Application No.:
Exhibit No.: SCE-03, Vol. 04
(U 338-E)
Before the
Public Utilities Commission of the State of California
Rosemead, California
November 2013

SUMMARY
This chapter describes programs which reduce the impact of aging infrastructure on the reliability and safety of SCE’s distribution and substation systems by replacing equipment before it fails in service. SCE is requesting $2.032 billion in 2013-2017 capital expenditures for these programs.
($ Millions, CPUC Jurisdictional Only)
Pole Loading (Volume
6, Part 2), $1,078 , 9%
Distribution
Maintenance (Volume
6, Part 1), $2,519 ,
21%
Customer Driven Prog
& Distr. Con.(Volume
5), $3,158 , 26%
Grid Operations
(Volume 7), $511 , 4%
Transmission &
Substation
Maintenance (Volume
8), $438 , 4%
T&D Engineering and
Grid Technology
(Volume 2), $183 , 1%
System Planning
Capital Projects
(Volume 3), $2,165 ,
18%
Infrastructure
Replacement
Programs (Volume
4), $2,032 , 17%

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SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
Table Of Contents
Section Page Witness
INTRODUCTION .............................................................................................1 R. Lee
A.
What Is Infrastructure Replacement? .....................................................1
B.
Why Is Infrastructure Replacement Necessary? ....................................1
1.
2.
Infrastructure Replacement Manages Costs,
Reliability, And Safety ...............................................................1
Equipment Failures Are Driven By Aging ................................3
3.
4.
5.
Illustration ..................................................................................4
SCE’s Infrastructure Is Aging ....................................................6
Conclusion .................................................................................8
C.
Overview Of Work Process Associated With Infrastructure
Replacement ...........................................................................................9
1.
Strategy Development ................................................................9
a) b)
Data Acquisition And Analysis .....................................9
Identification Of System Needs .....................................9
2.
3.
4.
c) Stakeholder Refinement ...............................................10
Project Management ................................................................10
a) Distribution ..................................................................10
b) Substation .....................................................................10
Design ......................................................................................11
a) Distribution ..................................................................11
b) Substations ...................................................................11
Construction .............................................................................11
a) Distribution ..................................................................11
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II.
A.
B.
D.
SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs b)
Table Of Contents (Continued)
Section Page
Substations ...................................................................11
Summary Of Cost Forecast ..................................................................12
CAPITAL WORK FORECASTS ....................................................................13
Historical Perspective ..........................................................................13
Distribution Infrastructure Replacement (DIR) Program ....................13
1.
Worst Circuit Rehabilitation Program .....................................14
a) Program Description ....................................................14
b) c) d)
Program Necessity .......................................................15
Historical And Forecast Spending ...............................17
Justification Of Forecast Work ....................................19
(1) Background ......................................................19
(2) Program Approach ...........................................23
(3) Quantitative Benefits .......................................24
(4) Non-quantitative Benefits ................................27
2.
3.
b) c) d)
(5) Conclusion .......................................................28
CIC Replacement Program ......................................................28
a) Program Description ....................................................28
Program Necessity .......................................................28
Historical And Forecast Spending ...............................29
Justification Of Forecast Work ....................................30
e) Conclusion ...................................................................36
Testing-Based Cable Life Extension Program .........................37
a) Description Of Program ...............................................37
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Witness

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5.
6.
7.
SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs b) c)
Table Of Contents (Continued)
Section Page
Necessity Of Program ..................................................37
Historical And Forecast Spending ...............................37
a) b) c) d) Justification Of Forecast Work ....................................39
Underground Oil Switch Replacement Program .....................42
Description Of Program ...............................................42
Necessity Of Program ..................................................42
Historical And Forecast Spending ...............................44
d) Justification Of Forecast Work ....................................45
PMH-4 Switch Replacement Program .....................................48
a) Description Of Program ...............................................48
b) c)
Necessity Of Program ..................................................50
Historical And Forecast Spending ...............................50
d) Justification Of Forecast Work ....................................51
Capacitor Bank Replacement Program ....................................51
b) c) d) a) b) c)
Description Of Program ...............................................51
Program Necessity .......................................................51
Historical And Forecast Spending ...............................52
d) Justification Of Forecast Work ....................................53
Distribution Voltage Regulator Program .................................56
a) Description Of Program ...............................................56
Program Necessity .......................................................56
Historical And Forecast Spending ...............................56
Justification Of Forecast Work ....................................58
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Witness

C.
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SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
Table Of Contents (Continued)
Section Page
Automatic Reclosers Replacement Program ...........................60
a) Program Description ....................................................60
9.
b) c)
Program Necessity .......................................................60
Historical And Forecast Spending ...............................60
d) Justification Of Forecast Work ....................................62
PCB Transformers Replacement Program ...............................63
a) Program Description ....................................................63
b) c) d)
Program Necessity .......................................................63
Historical And Forecast Spending ...............................65
Justification Of Forecast Work ....................................67
Substation Infrastructure Replacement (SIR) Program .......................68
1.
Transformer Bank Replacement ..............................................69
a) b)
AA-Bank Replacement ................................................70
A-Bank Replacement ...................................................71
c)
(1) Description Of Program ...................................71
(2) Necessity Of Program ......................................71
(3) Historical And Forecast Spending ...................72
(4) Justification Of Forecast Work ........................73
B-Bank Replacement ...................................................76
(1) Description Of Program ...................................76
(2) Necessity Of Program ......................................77
(3) Historical And Forecast Spending ...................77
(4) Justification Of Forecast Work ........................79
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Witness

