will, by necessity, remain in the system in a failed state longer than would 24

otherwise occur. As part of the planning process, SCE engineers will confirm that deferred capacitor 25

banks (individually or in aggregate) do not compromise overall system voltage stability in the near term. 26

As long as future capacitor bank replacement forecasts are increased to compensate for the replacement 27



78

deferrals that will result from the present forecast, the near-term risks associated with such deferrals will 1

be localized in nature and generally acceptable. 2

b) Distribution Automatic Recloser Replacement Program 3



(2019-2023) for the Distribution Automatic Recloser Replacement program. 6

Table II-30 Distribution Automatic Recloser Replacement Program68

CET-PD-IR-AR Recorded (2014-2018)/Forecast (2019-2023)



Automatic reclosers (ARs) are used in distribution circuits to interrupt the 8

supply of electricity to that portion of the circuit downstream of its location. They act much like circuit 9

breakers but are installed on a distribution circuit instead of in a substation. ARs improve the safety and 10

68 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 85-86 – Capital Detail by WBS Element for Distribution

Automatic Recloser Replacement Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $1,523 $2,488 $2,136 $2,393 $1,248 $2,435 $2,448 $2,610 $2,686 $2,763

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Forecast

79

reliability of SCE’s system. On long distribution circuits, the amount of impedance on the line makes it 1

more difficult to detect faults that are far from the substation. ARs detect those faults and open to de-2

energize the downstream portion of the line. Since ARs are designed to open before the substation 3

circuit breaker, they isolate faults to a smaller portion of the line, thus reducing the number of customers 4

that experience an outage. 5

The Distribution Automatic Recloser Replacement program replaces 6

automatic reclosers identified as being obsolete and/or unreliable. SCE has been replacing ARs at a rate 7

of approximately 30 per year in recent years. 8

As of year-end 2018, there are approximately 1,700 ARs in SCE’s 9

distribution system. Of these, about 1,650 are on the overhead system, with the rest on the underground 10

system. A graph showing the age distribution of all existing ARs is provided in Figure II-28. 11

Figure II-28 Age Distribution of Distribution Automatic Reclosers

The design of ARs has undergone extensive changes since SCE first began 12

installing them. The earliest ARs were oil-filled, whereas ARs installed since 2002 have a vacuum 13

switch and electronic control arrangement. Many of the oldest ARs are no longer manufactured and 14

cannot be repaired or are of an obsolete design, which cannot be repaired cost-effectively. 15

What is evident from the age distribution shown in Figure II-28 is that 16

SCE’s inventory has a large number of relatively young ARs, and very small number of older ARs. This 17

80

is due to efforts by SCE in recent years to replace older and obsolete ARs with new ARs. SCE has been 1

replacing ARs at an approximate rate of 30 per year in recent years, in an effort to remove all old oil-2

filled ARs from inventory and replace them with new vacuum ARs. As of year-end 2018, SCE has 3

approximately 155 ARs remaining in inventory of vintage 2002 or earlier. 4



Distribution Automatic Recloser Replacement program are shown Table II-31. 7

Table II-31 Distribution Automatic Recloser Replacement Program69


The capital expenditure forecast is based on historical replacement rates 8

and SCE’s plans to remove all older, oil-filled ARs from the system and replace them with newer 9

vacuum ARs. In 2019, SCE updated unit costs based on analysis of available 2014-2018 recorded data. 10

At this time, SCE has identified a total of 155 ARs that are remaining in the system of vintage 2002 or 11

earlier. This forecast will complete the efforts that SCE has undertaken in recent years to remove older 12

oil-filled ARs from the system, and therefore complete the Distribution Automatic Recloser 13

Replacement program by 2023. 14

69 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 87-88 – Cost of Automatic Recloser Replacements.

YearHistorical/Forecast Units (Number of Automatic Recloser Replacements)

Forecast Unit Cost (Automatic Recloser


Recorded/Forecast Cost(Automatic Recloser


2014 29 $1,5232015 34 $2,4882016 24 $2,1362017 33 $2,3932018 29 $1,2482019 31 $79 $2,4352020 30 $82 $2,4482021 31 $84 $2,6102022 31 $87 $2,6862023 31 $89 $2,763

81

c) 4 kV Cutover Program and 4 kV Substation Elimination Program 1

The 4 kV Cutover program involves the conversion, or cutover, of 4 kV 2

distribution circuits to a higher voltage class. The 4 kV Substation Elimination program involves the 3

physical removal of 4 kV substations. Together, both programs address safety and reliability risks and 4

other problems associated with obsolete 4 kV distribution infrastructure. 5



(2019-2023) for the 4kV Substation Elimination program. 8

Table II-32 4kV Cutover Program70

CET-ET-IR-4C Recorded (2014-2018)/Forecast (2019-2023)



(2019-2023) for the 4kV Substation Elimination program. 10

70 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 89-90 – Capital Detail by WBS Element for 4kV Cutover

Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $53,403 $79,916 $107,452 $107,349 $116,586 $48,326 $29,981 $9,982 $9,985 $10,044

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

Forecast

82

Table II-33 4kV Substation Elimination71

CET-ET-IR-SR Recorded (2014–2018)/Forecast (2019-2023)



The majority of SCE’s distribution circuits operate at primary voltages of 2

12 kV, 16 kV, or 33 kV. However, about 19 percent of distribution circuits and 27 percent of 3

distribution substations operate at primary voltages of 4 kV.72 These 4 kV circuits and substations were 4

typically designed and installed between 1940 and 1960, making up some of the oldest parts of SCE’s 5

system. Many of SCE’s 4 kV substations incorporate antiquated and obsolete equipment and designs. 6

Much of the equipment and replacement parts in service today are no longer manufactured. Replacement 7

parts are difficult and expensive to procure as much of our in-service equipment was installed between 8

1940 and 1960. Aged components have higher probability of failure, with the potential to adversely 9

impact service reliability and power quality. The 4 kV Cutover Program and the 4 kV Substation 10

71 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 91-92 – Capital Detail by WBS Element for 4kV Substation

Elimination.

72 For purposes of this program, SCE includes 2.4 kV, 4.0 kV and 4.8 kV in this category.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $1,731 $1,757 $2,643 $3,893 $5,521 $6,054 $5,643 $3,288 $2,071 $2,131

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

Forecast

83

Elimination program together address the problems of aging and obsolete 4 kV infrastructure by 1

removal of this infrastructure. 2

The removal of aging and obsolete 4 kV infrastructure is performed in two 3

phases. The first phase is performed by the 4 kV Cutover program, which focuses on 4 kV distribution 4

circuit infrastructure outside of a substation physical boundary. Through the 4 kV Cutover program, 5

SCE converts 4 kV circuit infrastructure to a higher voltage class and removes remaining 4 kV circuit 6

infrastructure that is no longer needed. Figure II-29 illustrates a distribution circuit before and after a 4 7

kV cutover project. 8

Figure II-29 Illustration of 4 kV Distribution Circuit Cutover

In this figure, SCE makes use of an adjacent circuit operating at a higher 9

voltage circuit to serve customers previously fed from an underbuilt 4 kV circuit. During this cutover, 10

the 4 kV transformer is replaced with a higher voltage transformer and connected to the higher voltage 11

circuit, and then the underbuilt 4 kV conductor is physically removed. The cutover also involves 12

removing existing open wire secondaries and replacing them with covered aluminum triplex, SCE’s 13

current standard for secondary wire. Once the cutover is completed, the customer is now served from a 14

higher voltage circuit that is brought up to existing standards. 15

The second phase involves removing substation electrical equipment and 16

performing other work as necessary, such as soil remediation and the removal of associated buildings. 17

84

This phase depends on the prior completion of all distribution circuit cutover work. Figure II-30 shows a 1

simplified diagram of a 4 kV system before and after the substation elimination. In this figure, the first 2

phase is shown as the removal of 4 kV distribution circuit infrastructure outside of the substation 3

property, and the second phase is shown as the removal of 4 kV substation equipment (i.e., transformer 4

bank, circuit breakers, and 4 kV bus) within the substation property. 5

Figure II-30 Illustration of 4kV Substation Elimination

SCE utilized the T&D risk assessment for framework, referred to as 6

PRISM, to evaluate risks events associated with the 4 kV system.73 The 4 kV substation PRISM analysis 7

is a result of aggregated risk models from distribution overhead conductor, substation transformer banks, 8

and substation circuit breakers. The PRISM analysis provides SCE with an understanding of the risks 9

associated with 4 kV infrastructure and helps inform prioritization of 4kV projects. Along with PRISM, 10


85

a variety of other interrelated factors also drive the need for cutovers or help inform the prioritization, 1

including: (1) maintenance and expandability constraints; (2) operational constraints; (3) voltage quality; 2

and (4) customer choice benefits. Each of these are discussed in greater detail below. 3

(a) Maintenance and Expandability Constraints 4

SCE’s standard 12 kV and 16 kV substations are built with enough 5

physical space to provide inherent flexibility and expandability. These designs allow for circuits to be 6

transferred to another bus when maintenance is required. This helps reduce or eliminate outages during 7

both planned and emergent situations related to equipment failures or maintenance within 12 kV and 16 8

kV substations. The standard substation footprint also allows SCE to install new equipment when 9

necessary to support increased load. 10

In contrast, typical 4 kV substations are on small plots of land in 11

space-constrained metropolitan areas. This lack of space can lead to an increased risk to worker safety 12

and difficulty upgrading equipment. Bedford 4 kV substation in the city of Beverly Hills, for example, is 13

comprised of non-standard metal-clad switchgear, installed in the basement of a building on a congested 14

street, and between rows of commercial buildings, eliminating the possibility of any future expansion 15

under current standards. The upgrade of any equipment in the Bedford 4 kV substation non-standard 16

switchgear would require a complete substation rebuild. However, this is not possible due to insufficient 17

space.74 These situations are prevalent among 4 kV substations, especially in space-constrained 18

metropolitan areas, and because of these limitations, lead to the need to eliminate the substations. 19