2.
SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
Table Of Contents (Continued)
Section Page
Circuit Breaker Replacement ...................................................83
a) Bulk Power Circuit Breaker Replacement ...................84
D.
b) Distribution Circuit Breaker Replacement ...................84
(1) Description Of Program ...................................84
(2) Necessity Of Program ......................................85
(3) Historical And Forecast Spending ...................85
(4) Justification Of Forecast Work ........................86
4kV Circuit Replacement .....................................................................91
1.
Overview Of 4kV System ........................................................91
2.
4kV Circuit Overload-Driven Cutover Program ......................92
c) d) a) b)
Description Of Program ...............................................92
Necessity Of Program ..................................................92
Historical And Forecast Spending ...............................93
Justification Of Forecast Work ....................................95
3.
4kV Substation Elimination Program ....................................102
a) Description Of Program .............................................102
b) Necessity Of Program ................................................102
c) d)
Historical And Forecast Spending .............................107
Justification Of Forecast Work ..................................113
Appendix A Witness Qualification ..................................................................................
Witness
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SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
List Of Figures
Figure Page
Figure I-1 “Time-Dependent Failure Rate” .................................................................................................3
Figure I-2 Example of a Light Bulb Population’s Approach to its Long-term Steady State
Replacement Rate ..................................................................................................................................5
Figure I-3 Trend in Average Age of Underground Cable ............................................................................6
Figure I-4 Trend in Average Age of Distribution Poles ..............................................................................7
Figure I-5 Trend in Average Age of Subtransmission Poles .......................................................................7
Figure I-6 Trend in Average Age of Padmount PMH Switches .................................................................8
Figure I-7 Trend in Average Age of Underground Distribution Transformers ...........................................8
Figure II-8 2012 Capital Expenditures Authorized Versus Recorded (Nominal $ millions) ....................13
Figure II-9 Forecast of System SAIDI with No Program of Preemptive Cable
Replacement .........................................................................................................................................16
Figure II-10 Forecast of System SAIFI with No Program of Preemptive Cable
Replacement .........................................................................................................................................17
Figure II-11 Worst Circuit Rehabilitation/Cable Replacement Capital Expenditure WBS
Element CET-PD-IR-WC Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) ..............................................................................................................................19
Figure II-12 Current Inventory of Underground Cable by Year of Installation (as of yearend 2012) .............................................................................................................................................21
Figure II-13 Cable Failure Rates ................................................................................................................22
Figure II-14 Contribution to System SAIDI by Circuits in 2012 ..............................................................23
Figure II-15 Impact of WCR Program on Future SAIDI ...........................................................................25
Figure II-16 Impact of WCR Program on Future SAIFI ...........................................................................26
Figure II-17 CIC Replacement Capital Expenditure WBS Element CET-PD-IR-CC
Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) .................................30
Figure II-18 Pumping Equipment for CIC Removal .................................................................................31
Figure II-19 Pulling Equipment for CIC Removal ....................................................................................32
Figure II-20 Cable Designed for CIC Replacement ..................................................................................33
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SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
List Of Figures (Continued)
Figure
Figure II-21 Cable Life Extension WBS Element CET-PD-IR-LE Recorded 2008-
Page
2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) ...........................................................38
Figure II-22 In-Service Failures of Mainline Oil-Filled Subsurface Switch .............................................43
Figure II-23 Underground Oil Switch Replacement and PMH-4 Switch Replacement
WBS Element CET-PD-IR-SR Recorded 2008-2012/Forecast 2013-2017 (Constant
2012 and Nominal $000) .....................................................................................................................45
Figure II-24 Inventory of Mainline Subsurface Oil Switches by Year of Installation .............................47
Figure II-25 Probability of Failure vs. Age for Mainline Oil Switches .....................................................48
Figure II-26 Capacitor Bank Replacement Portion of WBS Element CET-PD-IR-CB
Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) .................................53
Figure II-27 Inventory of Overhead Capacitors by Year of Installation (as of year-end
2012) ....................................................................................................................................................54
Figure II-28 Inventory of Underground Capacitors by Year of Installation (as of year-end
2012) ....................................................................................................................................................55
Figure II-29 Distribution Voltage Regulator Replacement Program Portion of WBS
Element CET-PD-IR-CB Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) ..............................................................................................................................57
Figure II-30 Inventory of Distribution Voltage Regulators Outside of SCE Substations
(as of year-end 2012) ...........................................................................................................................59
Figure II-31 Automatic Recloser Replacement, WBS Element CET-PD-IR-AR Recorded
2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000)..................................................61
Figure II-32 Age Distribution of Overhead ARs by Year of Installation (as of year-end
2012) ....................................................................................................................................................62
Figure II-33 Inventory of Underground Automatic Reclosers by Year of Installation (as of year-end 2012) .................................................................................................................................63
Figure II-34 PCB Transformer Replacement WBS Element CET-PD-IR-PC Recorded
2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000)..................................................67
Figure II-35 Overview of SCE’s Transmission and Distribution System .................................................69
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SCE-03: Transmission and Distribution
Volume 04 – Infrastructure Replacement Programs
List Of Figures (Continued)
Figure
Figure II-36 Substation Transformer Replacement (AA-Bank, A-Bank, & B-Bank) WBS
Page
Element CET-ET-IR-TB Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000, includes FERC and CPUC jurisdictional expenditures) ......................................71
Figure II-37 Probability of Failure vs. Age for A-Bank Transformers ......................................................74
Figure II-38 Inventory of A-Bank Transformers by Year of Installation ..................................................75
Figure II-39 Probability of Failure vs. Age for B-Bank Transformers ......................................................80
Figure II-40 Inventory of B-Bank Transformers .......................................................................................81
Figure II-41 220kV – 2.4kV Circuit Breaker Replacement WBS Element CET-ET-IR-CB
Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000, includes FERC and CPUC jurisdictional expenditures) ......................................................................84
Figure II-42 Probability of Failure vs. Age for Distribution Circuit Breakers ..........................................87
Figure II-43 Inventory of 115kV and 66kV Circuit Breakers by Year of Installation ..............................88
Figure II-44 Inventory of 33kV – 2.4kV Circuit Breakers by Year of Installation ...................................89
Figure II-45 4kV Circuit Overload-Driven Cutover Program WBS Element CET-ET-LG-
4C Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000)............................95
Figure II-46 4 kV Circuit Overload Forecast (amps) .................................................................................96
Figure II-47 Bixby Substation .................................................................................................................104
Figure II-48 Belmont Substation (adjacent to residential houses) ...........................................................105
Figure II-49 Bedford Substation (a vault underneath an alley) ..............................................................106
Figure II-50 4kV Substation Elimination Program WBS Element CET-ET-IR-4C
Recorded 2008-2012/Forecast 2013-2017 (Constant 2012 and Nominal $000) ...............................112
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SCE-03 : Transmission and Distribution
Volume 04 – Infrastructure Replacement
List Of Tables
Table
Table I-1 Infrastructure Replacement Programs Summary of 2013 -2017 Forecast Capital
Page
Expenditures (Nominal $000) .............................................................................................................12
Table II-2 Historical and Forecast Spend under the WCR/Cable Replacement Programs ........................18
Table II-3 Underground Cable Statistics ...................................................................................................21
Table II-4 Historical and Forecast CIC Cable Replacement .....................................................................29
Table II-5 CIC Replacement Projects Forecast for 2013 ...........................................................................34
Table II-6 CIC Replacement Projects Forecast for 2014 ...........................................................................35
Table II-7 Historic and Forecast Spending for Cable Testing ...................................................................37
Table II-8 Cable Testing Economic Analysis ............................................................................................40
Table II-9 Circuits to be Tested in 2013 ....................................................................................................41
Table II-10 Historic and Forecast Spending for Underground Oil Switch Replacement ..........................44
Table II-11 Population of Underground/Padmounted Switches by Type ..................................................46
Table II-12 Inventory of PMH Switches ...................................................................................................49
Table II-13 Types of PMH Switches Having Experienced Violent Failure ..............................................50
Table II-14 Historic and Forecast Spending for PMH-4 Switch Replacement .........................................51
Table II-15 Historic and Forecast Spending for Capacitor Bank Replacement .........................................52
Table II-16 Forecast Spending for Distribution Voltage Regulator Replacement Program ......................58
Table II-17 Historic and Forecast Spending for Automatic Recloser Replacements ................................61
Table II-18 Historic and Forecast Spending for PCB-Contaminated Transformer
Replacement .........................................................................................................................................66
Table II-19 Type and Number of Transformer Banks ...............................................................................70
Table II-20 Historical and Forecast Spend for A-Bank Transformer Replacements .................................73
Table II-21 Forecast A-Bank Transformer Wear-Out Rate .......................................................................75
Table II-22 Historic & Forecast Spending for Distribution Transformer Replacements
(CPUC-Jurisdictional $(000) ...............................................................................................................78
Table II-23 Forecast B-Bank Transformer Wear-Out Rate .......................................................................81
Table II-24 Historic & Forecast Spending for Distribution Circuit Breaker Replacements
(CPUC-Jurisdictional $(000) ...............................................................................................................86
Table II-25 Forecast Circuit Breaker Wear-Out Rate, 66kV-115kV .........................................................89
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SCE-03 : Transmission and Distribution
Volume 04 – Infrastructure Replacement
List Of Tables (Continued)
Table Page
Table II-26 Forecast Circuit Breaker Wear-Out Rate, 4kV-33kV .............................................................90
Table II-27 Historic & Forecast Spending for 4kV Circuit Overload-Driven Cutovers ...........................94
Table II-28 4kV Circuit Overload Forecast (amps) ...................................................................................96
Table II-29 4 kV Cutovers to be Completed in 2013 .................................................................................97
Table II-30 4 kV Cutovers to be Completed in 2014 .................................................................................98
Table II-31 4 kV Cutovers to be Completed in 2015 .................................................................................99
Table II-32 4 kV Cutovers to be Completed in 2016 ...............................................................................100
Table II-33 4 kV Cutovers to be Completed in 2017 ...............................................................................101
Table II-34 Partial List of 4 kV Substations Containing Old Transformers and Circuit
Breakers .............................................................................................................................................103
Table II-35 Forecast Spending for 4kV Substation Elimination – 2013 .................................................107
Table II-36 Forecast Spending for 4kV Substation Elimination - 2014 .................................................108
Table II-37 Forecast Spending for 4kV Substation Elimination – 2015 .................................................109
Table II-38 Forecast Spending for 4kV Substation Elimination – 2016 .................................................110
Table II-39 Forecast Spending for 4kV Substation Elimination – 2017 .................................................111
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I.
INTRODUCTION
A.
What Is Infrastructure Replacement?
Infrastructure refers to major pieces of equipment, such as poles, transformers, switches, circuit breakers, capacitors, automatic reclosers, cable, and conductors that make up the distribution and substation system. Typically, these pieces of equipment operate for many years, some over fifty years, before they wear out. But eventually every part of the infrastructure will wear out and need to be replaced. In fact, every piece of equipment will need to be replaced repeatedly over the life of the system. Ongoing replacement of every component as it wears out is an inescapable part of maintaining a distribution and substation system.
While the lines of demarcation between programs are not always well defined, in general, programs associated with the replacement of equipment as a result of inspections are described under
Preventive Capital Maintenance. Programs associated with replacement of equipment after their inservice failure are described under Breakdown Capital Maintenance.
1 Programs associated with equipment replacement using a risk/reliability-based approach are described here under Infrastructure
Replacement.
These chapters focus on Infrastructure Replacement in three areas: x Distribution equipment; x Substation equipment; and x 4 kV circuits and substations.
B.
Why Is Infrastructure Replacement Necessary?
1.
Infrastructure Replacement Manages Costs, Reliability, And Safety
Every piece of equipment will eventually wear out and need to be replaced. There are three options available for dealing with equipment as it wears out: x Run-to-failure, i.e., wait until the equipment fails in service and then replace it; x Inspection-driven replacement, i.e., replace the component prior to in-service failure after inspections identify observable indications of imminent failure;
1 Preventive Capital Maintenance and Breakdown Capital Maintenance are discussed in Exhibit SCE-03, Vol. 6, Part 1:
Distribution Inspections and Maintenance.
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25 x Risk/reliability-based preemptive replacement, i.e., replace the component prior to inservice failure when engineering analyses predict excessive risk.
The optimum strategy for replacing aging equipment varies with equipment type and depends on: (1) how thoroughly the condition of the equipment can be assessed by inspection; and (2) the consequences of an in-service failure in terms of cost, reliability, and safety.
A run-to-failure strategy can, for some types of equipment, be the preferred approach.
For equipment whose in-service failures have minimal consequences, there is little benefit derived from preemptive replacement. In-service failures of capacitor banks, for example, are very rarely violent and usually pose little threat to reliability if replaced in a timely manner. Therefore, SCE’s capacitor replacement program is largely based on run-to-failure.
Virtually every piece of equipment could benefit from routine inspections of its physical condition. Such inspections, performed per G.O. 165, reveal many obvious symptoms of aging and result in large quantities of equipment being replaced each year prior to in-service failure. Ideally, routine inspections of equipment would prevent all in-service failures of equipment. Unfortunately, this is not the case, even with current state-of-the-art inspection technology. For most types of equipment, inspections reveal only external deterioration. Problems inside the equipment usually cannot be detected. Therefore, while inspection programs prevent many in-service equipment failures, they cannot prevent all of them.
When the consequences of in-service failure can be unacceptably high, a risk-based approach to infrastructure replacement is necessary, (where risk is defined as {probability of in-service failure} x {consequence of in-service failure}). This risk-based approach to infrastructure replacement is intended to deal with equipment believed to be approaching the end of its service life and when failure could result in significant unnecessary expenses, prolonged and/or widespread power outages, and/or injury to our employees and the public. Our infrastructure replacement program is a necessary part of providing safe and reliable electric service at a reasonable cost.
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2.
Equipment Failures Are Driven By Aging
The likelihood that a given component will fail is a function of its age. The reliability of most types of equipment is described by a “time-dependent failure rate” curve, as shown conceptually in
Figure I-1.
2
a) Probability that an
Individual
Piece of
Equipment will Fail, or b) Fraction of
Components in a Large
Population
Reaching the End of their Service
Lives
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This curve may be read two ways. In the case of an individual component, the curve tells us that the component’s probability of failure will remain low for a long period of time. Then, at some point in its life, the component’s probability of failure begins to increase dramatically.
In the case of a large population of components, the fraction of components reaching the end of their service lives will be small as long as the average age of the population is young.
3 Then, as the average age of the population approaches its mean-time-to-failure, the volume of components wearing out and needing replacement will increase significantly.
2 Ref. , 2 nd Ed., Hiromitsu Kumamoto, Ernest
J. Henley, p. 267, Figure 6.2.
3 The average age must be measured on a fixed (non-growing) population in order for it to be useful in forecasting the number of failures in that population. The addition of new equipment to accommodate new customers reduces the average age of the total population but clearly does not reduce the number of failures expected in the “original” population.
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Note that in a fixed population the volume of equipment failing each year will not increase indefinitely. This is because the average age of a fixed population cannot increase indefinitely.
At some point, the average age of a fixed population will plateau and, sometime after that, the replacement rate will also plateau at a “long-term steady-state replacement rate.”
While precise calculations of when the average age of the population will plateau and when the steady state replacement rate will plateau can be complicated, the simple message of these curves should not be lost. As long as the average age of a population continues to increase, the number of components wearing out and needing to be replaced each year will also increase.
3.
Illustration
SCE’s distribution infrastructure can be likened to the population of light bulbs in a hypothetical factory. Imagine a new factory commencing operation. This factory, which is going to operate around the clock, seven days a week, has a population of 10,000 fluorescent light bulbs illuminating all the work areas. Let’s suppose that a maintenance crew will come in every morning to look for and replace any burned-out bulbs. When the factory turns on all the lights for the first time, we would not expect any burned-out bulbs. Because the typical fluorescent light bulb has an average service life of about 10,000 hours (or about 60 weeks or 417 days), we would not expect the maintenance crew to have much to do for the first several weeks. But eventually we would start to find an occasional failed bulb. By around the 30th week, we might be finding 1 or 2 bulbs burned out each day. By around the 40th week we might be finding 3 or 4 bulbs burned out each day, maybe 8 bulbs per day in the 50th week, and maybe 12 bulbs per day in the 60th week. Eventually we would see the replacement rate of light bulbs level-off at an average rate of about 24 bulbs per day (Figure I-2).
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This rate of 24 bulbs per day on average is the long-term steady state replacement rate and is the rate at which the factory would be replacing bulbs indefinitely. This long-term steady state replacement rate is calculated by dividing the population of light bulbs ( i.e
., 10,000) by the average service life of a light bulb ( i.e
., 417 days).
Replacing an average of 24 bulbs per day will be an unavoidable part of the cost of operating the factory. The only way to reduce this replacement rate of 24 bulbs per day would be to either reduce the total number of bulbs in the factory below 10,000 or increase the expected service life of each bulb beyond 417 days.
Finally, the dynamics of average age must be understood. The average age (or arithmetic mean age) of an equipment population is the sum of the ages of every component in that population divided by the size of the population. Using our example of light bulbs in a factory, at the end of 25 days, if none of the bulbs had burned out, then the average age of all the light bulbs would obviously be
25 days, (10,000 * 25 days / 10,000). Assuming no bulbs burned out, at the end of 50 days, the average age of the bulb population would be 50 days. Up until this point, the average age would have been increasing by one day each day. Suppose, however, that on the 51st day, two bulbs burned out and were replaced with new bulbs (each 0 days old). The average age of the light bulbs would now be, not 51 days, but 50.9898 days, ({9,998 bulbs * 51 days + 2 bulbs * 0 days} / 10,000). The average age of the bulb population has still increased but by less than one day per day. As our hypothetical factory
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4.
SCE’s Infrastructure Is Aging
The average age of many types of equipment in SCE’s distribution system is increasing as can be seen in Figure I-3, Figure I-4, Figure I-5, Figure I-6, and Figure I-7 below.
4 Calculating the times when a population reaches its peak average age and its long term steady state replacement rate is complicated. Much depends on the shape of the “time dependent failure rate” curve and the historical growth profile of the population. Our conclusions about the hypothetical light bulb population assume that it will have characteristics similar to what we expect to see in our cable population.
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5.
Conclusion
Because much of SCE’s infrastructure is continuing to age, as indicated by the trends in the average age of equipment shown above, the volume of infrastructure wearing out and needing to be
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2 replaced each year is continuing to grow. Not all of this deterioration can be identified through inspections. When in-service failure poses an unacceptable risk in terms of cost, reliability, and/or safety, SCE and its customers cannot wait for equipment to fail; SCE must replace it preemptively.
C.
Overview Of Work Process Associated With Infrastructure Replacement
1.
Strategy Development a) Data Acquisition And Analysis
SCE’s Asset Management and System Reliability group (AMSR) is responsible for establishing a long-term strategy for managing distribution system reliability through asset management. AMSR maintains records of distribution assets, tracks distribution system and circuit reliability, identifies actual and probable performance trends, and drafts cost-effective corrective actions where indicated.
Asset Management maintains records on major substation equipment, analyzes historic performance, assesses risks of future in-service failures, and develops long-term infrastructure replacement strategies.
5 b) Identification Of System Needs
Asset Management evaluates outage records to identify the worst performing circuits in terms of System SAIDI, System SAIFI, Circuit SAIDI, and Circuit SAIFI.
6 The most risksignificant equipment/infrastructure in the worst-performing circuits are identified for replacement. In addition to the replacement of aging infrastructure, circuit enhancements, (e.g., automation, the addition of automatic reclosers and radial fuses, and the elimination of “chokers” 7 ) may also be identified wherever cost-effective.
5 AMSR has had the responsibility for overseeing distribution assets for many years. Overseeing a long term strategy for major substation assets is a recent addition to its responsibilities.
6 SAIDI is the System Average Interruption Duration Index. This represents the amount of time the “average” customer was without power due to “sustained,” i.e., over 5 minutes, outages during the year. SAIFI is the System Average
Interruption Frequency Index. This represents the number of times the “average” customer experienced a “sustained” outage during the year.
7 A “choker” is a segment of cable that is too small to carry the amount of power we would like to send through it. We often find chokers at the end of a circuit where the cable is smaller and where we have tied that circuit to an adjacent circuit in order to provide a backup source of power. If the cable near the tie is too small, the adjacent circuit can back up only a portion the circuit. Replacement of the choker cable can allow the adjacent circuit to carry a much larger portion of the circuit. This can have a significant impact on reliability.
9

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28
29
30
23
24
25
26
20
21
22
17
18
19
13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
Asset Management provides a preliminary schedule for replacing major substation assets based on the probability of in-service failure which, in turn, is based on failure analyses, inspection data, and the input from subject matter experts in Engineering. c) Stakeholder Refinement
Draft work scopes for distribution infrastructure replacement are reviewed with all major stakeholders within SCE, including Region and District operations personnel, Field
Engineering, and Public Affairs prior to submittal for design. This way the latest data regarding circuit performance and other information not included in the Outage Records Database are factored into determining which circuits and items of infrastructure will be worked. Emergent conditions, which may alter the substance and/or priority of the work, are reviewed monthly at the Regional Grid Team meetings.
Draft project scopes and schedules for substation infrastructure replacement are reviewed with SCE’s Substation, Construction, and Maintenance (SC&M) department. Adjustments are made to these plans to incorporate SC&M input regarding recent performance data, vendor issues, and maintenance problems. Schedule adjustments may also be made to coordinate with other planned construction projects.
2.
Project Management a) Distribution
Work scopes for distribution projects are submitted to SCE’s Distribution Project
Management Organization (DPMO) which tracks and manages work scopes through design and construction. It coordinates field changes, if required, between Engineering and Design, and coordinates permitting and acquisition of necessary easements. DPMO reviews completed Work Orders for accuracy and completeness. Completed Work Orders are then issued to the appropriate Regional Project
Planning Manager for Construction. b) Substation
Proposed substation projects are submitted from the Integrated Work Plan (IWP) as a Project Management Work Initiation Form (PMWIF) to SCE’s Major Projects Organization (MPO).
Upon approval, projects are given to Transmission/Substation Engineering for design and material procurement. Project Management tracks design, construction, and cost status from design through construction.
10

19
20
21
22
23
13
14
15
16
9
10
11
12
17
18
7
8
5
6
3
4
1
2
3.
Design a) Distribution
Work Orders for distribution infrastructure replacement projects are developed by
Technical Design which reviews work scopes, performs field visits, and identifies necessary changes based on these field visits. Technical Design then prepares a Work Order based on agreed upon work scope and returns it to DPMO. b) Substations
Substation projects are designed in SCE’s Substation Projects group of
Transmission/Substation Engineering. Completed designs are sent to SC&M for construction.
4.
Construction a) Distribution
Each Region’s Resource Planning and Performance Manager determines whether the construction work will be performed by SCE crews or contractor crews based on resource availability. Projects performed by SCE crews are managed by the Regional Scheduling Manager.
Projects performed by contractor crews are managed by each Region’s Project Superintendent. DPMO tracks and reports on each project through completion.
After the circuits are re-energized, completed Work Orders are given to Field
Accounting for mapping updates and Work Order closing. b) Substations
Construction of substation infrastructure replacement projects are managed by the
Construction Division of SC&M. After the project is completed and the new equipment is in service, the completed Work Orders are given to SCE’s Field Accounting for mapping updates and Work Order closing.
11

1
D.
Summary Of Cost Forecast
(Total Company Nominal $000)
Activity
Worst Circuit Rehabilitation
Cable In Conduit Replacement
Testing-based Cable Life Extension
Underground Oil Switch Replacement
PMH-4 Switch Replacement
Capacitor Bank Replacement
Distribution Voltage Regulator
Automatic Recloser Replacement
PCB Transformer Replacement
Transformer Bank Replacement
Circuit Breaker Replacement
4 kV Circuit Overload-Driven Cutovers
4kV Substation Elimination
2013
104,605
25,544
12,847
5,610
3,474
12,731
511
1,010
1,737
62,108
29,483
21,253
20,436
$ 301,348
2014
85,086
65,451
13,167
9,425
3,133
13,048
524
2,388
1,780
83,775
32,592
23,562
41,889
$ 375,820
2015
112,961
93,577
26,892
9,625
-
13,325
535
2,438
1,818
72,972
31,430
26,736
85,556
$ 477,865
2016
115,486
95,669
27,494
9,840
-
13,623
547
2,493
1,859
74,168
31,946
27,334
87,469
$ 487,927
2017
118,607
98,254
28,237
10,106
-
13,991
561
2,560
1,909
75,973
32,723
28,073
89,832
$ 500,827
Total
536,744
378,495
108,636
44,606
6,607
66,720
2,677
10,889
9,103
368,996
158,175
126,958
325,181
$ 2,143,788
12

1
2
3
A.
Historical Perspective
II.
CAPITAL WORK FORECASTS
(CPUC-Jurisdictional Nominal $ millions)
300
$
266
250
$44
200
$40
$0
$4
$11
150
100
$ 167
50
-
2012 Authorized WCR & CIC
Repl
4kV Program Sub CB Repl Sub Xfmr Repl Dist Misc Repl 2012 Recorded
WCR & CIC Repl 4kV Program Sub CB Repl Sub Xfmr Repl Dist Misc Repl Diff from Auth
10
11
8
9
6
7
4
5
As shown in Figure II-8 above, in 2012 SCE spent 63 percent of what was authorized within the capital expenditure categories included in this exhibit. Recorded spending for the Worst Circuit
Rehabilitation and CIC replacement programs, and the 4kv cutover programs showed the largest difference from authorized ($44 million below the authorized amount). The delay in the 2012 GRC decision had a significant impact on expenditures in all distribution infrastructure replacement programs.
B.
Distribution Infrastructure Replacement (DIR) Program
The Distribution Infrastructure Replacement program replaces major pieces of aging or obsolete equipment in order to minimize the negative effect of aging on system reliability and safety. Eight
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16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
23
24
25
26 individual programs make up the DIR program: Worst Circuit Rehabilitation, Cable-in-Conduit
Replacement, Underground Oil Switch Replacement, PMH-4 Switch Replacement, Capacitor Bank
Replacement, Automatic Recloser Replacement, Distribution Regulator Replacement, and PCBcontaminated Transformer Replacement. Testing-based Cable Life Extension is an additional program which, while not directly replacing infrastructure, provides information necessary for targeting cable segments to be replaced by other programs.
1.
Worst Circuit Rehabilitation Program a) Program Description
The Worst Circuit Rehabilitation (WCR) program is an ongoing effort to manage system reliability by dealing with the challenge of infrastructure aging.
This program began in 1997, when it was known as the Annual Circuit Review
(ACR). We temporarily halted the program in 2004 due to lingering effects of California’s energy/financial crisis of 2002 - 2003 and restarted it again in 2005 as the Worst Circuit Rehabilitation
(WCR) program. A Cable Replacement Program was created in 2000 in order to focus solely on underground cable replacement, however this program was absorbed into the WCR program in 2012 in order to improve work efficiencies.
The two-fold objective of the WCR program is to: (1) minimize the negative impact of infrastructure aging on overall system reliability; and (2) minimize the disparity between levels of reliability received by customers served by different circuits.
The WCR program focuses attention on those circuits which are disproportionately high in terms of their contribution to system SAIDI and SAIFI and those circuits whose average customers are receiving relatively lower service reliability. Circuit rehabilitation typically involves replacement of each circuit’s most risk-significant mainline cable. This program also replaces infrastructure that has a lower reliability record and adds circuit enhancements such as automation, automatic reclosers, branch line fuses, and fault indicators wherever judged to be costeffective.
8
8 The determination of what constitutes cost-effective enhancements on a poorly performing circuit is based on the judgment of experienced reliability engineers as well as the results of a study performed by KEMA in 2007 which demonstrated that fault isolation devices such as fuses, automatic reclosers, and automation are highly cost-effective on circuits where they do not already exist.
14