Based on the design and present condition of our 4 kV substations, 20

SCE is experiencing challenges when a 4 kV substation capacity needs to be expanded. SCE is also 21

experiencing challenges associated with avoiding prolonged outages while performing maintenance on 4 22

kV substation equipment. As a result of the population growth and associated load increases since these 23

4 kV substations were built, the configuration of many of these substations no longer provides the 24

flexibility to allow for the reliability expected by our customers 25

Many existing 4 kV substations do not meet current design 26

standards that require specific substation dimensions, configurations, and equipment. The need to 27

upgrade or replace a piece of 4 kV substation equipment like a transformer often requires significant 28

additional work to be done to rebuild the substation to current design standards. When all of this 29

74 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 93-96 – Substation Elimination Project Descriptions.

86

additional work to replace existing 4 kV equipment is accounted for, the cutover of 4 kV circuits and the 1

elimination of 4 kV substations – as achieved by SCE’s 4 kV Cutover program and 4 kV Substation 2

Elimination program – is a more cost-effective long-term solution. 3

(b) Operational Constraints 4

Roughly 20 percent of SCE’s 4 kV substations are completely 5

“islanded,” meaning there is no way to restore power to customers by transferring their load to an 6

adjacent circuit during planned or unplanned outages. These constraints come from a lack of available 7

physical connections to other 4 kV circuits and substations. Without transferability, often referred to by 8

SCE as “operational flexibility,” both planned and emergent maintenance work can cause prolonged 9

outages and negatively impact system reliability. 10

Even 4 kV substations that are not completely “islanded” have 11

operational constraints related to 4 kV circuit loading and load transfers. Circuits operating at lower 12

voltages experience higher current flow than circuits operating at higher voltages when serving identical 13

levels of connected load. Therefore, 4 kV circuits often cannot accommodate load transfers from 14

adjacent circuits. These circuit flow constraints also make it more difficult to install fuses on 4 kV 15

circuits than on higher voltage circuits. To illustrate this concept, Figure II-30 shows the distribution 16

circuit with fuses after the cutover but without fuses before the cutover. 17

SCE’s 4 kV circuits often have more circuit imbalance issues than 18

circuits at higher voltage levels due to single-phase load configurations. Single-phase load is connected 19

to one phase and the neutral wire on 4-wire 4 kV systems. This configuration makes it inherently more 20

difficult to maintain balanced loading on all phases of the circuit. Imbalanced phase loading can cause 21

power quality problems and can also cause situations where the circuit ground relay might de-energize 22

the circuit unnecessarily. In contrast, single phase load on 12 kV or 16 kV circuits is typically connected 23

phase-to-phase which results in load sharing among the two phases of the circuit. This configuration 24

makes it inherently easier to maintain balanced loading on all phases of the circuit, and such circuits are 25

less prone to unnecessary tripping by ground relays. 26

87

(c) Voltage Quality 1

Requirements for voltage levels are based on CPUC Rule 2 2

Tariff.75 Voltage levels not meeting Rule 2 requirements can cause power quality concerns for 3

customers and can lead to the failure of voltage-sensitive equipment. 4

SCE’s 4 kV circuits are more likely to cause voltage quality issues 5

than circuits at higher voltage levels. This is again because lower voltage circuits experience higher 6

current flow than higher voltage circuits when serving identical levels of connected load. Because losses 7

are a function of current, higher current flow results in higher circuit losses and greater operational 8

challenges in regulating voltage. The PRISM risk assessment of 4 kV took into account the voltage 9

quality issues described here. 10

(d) Customer Choice Benefits 11

It is more difficult to connect Distributed Energy Resources 12

(DERs) or accommodate increased levels of electric vehicle charging on 4 kV circuits than on higher 13

voltage circuits without significant upgrades. As the 4 kV Cutover program and 4 kV Substation 14

Elimination program remove 4 kV infrastructure in favor of higher-voltage infrastructure, it becomes 15

easier for customers to implement DERs or install electric vehicle charging without increased costs or 16

delays. 17


SCE’s recorded costs (2014-2018) and forecast (2019-2023) for the 4 kV 19

Cutover and Substation Elimination programs are shown in Table II-34 and Table II-35. 20

75 https://www1.sce.com/NR/sc3/tm2/pdf/Rule2.pdf; (as of 7/29/2019).

88

Table II-34 4kV Cutover Program76


Table II-35 4kV Substation Elimination Program77


76 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 97-98 – Cost of Cutting Over a 4kV Circuit.

77 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 99-100 – Cost of Eliminating a 4kV Substation.