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2 b) Program Necessity
While age-related deterioration will affect every piece of equipment in SCE’s distribution infrastructure, underground cable is unique. Significant percentages of the transformer, switch, and pole populations have, for decades, been replaced each year as a result of routine visual inspections. This inspection-driven replacement of visibly deteriorated infrastructure reduces the number of in-service failures. Underground cable is unique in that it cannot be visually inspected.
Without a deliberate preemptive replacement program, cable would be removed from the system only as a result of in-service failure.
Figure I-3, “Trend in Average Age of Underground Cable,” illustrates the degree at which SCE’s underground cable is continuing to age.
9 Figure I-1, “Time-Dependent Failure Rate,” illustrates that with increasing age will come an increasing volume of cable reaching the end of its service life. This increasing volume of cable reaching the end of its service life will result in an increase in the number of in-service failures and resultant circuit outages. These cable outages, which are typically protracted, will negatively impact system reliability and customer satisfaction.
SCE performed a probabilistic analysis to forecast the impact of cable aging on system reliability.
10 The results of that analysis are shown in Figure II-9 and Figure II-10.
9 In fact, Figure I-3 understates the aging of our cable population because it includes in the addition of about 1,000 conductor-miles of new cable each year. A true trend of average cable age would examine a fixed population of cable and ignore subsequent additions of new cable.
10 See Workpaper entitled “Impact of Infrastructure Aging and a Program of Worst Circuit Rehabilitation on Future System
Reliability”
15

16

6
7
4
5
1
2
3
These figures indicate that without the benefit of a program of preemptive replacement, SAIDI will increase by approximately 61 minutes and system SAIFI will increase by about
0.269 interruptions over the next 20 years due to the aging of underground distribution cable. We consider this an unacceptable level of reliability. Our WCR program is intended to prevent this. c) Historical And Forecast Spending
Our recorded and forecast spending for underground cable replacement under the
Worst Circuit Rehabilitation Program is shown in Table II-2.
11
11 See Workpaper entitled “Cost of WCR Cable Replacement.”
17

Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Cable
Replacements
Completed under the Cable
Replacement
Program
(conductor-
Cost of Cable
Replacements
Completed
Replacement
Program
(Nominal $ x
1,000) under the
WCR
Program
(conductor-
Cost of WCR
Program
(Nominal $ x
1,000)
Forecast Unit Cost
(Nominal $ x 1,000)
Historic/Forecast
Spend for WCR
Program
(Nominal $ x 1,000)
Cable
Replacements
Completed under the UG Oil-filled
Switch Program
(conductor-miles) miles)
Cable miles)
Total Miles of
Cable Replaced
13
116
63
131
51
70
0
0
0
0
$11,439
$27,805
$35,875
$53,261
$32,747
55
73
81
62
59
245
250
325
325
325
$12,942
$16,932
$24,679
$23,749
$34,195
$332
$340
$348
$355
$365
$24,381
$44,737
$60,554
$77,010
$66,942
$104,605
$85,086
$112,961
$115,486
$118,607
51
0
0
31
81
98
61
0
0
0
99
270
242
254
161
315
250
325
325
325
18

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
9
10
11
12
13
14
7
8
5
6
3
4
1
2 d) Justification Of Forecast Work
(1) Background
SCE has approximately 50,179 conductor-miles of underground cable installed in approximately 4,600 distribution circuits. This cable is comprised of four basic insulation types: (1) paper insulated lead covered (PILC) cable; (2) high molecular weight polyethylene (HMW) insulated cable; (3) cross-linked polyethylene (XLPE); and (4) tree retardant cross-linked polyethylene
(TR-XLPE).
PILC cable is the oldest cable in our distribution system. While it is relatively long-lived and resistant to voltage spikes, PILC cable has many disadvantages. First, it cannot be moved once installed and therefore cannot be used with today’s removable “elbow connectors” for which all modern switches, transformers, and junction bars are designed. Secondly, when PILC cable fails, it presents a significant repair challenge. Performing repairs in PILC cable is very timeconsuming, can only be done by a small number of specially trained workmen, and often results in splices which are prone to subsequent failure.
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16
9
10
11
12
17
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19
20
7
8
5
6
3
4
1
2
HMW cable was the industry’s first effort at polymer insulation and reflects the immaturity of the science at that time. HMW cable has a significantly shorter life expectancy than cable manufactured today. Most of it has already been removed. What remains is believed to be close to failure.
Most of the underground cable in our system is XLPE. This cable has an average expected time-to-wear-out of about 34 years. For XLPE cable, breakdown of the insulation over time is generally the cause of cable failure. Typically, moisture around the cable penetrates through the polyethylene insulation, causing electrical tracking along voids and contaminants in the insulation and forming patterns that look like “trees.” This phenomenon of “water treeing” is the most common cause of underground cable failure.
TR-XLPE cable has been SCE’s standard since 1999. TR-XLPE contains essentially XLPE insulation material but with improved resistance to water-treeing. TR-XLPE cable has an expected time to wear out of about 36 years.
When a cable fails, as all eventually will, electricity in the center conductor breaks through the insulation and finds a return path back to the substation from which the cable is fed. The result of this short-to-ground is excessive current that causes an upstream protective device, such as a fuse, automatic recloser, or substation circuit breaker, to actuate and cut off power to all customers downstream of the protective device.
Figure II-12 below shows the current inventory of underground cable by year of installation.
20

1
2
For each of the four types of cable, Table II-3 below shows its average age, its average time to wear out, and the current inventory.
Type of insulation
PILC
HMW
Paper Insulated Lead Covered
High Molecular Weight Polyethylene
XLPE Cross-Linked Polytheylene
TR-XLPE Tree Retardant Cross-Linked Polythelene
Estimated dates of
Installation
Prior to 1968
1968-1970
1970-1998
Since 1999
Average
Age MTTF
44
43
27
7
47
22
34
36
Conductormiles
3,279
1,402
28,369
17,129
50,179
21

1
2
SCE has analyzed its cable failures and identified the relationship between the probability of failure and cable age. This relationship is shown in Figure II-13 below.
12 13
3
4
5
As one would expect, these cable failure curves resemble the timedependent failure rate curve of Figure I-1 and predict an increase in the number of in-service cable failures as our cable continues to age. And indeed, our cable will continue to age. As Figure II-13
12 See Workpaper entitled “Underground Cable Reliability.”
13 We believe these failure rates are reasonable. Our best estimate of the failure rate of SCE’s XLPE cable at 40 years is slightly lower than the “lower bound” failure rate and about two-thirds lower than the “best guess” failure rate projected by PG&E for its cable in its 2007 GRC filing, Exhibit 4, Chapter 18, p. 38, Figure 4.5. See Workpaper “Cable Failure
Rates from PG&E 2007 GRC.”
22

5
6
7
3
4
1
2 points out, the average age of our XLPE cable (which constitutes 56% of our cable population) is only
27 years, with a mean-time-to-wear-out of 34 years. The average age of our TR-XLPE (which constitutes 34% of our cable population) is only 7 years old, with a mean-time-to-wear-out of 36 years.
(2) Program Approach
The objective of the Worst Circuit Rehabilitation program is to invest infrastructure replacement dollars where they will achieve the most benefit in reliability improvement.
Clearly, not all circuits are in equal need of rehabilitation, as Figure II-14 below indicates.
10
11
8
9
12
13
In 2012, about 7% of the circuits were responsible for roughly 50% of the entire system’s SAIDI. Therefore, we believe it prudent to focus our WCR program on the worst performing circuits in the system as established by historical reliability data.
Each of our 4,600 circuits is ranked in terms of five different reliability metrics: (1) contribution to system SAIDI; (2) contribution to system SAIFI; (3) circuit-SAIDI; (4) circuit-SAIFI; and (5) peak load x number of interruptions/number of customers. The top ranked (i.e.,
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20
21
22
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14
15
16
9
10
11
12
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18
7
8
5
6
3
4
1
2 worst) circuits in each category are selected for further evaluation. This draft list of WCR circuits is then presented to and critically reviewed by other stakeholders including Field Engineering, District management, Region management, and Public Affairs. This review ensures that the less quantitative factors, e.g., customer special needs, have been considered in determining which circuits will be worked that year. Historically, about 5% of the initially listed circuits will be replaced with substituted circuits on the basis of non-quantifiable factors. These substitutions are documented.
With an approved list of circuits to be worked, the Asset Management group evaluates each circuit’s outage history to determine the causes of past outages and what corrective measures, if any, could be undertaken to improve future performance. Ultimately, under the WCR program, only the work judged to be the most cost-effective will be performed. When cable is replaced, only the least reliable cable, typically less than 10% of the cable in the circuit, is replaced. Cable which is replaced is selected on the basis of: (1) a history of failure; (2) being among the oldest; (3) being the most heavily loaded and therefore degraded; and (4) its potential for causing the largest outages if it were to fail. The installation of fuses on radial portions of the circuit, (the single-most cost-effective improvement possible) is always performed on any circuit worked whenever physically possible.
Isolation devices, such as automation and automatic reclosers, which are relatively inexpensive, are installed wherever judged to be both effective and cost-effective. Replacements of infrastructure where we would expect less than optimum reliability benefits are not performed under the WCR program
(3) Quantitative Benefits
To quantify the impact of cable aging and the resulting increase in cable failures on system reliability, SCE undertook a major engineering analysis of 20 representative circuits.
These 20 circuits were selected using cluster analysis methods 14 so that they statistically represented all
4,600 circuits in SCE’s distribution system. Models of these circuits were constructed using the CYME-
DIST-RAM software package. Every major circuit component was assigned a probability of failure and the theoretical reliability of each circuit was then calculated. An overall system level reliability was calculated by extrapolating the reliability of these 20 circuits out to the entire distribution system. To
14 Cluster analysis is the grouping of objects, in this case circuits, by the closeness of their characteristics. If circuit length were the only characteristic being considered, we might have created one cluster for all circuits whose length was between 0 and 1 miles, another cluster for circuits whose length was between 1 and 2 miles, etc. The task becomes more mathematically challenging because we evaluated approximately 15 characteristics, e.g., number of customers, historic reliability, miles of underground cable, etc., for each circuit. In the end, we identified and modeled one actual circuit for each of the 20 circuit clusters.
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3
4
1
2
5
6 estimate future system reliability, each cable segment in each of the modeled circuits was “aged” by increasing its probability of failure with each additional year. Each circuit’s SAIDI and SAIFI were calculated for each year out to 20 years with the results again being extrapolated to reflect the entire distribution system. The forecast increases in SAIDI and SAIFI were adjusted downward to reflect the exclusion of IEEE 1366 Major Event Days. The results of our analysis are shown in Figure II-15 and
Figure II-16 below.
25

7
8
5
6
9
3
4
1
2
The curves labeled “0 IR” on Figure II-15 and Figure II-16 reflect our 20year forecasts of system SAIDI and SAIFI without the benefit of SCE’s WCR program. What our analysis predicts is an increase in SAIDI of approximately 61 minutes/year and an increase in SAIFI of approximately 0.269 interruptions/year over the next 20 years.
15
After analyzing the impact of infrastructure aging with no preemptive cable replacement, we re-performed the analysis assuming various levels of preemptive cable replacement coupled with the typical WCR circuit enhancements, such as installation of automation, automatic reclosers, fuses, and fault indicators, wherever possible. Recognizing the near impossibility of preventing any decline in reliability over the near term, our objective was to identify the level of
15 In our 2012 GRC we relied upon an analysis performed by an outside consultant Quanta Technology. Since that time, we have developed in-house capabilities to perform that type of study. For this GRC, we developed new circuit models, corrected faulty assumptions, and re-performed that analysis. Despite their differences, both analyses yielded similar results.
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15
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12
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4
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2
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18
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21
22
23
24
25 infrastructure replacement which would restore, in 20 years, the level of reliability we are providing today.
What the analysis concludes is that approximately 570 conductor-miles of primary underground cable would need to be preemptively replaced each year in order to achieve, in 20 years, today’s level of SAIDI.
16 The average annual SAIDI, given a program of 570 miles of cable replacement, is indicated by the curve labeled “570 IR” on Figure II-16.
SCE’s plan is to preemptively replace 500 conductor-miles of underground cable each year. Of this, 325 miles will be mainline cable replaced under the WCR
Program and 175 miles will be radial cable replaced under the CIC Replacement Program. (CIC
Replacement and Testing-based Cable Life Extension will be discussed in the following two sections).
(4) Non-quantitative Benefits
Our WCR program also addresses the issue of equity in the quality of service provided to our customers. While it appears inevitable that our average overall system level reliability will decline in future years due to the harsh reality of infrastructure aging, our WCR program will function to limit the decline in reliability of any individual circuit. This program is directed specifically at circuits whose reliability makes them outliers, i.e., worst of the worst. Furthermore, these programs use a variety of reliability metrics to track circuit reliability to ensure that no degradations in performance will go undetected.
Finally, SCE monitors circuit performance on a monthly basis in order to ensure that emergent reliability issues in individual circuits are identified promptly. The reliability performance of each worst-performing circuit in each of SCE’s eight Regions is reviewed on a monthly basis as part of the Regional Grid Team meetings. Performance outliers are identified and corrective actions initiated as indicated. The WCR program is SCE’s first line of defense in the pursuit of our goal to provide an equivalent level of good and affordable service to all our customers, despite our forecast decline in average overall system reliability.
16 A “sanity check” can be performed on this replacement forecast by dividing the total cable population of approximately
50,000 conductor-miles by a very conservative mean-time-to-failure of 45 years. This gives us a long term steady state replacement rate of 1,100 conductor-miles per year. Clearly, a preemptive replacement rate of 500 miles per year is not excessive.
27

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14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
27
28
29
30
31
23
24
25
26
(5) Conclusion
There are three conclusions that should be drawn regarding SCE’s WCR program. First, the equipment these programs will replace is near failure. Infrastructure replaced under the WCR program are the least reliable components in the worst performing circuits in the system.
Second, this program will produce quantifiable results. SCE has demonstrated with objective analysis the benefits that can be expected from these preemptive replacements of infrastructure.
Third, this forecast is realistic. It will not fully counteract the effects of aging on our infrastructure, but will moderate it to a level which we believe our customers will agree is an acceptable balance between quality of service and affordability.
2.
CIC Replacement Program a) Program Description
The CIC Replacement Program preemptively replaces segments of SCE’s cablein-conduit (CIC) population which are approaching the end of their service life. The objective of the program is to reduce the number of in-service failures of CIC cable. b) Program Necessity
In the late 1960s, SCE began installing a type of underground cable known as
“cable-in-conduit,” or CIC. CIC is distinguished not by its insulation material (its insulation is either
HMW or XLPE), but by its construction. While cable in the mainline sections of circuits is typically installed in rigid PVC duct, CIC is installed in relatively thin-walled polypropylene tubing. CIC comes from the manufacturer with the conductor already inside the polypropylene tubing and coiled up on a large reel. It was installed primarily in radial branches of circuits serving residential customers. CIC was very attractive at the time because of: (1) its ease of installation which shortened the construction time of residential developments; (2) its lower cost relative to cable installed in rigid duct; and (3) its greater durability over that of direct buried cable.
However, decades later we have found that CIC is very difficult to replace. While cable installed in rigid PVC duct can be removed relatively easily, CIC cable resists being pulled out from its polypropylene tubing. This is especially true if the polypropylene tubing has been damaged as is usually the case when a CIC cable faults to ground. The tight clearances between the conductor and the tubing wall, the tendency of the tubing to crush and impinge on the conductor, and the tendency of the concentric neutral wires to break and “ball up” all make removal of the CIC conductor difficult and
28

7
8
5
6
9
3
4
1
2 often impossible. Outages to replace failed CIC can be very long. A typical outage caused by an inservice failure of CIC is over 20 hours.
17
Figure II-9 and Figure II-10 depict the future of SCE’s system reliability without a program of preemptive cable replacement. Approximately 13,000 conductor-miles, one-fourth of
SCE’s cable population, is CIC type cable. The challenge of an aging cable population cannot be adequately met without addressing the issue of CIC. c) Historical And Forecast Spending
Table II-4 and Figure II-17 below indicate SCE’s historic and forecast spending under the CIC Replacement program.
18
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Year
Recorded/Forecast
Replacements of CIC
(conductor-miles)
Forecast Unit
Cost of CIC
Replacement
(Nominal dollars x 1,000)
Recorded/Forecast
Cost of CIC
Replacements
(Nominal dollars x
1,000)
2.1
14
7.6
15.7
50
125
175
175
175
$511
$524
$535
$547
$561
$932
$4,030
$5,582
$4,674
$25,545
$65,451
$93,577
$95,669
$98,255
17 See Workpaper entitled “Duration of CIC Outages.”
18 See Workpaper entitled “Cost of CIC Replacement.”
29

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
7
8
5
6
3
4
1
2
9
10
11
12
13 d) Justification Of Forecast Work
As discussed in preceding sections, SCE’s cable population is continuing to age and, without a program of preemptive cable replacement, that aging will result in a significant decline in reliability. As shown in Figure II-9 and Figure II-10, a run-to-failure approach to managing our cable population would result in an increase in annual SAIDI of approximately 61 minutes and an increase in annual SAIFI of 0.269 interruptions over the next 20 years. As discussed in the previous section, SCE’s approach to dealing with infrastructure aging will be to preemptively replace 500 miles/year of its least reliable cable. Because it constitutes 25% of our cable population, CIC will need to be part of this preemptive cable replacement program.
As already described, replacement of CIC by removing it from its existing tubing has been difficult and often impossible. Historically, projects to “replace” it have involved constructing a new circuit, using rigid duct per SCE’s current standard, in parallel with the existing conductor, and then transferring the load over from the old circuit to the new circuit. We have found this method to be
30

3
4
1
2 very costly. Therefore, SCE has explored alternative methods of replacing CIC. We have arrived at a new strategy which we will put into operation late 2013. This new method will involve a process of lubricating the inside of the CIC duct with specially designed pumping equipment as shown below in
Figure II-18.
7
8
5
6
This cart contains an air compressor, a lubrication fluid pump, an assortment of hoses, and a portable generator. After the conductor inside the CIC tubing has been dislodged and lubricated, very high tensile forces are applied to the cable with a specially designed cable pulling machine as shown below in Figure II-19.
31

1
2
Finally, SCE has ordered specially designed cable from our cable supplier which can be inserted into the existing CIC ducting once the previous conductor has been removed.
32

1
14
15
16
17
10
11
12
13
8
9
6
7
4
5
2
3
This cable is superior to the cable removed, having a longer expected service life due to improved tree retardant crosslinked polyethylene insulation material and an exterior jacket to prevent corrosion of the concentric neutral wires. To facilitate reinstallation of this cable into the vacated duct, the overall diameter of the cable has been made smaller than the removed CIC conductor.
This is achieved by using a copper (which is narrower than aluminum) conductor, flat strap concentric neutrals, and a thin jacket constructed of low friction material.
SCE’s Construction Standards have been revised to specify that removal of the
CIC from its tubing using the newly available equipment is to be the preferred option for replacing CIC.
If removal from the tubing fails, then the default method will be the traditional approach of open cut trenching.
In addition to introducing new methods and tools into its CIC Replacement
Program, SCE has begun to use cable testing as a means to ensure that, in light of the very high cost of replacing it, no CIC is replaced prematurely. (Cable Testing is described in the following section.) CIC cable replaced in 2013 and 2014 will be cable identified based on historical circuit performance and for which Work Orders have already been developed. In 2015 and beyond, all CIC cable replaced will be that which has been concluded to be approaching its end of life via testing using clearly established criteria.
19 SCE intends to test approximately 381 conductor-miles of CIC cable each year. Based on
19 See Workpaper entitled “Criteria for Replacing Tested CIC Cable.”
33

3
4
1
2 failure rates seen thus far, we expect 50% of what is tested to require replacement, or 175 conductormiles per year. Replacement will take place within one year after the testing. CIC testing is being performed on those circuits with the most CIC cable failures (typically more than five failures) during the past three years.
Total
Conductor
Miles
Desert Foothill Banyan 1.6
Desert Palm Springs Mcmanus 1.8
Desert
Desert
Metro East
Metro East
Metro East
Metro East
Metro East
Metro East
Metro West
Palm Springs
Redlands
Covina
Monrovia
Montebello
Ontario
Ontario
Ontario
Compton
Rover
Mutual
Bandit
Rosemont
Lomas
Big Cone
Imbach
Onbord
Superior
1.3
1.2
1.5
1.4
1.8
1.4
1.2
3.1
6
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
Antelope Valley
Santa Barbara
Thousand Oaks
Valencia
Valencia
Valencia
Valencia
Valencia
Huron
Vallecito
Buffer
Centurion
Cross
Mcbean
Nero
Sand Canyon
0.7
0.7
0.6
1.2
2.3
2.3
0.8
2.6
North Coast
North Coast
North Coast
Orange
Orange
Orange
San Jacinto
San Joaquin
San Joaquin
Valencia
Ventura
Ventura
Fullerton
Saddleback
Santa Ana
Menifee
San Joaquin
San Joaquin
Wiley
Gringo
Salvador
Blizzard
Huskie
Dreyer
Ridgemoor
Mussel
Peoples
Total
0.9
3
1.8
2.1
0.6
1.9
2.9
2.3
1.1
50
34