(Number of 4 kV Transformers Removed)

Forecast Unit Cost (4 kV Cutover

Transformers: Nominal $000)

Recorded/Forecast Cost(4 kV Cutover Transformers:

Nominal $000)

2014 254 $53,4032015 1,636 $79,9162016 1,853 $107,4522017 1,689 $107,3492018 1,845 $116,5862019 826 $59 $48,3262020 493 $61 $29,9812021 159 $63 $9,9822022 155 $65 $9,9852023 151 $66 $10,044


(Number of 4 kV Substations Eliminated)

Forecast Unit Cost (4 kV Substation

Elimination: Nominal $000)

Recorded/Forecast Cost(4 kV Substation

Elimination: Nominal $000)

2014 3 $1,7232015 5 $1,7252016 5 $2,3702017 7 $3,6282018 9 $5,0442019 12 $510 $6,0542020 11 $529 $5,6432021 6 $546 $3,2882022 4 $562 $2,0712023 4 $578 $2,131

89

The forecasts for the 4 kV Cutover program and the 4 kV Substation 1

Elimination program were developed through several steps. First, SCE evaluated the risks associated 2

with 4 kV infrastructure, using the risk management methods described in Chapter III of this testimony 3

to develop risk scores. That scoring was then validated through internal challenge sessions and informed 4

the Distribution IR unconstrained need reflected in Table II-3. 5


recorded data. Next, SCE significantly reduced the forecast for the 4 kV Cutover program in response to 7

resource constraints for SCE’s grid resiliency program.78 The forecasts shown in Table II-34, Table II-6 8

and Table II-35 reflects the cutover of 1,784 distribution circuit transformers in years 2019-2023. 9

The forecasts for the 4 kV Cutover and 4 kV Substation Elimination 10

programs are reasonable for two reasons. First, the forecast level appropriately accounts for SCE’s grid 11

resiliency priorities and resulting resource constraints. Second, the forecast level is reasonable in that it 12

was informed by a process based on asset-specific risk scoring. 13


The 4 kV Cutover program is sized to account for SCE’s grid 15

resiliency priorities and the resulting resource constraints. The 2019-2023 4 kV Cutover program is a 16

significant reduction from prior GRC authorized levels and from the level of unconstrained need. This 17

reduction is reasonable in the near-term because it is based on the importance of mitigating wildfire 18

risks.79 19

(b) PRISM Risk Analysis 20

The 4 kV Cutover program and 4 kV Substation Elimination 21

program forecasts were informed by a process based on asset-specific risk scoring, allowing SCE to 22

target specific projects from 2019-2023 to maximize the risk reduction. This is one of the central 23

features of PRISM analysis, which is designed to assess risks in the electric system on a granular basis. 24

d) PCB Transformer Removal Program 25



(2019-2023) for the PCB Transformer Removal program. 28



90

Table II-36 PCB Transformer Removal Program80

CET-PD-IR-PC Recorded (2014-2018)/Forecast (2019-2023)



SCE’s Polychlorinated Biphenyls (PCB) Transformer Removal Program 2

replaces distribution line transformers suspected of being contaminated with PCB oil greater than 50 3

parts per million (ppm). PCBs are chemicals that have dangerous effects on the environment and human 4

health. PCBs had been manufactured and used in many industrial applications such as transformers, 5

capacitors, light ballasts, cable insulation, paints, and plastics. Although no longer allowed to be 6

manufactured, products containing PCBs still exist and are in use. Transformers and oil-filled electrical 7

equipment filled with PCB oils with a concentration of greater than 50 ppm were banned from being 8

manufactured after 1979 by the Environmental Protection Agency (EPA), due to human health toxicity 9

and bioaccumulation in the environment. 10

80 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 101-102 – Capital Detail by WBS Element for PCB

Transformer Removal Program.

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Nominal $1,368 $1,325 $1,579 $1,479 $2,533 $1,813 $1,883 $1,943 $1,999 $2,057

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Forecast

91

Failure of electrical equipment containing the PCB oil could cause the 1

oil’s release. EPA has encouraged all utilities to remove transformers containing significant levels of 2

PCB. It is anticipated that the federal government will ultimately make the elimination of PCB-3

containing equipment a legal requirement. 4

(a) History of EPA Regulations Regarding PCBs 5

In the late 1970s, the United States Congress enacted the “Toxic 6

Substances Control Act” (TSCA), which required the EPA to write regulations banning the 7

manufacturing, processing, distribution in commerce, and use of PCBs. The EPA’s PCB regulations 8

subsequently written provide specific use authorizations81 which allow electric utilities to continue using 9

these PCB oil filled transformers and other electrical equipment for the remainder of their useful lives 10

subject to use conditions82 and disposal requirements.83 11

The EPA’s regulations governing the use of PCBs in electrical 12

equipment and other applications were first issued in the late 1970s. In 1998, EPA initiated rulemaking 13

to reassess the ongoing authorized use of PCBs to determine whether certain use authorizations should 14

be ended or phased out because they no longer can be justified under section 6(e) of TSCA, which 15

requires that the authorized use shall not present an unreasonable risk to public health and the 16

environment. 17

The first step in the reassessment led to the EPA publishing an 18

Advanced Notice of Proposed Rulemaking (ANPRM) in 2010. The EPA reviewed and considered all 19

comments received on the ANPRM in planning the rulemaking. The actions were to address the 20

following specific areas: (1) the use, distribution in commerce, marking and storage for reuse of liquid 21

PCBs in electric equipment; (2) improvements to the existing use authorization for natural gas pipelines; 22

and (3) and other regulatory fixes. The reassessment of use authorizations related to liquid PCBs in 23

equipment were to focus on large capacitors, transformers, and other electrical equipment. In addition, 24

revised testing, characterization, and reporting requirements of PCBs in natural gas pipeline systems 25

were to provide transparency to regulatory agencies and the public when PCB releases occurred. 26

81 Title 40 Code of Federal Regulations (CFR) Part 761.30.

82 Title 40 CFR Part 761.30(a)(1).

83 Title 40 CFR Part 761.60.

92

To date, the EPA has not provided an update on the decision for 1

mandated removals of in-use PCB containing equipment, nor the reassessment of the use authorization 2

for PCBs and its consideration of mandatory removal of all equipment containing PCB at levels greater 3

than 50 ppm. Therefore, the EPA regulations set in the 1970s are still applicable to SCE. 4

Even though the EPA has not formally updated these regulations, 5

they continue to signal a clear desire to eliminate the presence of PCBs. For example, in 2001 the United 6

States was a participant at the Stockholm Convention on Persistent Organic Pollutants, which sets non-7

binding goals for eliminating PCB use in electrical equipment by 2025. The EPA was a participant at 8

this convention. As another example, in February of 2014, EPA presented at the Small Business 9

Advocacy Review (SBAR) Panel meeting for rulemaking indicating their continued focus on developing 10

a regulatory timeline for the phase-out of PCB Transformers (>500 ppm) and PCB-Contaminated 11

Transformers (50 ppm – 500 ppm) and interim use conditions on known PCB Transformers and PCB-12

Contaminated Transformers. 13

(b) Challenges that SCE Faces Regarding PCBs 14

The most substantial challenge that electric utilities may face is the 15

adoption of new regulations by the EPA that would require analytical testing of in-service equipment to 16

determine if transformers or other oil filled equipment contain regulated levels of PCBs greater than 50 17

ppm. While the EPA does not require testing as a condition of use, the EPA has a very stringent set of 18

assumption standards84 when levels are unknown. Manufacturers of distribution transformers do not 19

recommend taking oil samples from in-service units due to safety concerns. PCB oil concentrations in 20

these distribution transformers should only be tested once they are out of service and removed from the 21

field. These tests help SCE determine the level of PCB oil concentration for proper disposal and 22

management. With a few exceptions, all distribution transformers owned by SCE manufactured prior to 23

July 2, 1979 are assumed to contain regulated levels of PCBs until sampled. However, SCE has 24

developed analytics to help assess and further identify suspect PCB transformers. 25

These existing EPA assumption standards pose significant 26

management and liability concerns for SCE and our customers. This is due primarily to the fact that the 27

EPA regulates spills and even minor releases from transformers containing PCBs greater than 50 ppm as 28


93

“improper disposal” of PCBs.85 Under EPA’s penalty policy, such improper disposal of PCBs can 1

equate to penalties/fines of up to $32,500 per day per incident. 2

PCB oil spills are regulated under TSCA86 and have specific and 3

rigorous cleanup, reporting, verification and disposal requirements. Strict reporting and clean up 4

requirements are also enforced at the state and local level. A transformer with PCB oil that has released 5

into the environment requires more cleanup and mitigation efforts than that of a transformer filled with 6

non-PCB oil. 7

(c) SCE Recent History Regarding PCBs 8

In 2018, SCE responded to 2,930 oil releases from transformers. 9

These oil releases were a result of triggering events ranging from car hit poles to catastrophic equipment 10

failures. Of that, only three of those oil releases from transformers were over 50 ppm for PCB oils. All 11

releases were managed and mitigated according to the EPA’s policy. When older transformers in SCE’s 12

system leak and a release of PCBs 50 ppm or greater occurs, SCE is out of compliance with the EPA’s 13

regulations regarding improper disposal of PCBs and may be subject to enforcement actions. Although 14

SCE has protocols in place for proper response and cleanup of PCB spills under the EPA’s PCB Spill 15