Region District Circuit
Metro West
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
North Coast
Orange
Orange
Orange
Orange
Orange
Orange
Orange
Orange
Rurals
Rurals
Rurals
San Joaquin
Desert
Desert
Desert
Desert
Metro East
Metro East
Metro East
Metro East
Metro East
Metro East
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Metro West
Palm Springs
Palm Springs
Palm Springs
Redlands
Covina
Covina
Covina
Ontario
Ontario
Ontario
Compton
Compton
Compton
Long Beach
Long Beach
Santa Monica
South Bay
South Bay
South Bay
South Bay
South Bay
South Bay
Santa Barbara
Santa Barbara
Thousand Oaks
Thousand Oaks
Thousand Oaks
Thousand Oaks
Thousand Oaks
Valencia
Valencia
Ventura
Ventura
Ventura
Ventura
Ventura
Fullerton
Zinc
Carpoil
Wasp
Kanan
Lindero
Montgomery
Talley
Talley
Caesar
Powell
Corsica
Evita
Highway
Rainbow
Sidewinder
Akron
Fullerton Trinidad
Huntington Beach Hirsch
Saddleback
Saddleback
Saddleback
Doolittle
Martini
Piano
Saddleback
Saddleback
Barstow
Blythe
Ridgecrest
San Joaquin
Punch
Scotch
Inn
Lettuce
Shangrila
Royal Oaks
Total
Sawyer
Brahma
Hereford
Lombard
Bachelor
Bauxite
Chico
Ebony
Grizzley
Bit
Palo Brea
Sheraton
Lugonia
Highnoon
Place
Viaverde
Border
Kingsford
Quinto
Blimp
Mccloud
1.6
2.7
0.9
0.5
7.78
1.3
0.7
2.8
1
1.3
1.6
9.78
6.3
5.99
1.8
1.4
5.4
5.3
0.7
2
1.8
5.08
2.3
2.4
1.7
0.3
2.9
125
3.9
1.1
4.7
5.4
1.5
1.9
0.8
Total
Conductor
Miles
0.8
1.2
1.8
2.3
1.2
7.1
1.5
1.3
1.3
5.1
1.1
0.9
1.1
2
35

22
23
24
25
18
19
20
21
26
27
28
29
30
31
7
8
5
6
3
4
1
2
9
10
11
12
13
14
15
16
17 e) Conclusion
Preemptive replacement of CIC cable is necessary to prevent the decline in reliability forecast in Figures II-9 and II-10. CIC replacement is a part of SCE’s plan to ensure that we are able to restore system reliability to current levels within 20 years.
SCE’s forecast to replace 50 conductor-miles of CIC cable in 2013, 125 miles in
2014, and 175 conductor-miles per year thereafter is modest. 175 miles represents only 1% of our CIC population, (i.e., a replacement cycle of 100 years.)
SCE has worked aggressively to reduce the cost of CIC replacement by introducing new methods and tools for replacement and by introducing a program of cable testing to maximize the return on infrastructure replacement dollars invested.
In its Decision on SCE’s 2012 GRC, the CPUC stated on p. 153:
We expect SCE to carefully document the data collection from this program, as well as other efforts it undertakes to develop a best practice, and most costeffective method, for performing the balance of CIC replacements in the years to come. This information shall be submitted in support of future GRC requests in this category to assist the Commission and to illustrate that ratepayers achieved value from SCE’s “lessons learned.
There have been three significant lessons SCE has learned since the last GRC.
The first has been the difficulty in obtaining easements. At the time of the 2012 GRC our plan had been to install new cable ducts so as to relocate transformers from backyards and out to the curb. What we learned was that is has been extremely difficult to obtain easements from homeowners to run conduits alongside their homes. Despite the benefits of removing a transformer from one’s back yard, the vast majority of requests for easements were rejected. Those that were granted were often very expensive.
The second lesson, although not surprising, has been the wide range in costs of replacing CIC. While unit costs of replacements in highly rural areas are relatively low, the unit cost in urban areas was very high. Unfortunately, most of our CIC is located in urban areas. This is exactly the reason for SCE’s new strategy of reusing the existing CIC duct as discussed at length in the preceeding sections.
The third lesson learned is the potential savings associated with identifying CIC which, while old, still has significant remaining life. This will be described in detail in the following section.
36

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
3.
Testing-Based Cable Life Extension Program a) Description Of Program
The Testing-Based Cable Life Extension Program performs “partial discharge” testing on de-energized segments of underground primary cable in order to assess its remaining service life. Cable segments which test “good” are guaranteed by the testing vendor not to fail in service for at least ten years. Cable segments which test “bad” are scheduled for replacement. b) Necessity Of Program
Prediction of impending cable failure is an inexact science. Neither age nor manufacturer nor failures of proximate cable segments can provide precise estimates of a cable segment’s remaining service life. This imprecision can result in the removal of cable possibly several years prior to when it would have failed and, therefore, less than optimal use of available infrastructure replacement dollars. The need for a more precise way to assess a cable’s remaining life is most acute when the cost of cable replacement is very high, as in the case of CIC. c) Historical And Forecast Spending
Table II-7 and Figure II-21 below indicate SCE’s historic and forecast spending for its Testing-Based Cable Life Extension program.
20
2009
2010
2011
2012
2013
2014
2015
2016
2017
Year Historical/Forecast Forecast Unit Cost
Cable Tested (Nominal dollars x
Total Cost
(Nominal dollars x
2008
(conductor-miles)
2
1,000) 1,000)
$82
0
0
0
40
381
381
762
762
762
$34
$35
$35
$36
$37
$0
$0
$0
$1,361
$12,847
$13,167
$26,892
$27,494
$28,237
20 See Workpaper entitled “Cost of Cable Testing.”
37

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
3
4
1
2
5
In 2008, costs for cable testing were recorded as an Operations and Maintenance expense per then current FERC guidelines. On March 9, 2009, FERC issued a letter, (Docket No.
AC09-27-000), which stated that costs associated with a testing program meeting certain requirements could be capitalized. Cable testing activities under SCE’s Testing-based Cable Life Extension Program adhere to all of the FERC requirements and are, therefore, considered capital expenditures.
21
21 The letter issued by FERC states, in part, “However, cable assessment costs may be capitalized when the assessments are a part of a one-time major rehabilitation project of an electric cable system that results in significant repairs and replacements. Such rehabilitation projects also significantly enhance and increase the life of the electric cable system beyond its original useful life. Cable assessment costs permitted to be capitalized are those incurred subsequent to determining the need for a major rehabilitation program. The purpose of these capitalized cable assessments would generally be to determine the specific location of underground cables that need to be repaired or replaced.”
38

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
23
24 believe it to be cost-effective.
22 In September through December, 2012, SCE piloted the use of “partial discharge” testing to assess the condition of CIC cable segments in circuits with histories of in-service
CIC failures.
23 d) Justification Of Forecast Work
Many utilities across the U.S. perform testing of their underground cables and
This pilot, which tested the radials on three circuits in the city of Irvine and three circuits in the city of Rancho Palos Verdes, was highly successful and informative. As a result of the pilot, we learned that an entire radial section of a circuit (typically 6 to 12 segments) can be tested in a single day by a single mobile test unit supported by three line crews (each crew comprised of two linemen.) This rapid pace means that the customers on typical radials will need to experience only a single planned outage in order for their cable to be tested. We also learned that a single mobile test unit can be expected to test at a rate of approximately 127 conductor-miles of cable per year.
We learned that on these “poorly performing” circuits, approximately 50% of the cable segments were in need of replacement, while the remaining 50% will continue to operate for at least another ten years.
24 Finally, we learned that CIC cable testing can be performed for a total cost on the order of $33,000 per conductor-mile (including the testing vendor, utility crew support, outage planning, traffic control, etc.).
An economic analysis was performed by SCE’s Financial Analysis and Reporting group to quantify the fiscal advantages, if any, of a cable testing program.
25 This analysis compared the net present value of the revenue requirements needed to: (1) test one conductor-mile of CIC cable and then replace only those segments which tested “bad,” and (2) replace one conductor-mile of CIC cable without testing.
For example, if we were to assume that the cost of replacing CIC were
$500,000/conductor-mile, the cost of testing were $30,000 per conductor-mile, that testing were finding
22 E.g.
, NIPSCO, Progress Energy Florida, Progress Energy Carolina, Duke Energy, WE Energies, Puget Sound Energy,
Boone Electric Cooperative, DEMCO.
23 Partial discharge was chosen as the testing methodology best suited to SCE’s needs because it provided credible and reproducible results which could be used to definitively determine in a single, brief, and non-destructive test whether a cable segment did or did not need to be replaced in the near future.
24 Cable segments testing “good” are guaranteed by the testing vendor not to fail in service for at least ten years.
25 This analysis is a rather complicated Excel file and the product of considerable SCE resources. SCE will provide this file to the CPUC upon request on a proprietary basis.
39

1
2
3
4
5
6
50% of the cable to be “good”, and the very conservative assumption that all “good” cable were replaced at exactly ten years in the future, then the NPV comparison factor would be:
NPV of Rev Req to Test and Replace Only “Bad” Cable = 0.82
NPV of Rev Req to Replace All Cable
Running the analysis for a variety of assumptions about the cost of cable replacement and the cost of cable testing, we obtain:
11
12
13
14
9
10
7
8
15
16
17
18
Minimum % of Tested Cable Needing to "Pass" in Order for Testing to be Cost-Effective pass, i.e., avoided costs of replacement, in order for the testing to pay for itself. Percentages of cable
“passing” the test which exceed the amount in the table indicate savings to our customers in avoided replacements.
Cost of Testing Cable
$150,000 cond-mi
$200,000 cond-mi
$300,000 cond-mi
$400,000 cond-mi
$500,000 cond-mi
$600,000 cond-mi
$700,000 cond-mi
$20,000 /cond-mi $30,000 /cond-mi $40,000 /cond-mi
28% 50% 55%
20%
14%
11%
32%
21%
17%
42%
27%
20%
9%
6%
5%
13%
10%
8%
16%
14%
12%
Table II-8 above identifies the minimum percentage of cable segments needing to
The upshot of this is that, given SCE’s current forecasts of CIC replacement costs,
CIC testing costs, and CIC testing results observed thus far, a strategy of testing CIC and replacing only that which tests “bad,” will be more cost-effective than a strategy of replacing all the cable.
Therefore, SCE intends to make all CIC cable replacements performed under the
CIC Replacement Program in 2015 and beyond contingent on having been tested and found to be “bad.”
SCE plans to employ three mobile test units full time in 2013 through 2017 testing CIC cable. In 2015 we intend to add an additional three mobile test units and study the benefits and risks associated with expanding our test and replace strategy to include mainline cable.
40