Cleanup Policy87 and performs well with due diligence, it is still virtually impossible to monitor the 16

hundreds of thousands of older distribution transformers remaining in our system for the presence of 17

minor oil leaks. 18


SCE’s recorded costs (2014-2018) and forecast (2019-2023) for the PCB 20

Transformer Removal program are shown Table II-37. 21


86 Title 40 CFR 761 Subpart G.

87 Title 40 CFR 761.125.

94

Table II-37 PCB Transformer Removal Program88


The PCB Transformer Removal program forecast is based on the five-year 1

average historical replacement rates. In 2019, SCE updated unit costs based on analysis of available 2

2014-2018 recorded data. SCE estimates that there are fewer than 2,500 distribution transformers in our 3

system that may contain over 50 ppm PCBs. This estimate is based on historical analytical tracking of 4

removed PCB transformers. The forecast removal rate puts SCE on track to remove all suspected PCB-5

contaminated transformers by 2025.89 6

SCE identifies likely PCB-contaminated transformers for replacement 7

using a predictive model based on manufacturer data captured during normal attrition.90 Under normal 8

conditions, transformers are identified with a unique serial number. Because serial numbers are assigned 9

sequentially during the manufacturing process, transformers whose serial numbers are numerically close 10

are likely to have been filled with the same transformer oil. Operating transformers whose serial 11

numbers are closest to those of removed transformers found to be contaminated are then targeted for 12

removal by the PCB Transformer Removal program. 13

88 Refer to WP SCE-02, Vol. 01, Pt. 01, pp. 103-104 – Cost of PCB Transformer Replacements.

89 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 105-106 – Completion Date of Removal of all PCB-Contaminated Transformers.

90 Refer to WP SCE-02, Vol. 01, Pt. 01 WP, pp. 107-108 – PCBRP Process.

Year

Historical/Forecast Units (Number of PCB-

Contaminated Transformers Replaced)

Forecast Unit Cost (PCB-Contaminated

Transformer Replacement: Nominal $000)

Recorded/Forecast Cost(PCB-Contaminated

Transformer Replacement: Nominal $000)

2014 276 $1,3682015 177 $1,3252016 232 $1,5792017 213 $1,4792018 291 $2,5332019 250 $73 $1,8132020 250 $75 $1,8832021 250 $78 $1,9432022 250 $80 $1,9992023 250 $82 $2,057

95

III. 1

T&D OPERATIONAL RISK MANAGEMENT PRACTICES 2

A. Introduction 3

Prioritized Risk-Informed Strategic Management (PRISM) is the name used to refer to the 4

Transmission and Distribution (T&D) risk assessment framework.91 As discussed in Exhibit SCE-01 5

Volume 02, SCE develops risk-informed decision-making frameworks that enable SCE Operating Units 6

to evaluate asset and operational risks in a manner consistent with Enterprise Risk Management (ERM) 7

principles. In 2014, SCE began piloting the PRISM framework within T&D to evaluate safety, 8

reliability, environmental, compliance, and financial risks associated with T&D assets. PRISM is based 9

on an event-based methodology that evaluates the potential negative outcomes that can result from a 10

particular event. PRISM risk assessments rely on empirical data and are supplemented by subject-matter 11

expertise. Risk assessments are completed across a variety of T&D activities and results are reviewed by 12

T&D staff before being used to inform operational and planning decisions. This chapter describes 13

assessment practices performed through the PRISM framework through May 2019. 14

B. Process and Governance 15

The process followed to complete PRISM risk assessments is consistent with the SCE Enterprise 16

Risk Management (ERM) framework. Risk assessment assumptions and results are reviewed through an 17

internal calibration process and documented in work papers. See Section III.E for an explanation of the 18

steps required to complete a PRISM risk assessment. 19

PRISM risk assessments are completed by cross-functional Asset Strategy Teams (ASTs) made 20

up of subject matter experts throughout T&D. There are currently four ASTs: Distribution, Substation, 21

Transmission, and Grid Planning. Risk assessment results are first reviewed within an AST for accuracy 22

and across ASTs for calibration of results. SCE refers to these reviews as challenge sessions. Risk 23

assessment results approved through the challenge sessions may be used to inform prioritization 24

decisions within an activity and trade-off decisions across activities. 25

C. Connection to RAMP 26

In SCE’s 2018 Risk Assessment and Mitigation Phase (RAMP) report, PRISM results were used 27

as an input for modeling of those activities that had complete PRISM risk assessments. PRISM output of 28

91 The PRISM framework was documented in the 2018 SCE GRC, in SCE-02 Vol. 01, Operational Overview

and Risk-Informed Decision-Making.