CIRCUIT NAM E
SHEPHERD
TERRIER
FREEDOM
FAIRWAY
DRISKILL
GAUCHO
COVEVIEW
ELLENWOOD
FELDSPAR
M IRALESTA
APPLETON
BUFFER
TALLEY
CAESAR
CROSS
M CBEAN
NERO
WILEY
CARNEGIE
CORSICA
CROSSON
DIABLO
PONDEROSA
VINEYARD
BOISE
BAYLINER
CHARDONNAY
BREN
CABOOSE
DINER
FIELDGATE
FUERTE
CADDY
OKLAHOM A
OUTRIGGER
TITTLE
GOETZ
NEAPOLITAN
APARTM ENT
ARNEZ
BULDGE
CARRIAGE
COM BAT
HORN
M ARQUIS
M CM ANUS
BOWM AN
SHANGRILA
ANTE
BULLDOG
M ARTINI
PUNCH
KV
16
16
16
16
16
16
12
12
12
16
16
16
16
16
16
16
16
16
16
16
16
16
12
12
12
12
16
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
SADDLEBACK
SADDLEBACK
SAN JOAQUIN
SANTA ANA
SANTA BARBARA
SANTA BARBARA
SOUTH BAY
SOUTH BAY
SOUTH BAY
SOUTH BAY
THOUSAND OAKS
THOUSAND OAKS
THOUSAND OAKS
VALENCIA
VALENCIA
VALENCIA
VALENCIA
VALENCIA
VENTURA
VENTURA
VENTURA
VENTURA
VENTURA
VENTURA
VICTORVILLE
WILDOM AR
WILDOM AR
COVINA
COVINA
COVINA
COVINA
COVINA
FULLERTON
M ERCED
RAILROAD
RAILROAD
WALNUT
NOGALES
GILBERT
FULLERTON CAROLINA
HUNTINGTON BEACH BOLSA
HUNTINGTON BEACH BROOKHURST
M ENIFEE
M ENIFEE
PALM SPRINGS
PALM SPRINGS
PALM SPRINGS
NEWCOM B
NEWCOM B
SANTA ROSA
SANTA ROSA
EISENHOWER
PALM SPRINGS
PALM SPRINGS
PALM SPRINGS
PALM SPRINGS
PALM SPRINGS
RIDGECREST
RIDGECREST
SADDLEBACK
SADDLEBACK
SADDLEBACK
SADDLEBACK
SILVER SPUR
EISENHOWER
SILVER SPUR
THORNHILL
THORNHILL
DOWNS
DOWNS
BORREGO
M OULTON
CHIQUITA
CHIQUITA
M OULTON
M OULTON
LIBERTY
VILLA PARK
SAN M ARCOS
VEGAS
M ARYM OUNT
ROLLING HILLS
CREST
ROLLING HILLS
ROYAL
CHATSWORTH
THOUSAND OAKS
HASKELL
NEWHALL
NEWHALL
HASKELL
NEWHALL
GONZALES
GONZALES
CAM ARILLO
SAN M IGUEL
COLONIA
SATICOY
SAVAGE
CANYON LAKE
PAUBA
DISTRICT NAM E SUBSTATION CITY_OF_SUB Region Name
WEST COVINA
INDUSTRY
INDUSTRY
INDUSTRY
WALNUT
FULLERTON
BREA
HUNTINGTON BEACH
WESTM INSTER
PERRIS
PERRIS
RANCHO M IRAGE
RANCHO M IRAGE
PALM SPRINGS
PALM DESERT
PALM SPRINGS
PALM DESERT
PALM SPRINGS
PALM SPRINGS
RIDGECREST
RIDGECREST
LAGUNA BEACH
LAKE FOREST
M ISSION VIEJO
M ISSION VIEJO
LAKE FOREST
LAKE FOREST
VISALIA
ORANGE
SANTA BARBARA
ORANGE
ORANGE
SAN JOAQUIN
ORANGE
NORTH COAST
GOLETA
PALOS VERDES
TORRANCE
NORTH COAST
M ETRO WEST
M ETRO WEST
RANCHO PALOS VERDES M ETRO WEST
TORRANCE M ETRO WEST
SIM I VALLEY
CHATSWORTH
THOUSAND OAKS
SAUGUS
NEWHALL
NEWHALL
SAUGUS
NEWHALL
OXNARD
OXNARD
CAM ARILLO
VENTURA
OXNARD
SATICOY
VICTORVILLE
CANYON LAKE
RANCHO CALIFORNIA
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
NORTH COAST
DESERT
SAN JACINTO
SAN JACINTO
DESERT
DESERT
DESERT
DESERT
DESERT
RURALS
RURALS
ORANGE
ORANGE
ORANGE
ORANGE
M ETRO EAST
M ETRO EAST
M ETRO EAST
M ETRO EAST
M ETRO EAST
ORANGE
ORANGE
ORANGE
ORANGE
SAN JACINTO
SAN JACINTO
DESERT
DESERT
DESERT
41

13
14
15
16
9
10
11
12
17
18
19
7
8
5
6
3
4
1
2
4.
Underground Oil Switch Replacement Program a) Description Of Program
The Underground Oil Switch Replacement Program replaces those mainline oilfilled switches located in underground structures which we believe are approaching the end of their service lives and pose a threat to both system reliability and public and employee safety. b) Necessity Of Program
Switches are used in the distribution system for opening and closing electrical circuit connections. Switches are found in both overhead and underground circuits, with underground circuits containing both subsurface and padmounted switches.
Subsurface switches are inspected every three years in compliance with G.O. 165.
These inspections include visual examination of the enclosure for corrosion, leaks, and hot connections.
Every six years, every oil-filled switch is subjected to an oil test to check for water ingress. Over 600 switches fed from the underground system were replaced in 2012 as a result of deterioration observed during inspections.
Unfortunately, inspections are not able to detect all imminent failures of switches.
Deterioration of the electrical contacts and other components internal to the switch cannot be detected.
As a result, in-service failures of switches can and do occur. In 2012, 49 mainline oil-filled subsurface switches failed in service. Figure II-22 below indicates the number of mainline oil-filled subsurface switches which have failed in service since 2002.
42

7
8
5
6
9
3
4
1
2
10
11
12
13
In-service failures of oil-filled switches are costly. The cost of replacing a switch after it has failed in service is about 30% more than the cost of a planned replacement.
26 This is because an in-service switch failure is often replaced on an emergency basis with linemen working on premium time.
But, the primary reason for SCE’s program to remove old oil-filled switches is that failures of oil-filled switches can be violent. Arcing across electrical components, (as can occur in older equipment), under oil creates acetylene gas, which is highly explosive. Violent failures of oilfilled equipment can damage adjacent electrical equipment (e.g., cable, transformers, switches), expanding the scope and duration of the outage. Property damage and injuries can also result from violent oil switch failures. Most of our oil-filled subsurface switches are located in concrete structures, typically 10 feet by 15 feet, underneath streets. Violent failures of oil-filled equipment can release enough energy to send the concrete lid of the structure several feet into the air. Needless to say, this has the potential of causing great bodily harm and damaging property.
26 See Workpaper entitled “Cost of Emergency vs. Planned Switch Replacement.”
43

3
4
1
2 c) Historical And Forecast Spending
Table II-10 and Figure II-23 below indicate the number of subsurface oil-filled switches replaced and the recorded spend from 2008 through 2012 and SCE’s forecast replacements and spend from 2013 through 2017.
27
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Number of Mainline Oilfilled Underground
Switches Replaced
86
122
200
200
199
268
264
104
200
200
Forecast Unit Cost for
Switch Only
(no cable)
(Nominal dollars x
1,000)
$46
$47
$48
$49
$51
Total Spend -
Switches Only
(no cable)
(Nominal dollars x
1,000)
$11,773
$13,157
$18,076
$13,299
$4,045
$5,610
$9,425
$9,625
$9,840
$10,106
27 See Workpaper entitled “Cost of Underground Oil Switch Replacement.”
44

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
3
4
1
2 d) Justification Of Forecast Work
Currently, there are about 44,613 subsurface and padmounted switches installed in our underground system. The population of these switches by type, as of the end of 2012, is summarized in Table II-11.
45

Switch Type Population Year-End 2012 Average Age
Mainline Subsurface
Oil
SF6
Vacuum -VAC
Subtotal
Mainline Padmount
PMH
PME
SF6
Subtotal
Radial Padmount
Oil
3,501
12,072
418
15,991
2,280
6,138
108
8,526
2,224
BURD (Radial subsurface)
BURD Oil
Subtotal
BURD SF6
10,765
7,107
17,872
Total 44,613
28
8
6
19
6
7
14
27
6
14
46

1
2 below.
The age distribution of subsurface mainline oil switches is shown in Figure II-24
3
4
5
SCE has performed an engineering analysis of mainline oil-filled switch reliability. For these switches, our analysis concludes the relationship between unreliability and age to be represented by the curve shown in Figure II-25 below.
28
28 See Workpaper entitled “Underground Oil Switch Reliability.”
47

9
10
7
8
5
6
3
4
1
2
This reliability analysis concludes that the mean-time to wear-out is about 35 years. As of the end of 2012, SCE had 3,501 mainline oil-filled subsurface switches remaining in service. In 2017, 821 of these will be 35 years or older; 2,373 will be 30 years or older. SCE believes that it would be prudent to continue its program of preemptively replacing mainline oil-filled subsurface switches with SF6-filled switches (or vacuum switches in some cases) until all have been replaced. We intend to remove these switches at a rate of 122 in 2013 and 200 per year in 2014 – 2017.
5.
PMH-4 Switch Replacement Program a) Description Of Program
The PMH-4 Switch Replacement program replaces those PMH switch types that are believed to pose an unacceptably high risk to operating personnel.
48

P M H T Y P E
N U M B E R IN
IN V E N T O R Y
P M H -4
P M H -5
P M H -6
P M H -8
P M H -9
P M H -10
P M H -11
P M H -12
P M H -13
P M H -14
P M C
U N K N O W N
P M H /P M C
376
190
88
98
165
308
155
28
109
42
106
457
S P E C IF IC P M H T Y P E
P M H -4
P M H -4 CL
P M H -4 S M L
P M H -5
P M H -5 CL
P M H -5 S M L
P M H -6
P M H -6 CL
P M H -6 S M L
P M H -8
P M H -8 CL
P M H -8 S M L
P M H -9
P M H -9 CL
P M H -9 CL-S T A IN LES S S T EEL
P M H -9 S L
P M H -9 S M L - S T A IN LES S S T EEL
P M H -10
P M H -10 S T A IN LES S S T EEL
P M H -11
P M H -11 CL
P M R-11 S M L
P M H -11 S M L-S T A IN LES S S T EEL
P M H -12
P M H -12 CL
P M H -12 S M L
P M H -13
P M H -14
P M H -14 CL
P M H -14 S M L
P M H -14 S M L-S T A IN LES S S T EEL
P M C W IT H F U S E
P M C F U S E S T A T U S U N K N O W N
U N K N O W N P M C
U N K N O W N P M H
T O T A L
49
P opula tion
35
1
0
6
28
109
0
0
7
99
14
443
0
60
93
2
131
2
307
1
85
0
30
2
9
79
0
13
0
66
310
0
33
157
0
2,122