96

asset-specific risk scores informed RAMP input assumptions regarding effectiveness of controls and 1

mitigations. Incorporating PRISM results in RAMP modeling allowed SCE to account for the benefit of 2

targeting the highest-risk assets first through “targeting benefits” for controls and mitigations. These 3

targeting benefits approximated the mitigation effectiveness expected by targeting scope on the highest-4

risk assets as opposed to a random selection of assets for a given activity. For example, if PRISM results 5

estimated that 50% of the potential risk-reduction benefits for an activity could be achieved by replacing 6

10% of the assets in an asset class, a targeting multiplier of 5x would be used in the RAMP analysis. As 7

T&D continues to complete risk assessments, PRISM results will continue to be used as inputs in future 8

iterations of RAMP models and the modeling of mitigation effectiveness. 9

D. Applications 10

PRISM results are used to inform prioritization of work within an activity, such as helping to 11

determine which specific equipment in an asset group to replace first or which project to prioritize over 12

others. Current PRISM analysis is equipment- or project-specific and is detailed enough to be used by 13

project scoping organizations to inform prioritization within an activity. Risk informed prioritization 14

guidance is documented in activity-specific lists that show the ranking of work within a given asset 15

class. Five Distribution Infrastructure Replacement (IR) activities and two Substation IR activities 16

currently rely on PRISM analysis to inform detailed prioritization decisions.92 In addition to PRISM 17

analysis results, a variety of other factors are considered as constraints in the final determination of 18

equipment or project prioritization, including execution constraints, work initiated before PRISM results 19

were available, and field assessment input. 20

In addition to informing prioritization within an activity, PRISM is used to allocate funds across 21

activities while taking into account funding and resource constraints. T&D accounts for the inherent risk 22

exposure and effectiveness of mitigation activities when allocating funding and resources. PRISM risk 23

assessment results include Risk Spend Efficiency (RSE) metrics comparable across activities. PRISM 24

results have been used in annual T&D budgeting exercises to inform trade-off decisions. More recently, 25

SCE’s decision in this GRC to prioritize Wildfire Management activities and defer work in areas such as 26

92 Distribution IR activities assessed by PRISM include the Overhead Conductor Program (OCP), the cable

portion of the Worst Circuit Rehabilitation (WCR) program, 4kV Cutover and Substation Elimination, Covered Pressure Relief Restraints (CPRR), and UG Switches. See Exhibit SCE-02 Vol. 01 chapter 2 for details. Substation IR activities assessed by PRISM include Circuit Breakers and Transformers. See Exhibit SCE-02 Vol. 03 for details.

97

Distribution Infrastructure Replacement and System Augmentation was validated with updated RAMP 1

analysis.93 As noted above, PRISM results were used as an input for select RAMP analysis. 2

E. Methodology Overview 3

The methodology used to complete PRISM risk assessments aligns with SCE’s ERM framework 4

and includes risk identification, risk evaluation, risk mitigation identification, risk mitigation evaluation, 5

decision making and planning, and monitoring and reporting. 6

PRISM utilizes risk statements for risk identification and documentation of risks in a common 7

syntax, as triggering events that lead to outcomes (e.g., underground cable failure leading to an outage). 8

Drivers are factors that contribute to a triggering event (e.g., a dig-in is one of several drivers that can 9

result in an underground cable failure triggering event). The triggering event can then result in multiple 10

outcomes (e.g., underground cable failure can result in safety incidents and/or outages). Outcomes may 11

result in risk estimates in one or more dimensions (e.g., the outage outcome will be measured in terms of 12

reliability risk). In the course of risk identification, the relationship between driver(s), a triggering event, 13

outcome(s), and risk dimension(s) is depicted with a PRISM bowtie diagram (see Figure III-31 below). 14

93 See SCE-01 Vol. 02.

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Figure III-31 PRISM Bowtie Diagram

Following risk identification, a risk evaluation is completed to quantify risks. Risk is a function 1

of frequency and outcome. PRISM risk units are calculated based on Triggering Event Frequency (TEF), 2

Consequence Percentage (CP), and Consequence Impact (CI).94 TEF is the annual number of times a 3

triggering event is expected to occur. CP is the probability that an outcome occurs as the result of a 4

triggering event (e.g., the probability that an outage occurs as the result of an underground cable failure). 5

CI is the severity of impact for outcomes measured on a scale of 1 to 7 across five dimensions, including 6

safety, reliability, financial, environmental, and compliance risks. Types of outcomes within each 7

category are also referred to as natural units (e.g., the natural unit in the reliability dimension is customer 8

hours of interruption). The risk score for a given triggering event is the sum of risk units across all 9

outcomes for an event measured across each risk dimension. 10

Risk mitigation identification and evaluation is completed to assess the effectiveness of activities 11

that are designed to decrease existing risks, either by reducing the frequency of triggering events and/or 12

reducing the consequence of the outcomes. Current Residual Risk (CRR) measures risk units before 13

94 PRISM risk score formula: 𝑟𝑖𝑠𝑘 𝑇𝐸𝐹 ∗ 𝐶𝑃 ∗ 10 .

Cable Water Intrusion

Underground Cable Failure

Overload/Fatigue

Internal Component

Cable

Dig-in*

Cable Splice

Cable Vandalism

Caple Splice Water Intrusion

Animal

Unknown*

Safety Incident*Safety

Outage*Reliability

Financial

*Top Drivers by Frequency *Top Outcomes by Risk Score

Driver Triggering Event Frequency Outcome Dimension

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proposed mitigations are deployed. Mitigated Risk Reduction (MRR) measures the reduction in risk 1

units as a result of a given mitigation activity or project. CRR and MRR are both calculated for a fifteen-2

year window and discounted to present value to approximate benefits for activities that result in risk 3

reduction benefits over time. Risk Spent Efficiency (RSE) is calculated as a measure of MRR per $1,000 4

spend.95 5

In addition to aligning with SCE’s ERM framework, PRISM methodology outlined here aligns 6

with several principles in Safety Model Assessment Proceeding (S-MAP) settlement requirements, 7

including the multi-attribute value function (MAVF), identification of potential consequences and 8

frequency of risk events, definition of risk events and tranches, bow ties, mitigation risk reduction 9

scoring, risk spend efficiency, and risk scores over time.96 While all requirements outlined in S-MAP 10

settlement requirements are not fully accounted for at this time, PRISM methodology will continue to 11

advance to support the SCE ERM framework and align with S-MAP guidance. 12

F. Progress to Date 13

PRISM was initiated as a pilot in 2014 to develop a broadly applicable quantitative framework to 14

assess T&D asset risks. Progress through March 2016 related to PRISM and T&D risk-informed 15

planning is documented in the 2018 GRC. The following section documents PRISM advancements from 16

March 2016 through March 2019, including equipment and project specific risk assessments, 17

incorporating predictive analytics in the process, removing the Worst Reasonable Direct Impact (WRDI) 18

assumption, and developing a basis for assessing voltage risk. 19

Recent PRISM risk assessment work has focused on developing granular equipment and project 20

specific scores. This is an advancement compared to earlier tranche-based analysis, which organized 21

equipment in sub-groups with similar risk profiles. Equipment and project specific scores are beneficial 22

because they enable T&D to directly link operational decisions to risk assessment results and inform 23

prioritization within a given activity. This process enables T&D to link risk assessment results to 24

scoping decisions for the set of activities listed above in the Applications section. 25

Select PRISM risk assessments have recently leveraged predictive analytics as the basis of 26

triggering event frequency (TEF). As noted in Section II.A.1.c), SCE has advanced asset management 27

95 While PRISM and RAMP both include concepts of MRR and RSE, all terminology mentioned in this chapter

is PRISM specific.

96 D.18-12-014.

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by developing predictive analytics models for select assets. These predictive analytics models gather 1

data from multiple sources related to asset, performance, weather, environmental, and geographic 2

attributes to inform machine learning models based on past equipment failures. The models are used to 3

predict future equipment failures. PRISM risk assessments that currently utilize predictive analytics 4

include the Overhead Conductor Program, the cable portion of the Worst Circuit Rehabilitation 5

Program, Underground Switch Replacement, and Cover Pressure Relief and Restraint activities. 6

The WRDI assumption described in the 2018 GRC is no longer in use.97 In previous PRISM risk 7

assessments the WRDI assumption to select the highest scoring consequence for each risk statement was 8

used to provide consistency in results across risk dimensions with varying degrees of available data. As 9

opposed to using the WRDI assumption that provided results in a step function for the single highest risk 10

score for a given risk statement, the scoring scale now in use accounts for the entire distribution of 11

outcomes for a given risk statement. This development provides greater consideration to the full range of 12

potential risk outcomes. 13

The last methodology advancement relates to risks associated with under- and over-voltage 14

conditions on the system. An analysis to evaluate how voltage condition risks compare to other risks 15

already included in the PRISM framework found that 250 customer-hours of under- or over-voltage 16

conditions were equivalent to one customer-hour of interruption. This equivalency enabled risk 17

assessments to account for under-and over-voltage conditions in PRISM risk assessments. The voltage 18

risk is currently used to approximate benefits of mitigating voltage risks through 4kV substation 19

elimination work. Accounting for potential risks associated with under- and over-voltage is considered 20

an expansion of the reliability risk dimension. 21

G. Conclusion 22

Evaluating risks, identifying and prioritizing work, and allocating resources has always been part 23

of T&D planning for SCE. The PRISM methodology used by T&D has been developed as framework, 24

which aligns with SCE’s ERM framework, to document existing risks and risk reduction benefits for 25

mitigations. Progress to date for PRISM risk assessments has demonstrated value in the form of multiple 26

use cases to inform objective data-driven decisions. The scope of PRISM risk assessments and 27

97 The WRDI assumption selected the highest single risk score for risk statements that had multiple consequence

combinations. See 2018 SCE-02 Vol. 1 Appendix.

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methodology will continue to advance and is expected to incorporate new data sources as they are made 1

available. 2

Documents

Distribution Infrastructure Replacement...1 1 I. 2 INTRODUCTION 3 A. Content and Organization of Volume 4 The Distribution Grid volume describes the activities SCE performs to inspect