11
16
17
18
19
20
12
13
14
15
9
10
7
8
5
6
3
4
1
2 b) Necessity Of Program
PMH switches are mainline air-insulated padmounted switches whose bushings
(electrical connectors) on the front of the switch are energized (or “hot.”), i.e., live front.
29 There are
2,122 PMHs in SCE’s distribution system representing twelve different designs from two different manufacturers. The inventory of each PMH switch type is shown in below.
Since late 1990s, there have been 36 reported violent failures of PMH switches in the SCE distribution system (about 1% of the PMH population) which occurred during efforts to deenergize a circuit by operating that part of the switch mechanism known as the “fuse position.” Of these failures, 16 occurred on S&C switches and 20 on Scott Engineering switches. The types of switches on which these failures occurred are shown below in Table II-13.
Quantity Type
4 PFC
12 PMH-4
4 PMH-6
2 PMH-8
7 PMH-9
6 PMH-11
1 PMH-12
Several investigations, tests, and evaluations have been performed by both SCE and S&C (the manufacturer) to determine the actual cause of failure. Unfortunately, after many hours of investigation, tests, and evaluations, the cause of these failures remains a mystery. The fact that failures seem to occur in the morning during light loading conditions (less than 2 amperes) is counter-intuitive.
SCE crews have been issued Gary-Guard and Arc-Shield tools to reduce the risk of injury should a flashover occur during switching operations. This, however, is not a complete solution. Switches that pose a hazard to our operating personnel must be replaced. c) Historical And Forecast Spending
Our forecast PMH-4 switch replacements and spending are shown in Table II-14 below.
30
29 In the mid-1990s, SCE’s design standard changed from PMHs to PMEs. A PME is a switch whose bushings on the front switch are “elbow-connected.” PMEs are safer than PMHs. PMEs are “dead front,” i.e., they have no exposed energized conductor. PMHs are “live front,” i.e., there is exposed energized conductor.
30 See Workpaper entitled “Cost of a PMH-4 Switch Replacement.”
50

17
18
19
13
14
15
16
7
8
5
6
3
4
1
2
9
10
11
12
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Year Number of PMH-4 Forecast Unit Cost Total Spend
Switches to be Replaced (Nominal dollars x (Nominal dollars x
1,000) 1,000)
176
0
0
0
186
127
138
200
$3,480
$2,281
$5,754
$17 $3,474
$18 $3,133
$0 $0
$0 $0
$0 $0 d) Justification Of Forecast Work
The highest risk to personnel from PMH switches has come from our PMH-4 and
PFC type switches. This is because, in all other PMH switches, the “fuse position” mechanism can be de-energized by an internal upstream switch. De-energizing the “fuse position” mechanism prior to its operation eliminates the possibility of a flashover. Because the PMH-4 and PFC switches have no internal upstream switch and because safety procedures no longer permit operation of energized fuse position mechanisms, large sections of the circuit must now be de-energized before crews can operate these switches. Essentially, PHM-4 and PFC switches can no longer perform the function for which they were installed. SCE has had a program to replace these switches since 2010. All but 376 PMH-4s have already been replaced.
SCE intends to replace the remaining 376 PMH-4 switches with PME-4 switches by the end of 2014.
6.
Capacitor Bank Replacement Program a) Description Of Program
The Capacitor Bank Replacement Program replaces failed and obsolete capacitor banks and their appurtenant capacitor switches. b) Program Necessity
Capacitor banks are used in our distribution system to regulate the voltage to usable levels by compensating for load inductance. Without adequate numbers of properly operating
51

7
8
5
6
3
4
1
2 capacitor banks, the voltage of electricity supplied to many of our customers could drop to below the
95% of nominal service voltage level that SCE is obligated to provide per its tariff and its Electric
Service Requirements. Inadequate voltage could damage customers’ electrical equipment and appliances. Serious voltage drops resulting from inadequate capacitance could conceivably lead to grid collapse. c) Historical And Forecast Spending
Table II-15 and Figure II-26 below indicate SCE’s historical and forecast spend for its capacitor bank replacement program.
31
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Number of Cap Bank
Replacements
Forecast Unit Cost
(Nominal dollars x
1,000) Completed/Forecast
288
237
359
287
204
350
350
350
350
350
$36
$37
$38
$39
$40
Historical/Forecast
Cost
(Nominal dollars x
1,000)
$5,011
$5,257
$7,667
$8,360
$6,620
$12,731
$13,048
$13,325
$13,623
$13,991
31 See Workpaper entitled “Cost of a Capacitor Bank Replacement.”
52

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
7
8
5
6
3
4
1
2
9
10
11 d) Justification Of Forecast Work
There are two types of capacitor banks on our system, switched and fixed.
Switched capacitor banks turn on and off to accommodate changes in customer load. Fixed capacitor banks are permanently connected to the circuit. Each capacitor bank is composed of three capacitor units, fuses, a rack, and mounting hardware. For switched banks, capacitor switches (either two or three) and a capacitor control are also included.
There are approximately 13,160 capacitor banks in SCE’s distribution system. Of these, about 11,183 are installed in the overhead system (8,388 switched and 2,795 fixed). The other
1,977 are installed in the underground system (1,940 switched and 37 fixed).
A graph showing the age distribution of the overhead capacitor banks is provided in Figure II-27 below.
53

1
2
A graph showing the age distribution of the underground capacitor banks is provided in Figure II-28 below.
54

13
14
15
9
10
11
12
7
8
5
6
3
4
1
2
The expected average time to wear-out of an overhead capacitor bank is assumed to be about 30 years.
32 As of April 2013, approximately 1,350 capacitor banks (about 11% of the population) are currently older than 30 years. Approximately 1,100 of additional capacitor banks (an additional 8% of the population) will reach 30 or more years of age between now and year 2017.
Inspection of the capacitor banks is a part of our preventative maintenance program. Once every five years, each capacitor bank in our system is inspected for proper operation, corrosion, leaking oil, and loose connections. Capacitor banks requiring replacement or repair are recorded and prioritized for follow-up work. Problems with newer capacitor banks usually result in repairs. Problems with older banks, where parts are no longer available and/or where, in the judgment of SCE’s Apparatus Technicians, repairs cannot be made cost-effectively, often result in replacement.
As Table II-14 demonstrates, over the past five years we have been replacing capacitor banks at an average rate of 272 per year. SCE forecasts a need to replace capacitor banks in years 2015 – 2017 at a rate of 350 per year. The reasonableness of this forecast rate is demonstrated by the fact that it is substantially less than the long-term replacement rate of 442 capacitor banks per year that we will eventually see.
32 See Workpaper entitled “Capacitor Banks.”
55

13
14
15
16
9
10
11
12
17
18
19
7
8
5
6
3
4
1
2
7.
Distribution Voltage Regulator Program a) Description Of Program
The Distribution Voltage Regulator Program is proposed to replace failed and obsolete voltage regulators on distribution circuits. b) Program Necessity
Distribution voltage regulators are devices that are used in our distribution system to regulate feeder voltages within a specified range of values. A distribution voltage regulator is essentially a tapped autotransformer on a distribution feeder with adjustment of taps used for voltage regulation purposes. SCE typically installs new distribution voltage regulators in banks of three singlephase units. Like capacitor banks, they are used to help keep the voltage of electricity supplied to customers within voltage levels that SCE is obligated to provide per its tariff. Unlike capacitor banks, regulators are capable of raising or lowering voltage in step increments, typically plus or minus 10% in increments of 5/8% (i.e. 32 taps). Distribution voltage regulators are particularly useful on feeders where normal variations in load on the feeder would otherwise result in undesirable variations in voltage due to feeder losses and voltage drops. c) Historical And Forecast Spending
Heretofore, SCE has not had a program to preemptively replace distribution voltage regulators. Figure II-29 and Table II-16 below indicate SCE’s forecast spend for its distribution voltage regulator replacement program.
33
33 See Workpaper entitled “Cost of a Distribution Voltage Regulator Replacement.”
56

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
57

3
4
1
2
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Number of
Distribution Voltage
Regulator Bank
Replacements
Completed/Forecast
0
0
0
0
2
2
0
2
2
2
Forecast Unit Cost
(Nominal dollars x
1,000)
$255
$262
$267
$273
$281
Historical/Forecast
Cost
(Nominal dollars x
1,000)
$0
$0
$0
$0
$0
$511
$524
$535
$547
$562 d) Justification Of Forecast Work
There are approximately 164 distribution voltage regulators installed on distribution feeders outside of SCE substations. A graph showing the age of these distribution voltage regulators is provided below in Figure II-30.
58

9
10
7
8
5
6
3
4
11
12
13
14
1
2
The expected average time to wear-out of a distribution voltage regulator is assumed to be about 30 years. Approximately 21 distribution voltage regulators (about 13% of the population) are currently older than 30 years.
Inspection of distribution voltage regulators is a part of our preventative maintenance program. Once every five years, each distribution voltage regulator in our system is inspected for proper operation, corrosion, leaking oil, and loose connections. Distribution voltage regulators are also inspected when abnormal voltages are reported by customers on distribution feeders and regulator misoperation is suspected as the cause.
Because of the aging nature of SCE’s existing distribution voltage regulator inventory, the number of existing regulators older than 30 years, and the adverse impact that regulator failure can have on voltages supplied to SCE customers, SCE has identified a need for a preemptive distribution voltage regulator replacement program. Because SCE typically installs new distribution voltage regulators in banks of three single-phase units, a forecast replacement rate of 6 regulators per year will begin to address the oldest distribution voltage regulators in the SCE system at a rate consistent
59

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
23
24
25 with the anticipated long term steady-state replacement rate. Without replacement, the age of these regulators will continue to increase as will the risk of in-service failure.
8.
Automatic Reclosers Replacement Program a) Program Description
The Automatic Recloser Program replaces automatic reclosers (ARs) which have been identified as being obsolete and/or unreliable. b) Program Necessity
Automatic reclosers (ARs) are used in distribution circuits to interrupt the supply of electricity to that portion of the circuit downstream of its location. They act much like a circuit breaker. However, instead of being located at the upstream-most end of the circuit, ARs are typically located out toward the end of the circuit.
ARs are installed for two reasons, the first of which is safety. On long circuits there may be so much impedance in the conductor that if a fault were to occur near the very end of the circuit, the circuit breaker in the substation would not be able to detect it. This would mean that a broken overhead conductor lying on the ground would remain energized creating a serious public hazard. Energized conductors are also a serious fire hazard. ARs are often located on circuits just before the circuit enters an area of dense vegetation.
ARs are also installed to improve reliability. When a fault occurs downstream of an AR, the ARs opens before the circuit breaker in the substation responds to the fault. Only the downstream portion of the circuit is interrupted and all customers upstream of the AR remain energized.
Therefore, ARs reduce the number of customers affected by a downstream fault to a fraction of what it would otherwise have been. c) Historical And Forecast Spending
Figure II-17 and Figure II-31 below indicate SCE’s historic and forecast spend for the AR replacement program.
34
34 See Workpaper entitled “Cost of an Automatic Recloser Replacement.”
60

2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Year
Number of Automatic
Recloser Replacements
Completed/Forecast
17
27
22
24
12
13
30
30
30
30
Forecast Unit Cost
(Nominal dollars x
1,000)
$78
$80
$81
$83
$85
Recorded/Forecast
Cost (Nominal dollars x 1,000)
$1,369
$1,583
$1,536
$1,471
$905
$1,010
$2,388
$2,438
$2,493
$2,560
(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
61

3
4
1
2
5
6 d) Justification Of Forecast Work
We have approximately 1,213 automatic reclosers installed in our distribution system. Of these, approximately 1,175 are in the overhead system and about 38 are in the underground system.
A graph showing the age distribution of the overhead ARs is provided in Figure
II-32 below:
Inventory of Distribution Overhead Automatic Reclosers by Year of Installation
(as of year-end 2012
80
Total = 1175
70
60
50
40
30
20
10
0
7
8
Year
A graph showing the age distribution of the underground ARs is provided as follows in Figure II-33 below:
62

7
6
5
4
3
2
1
0
10
9
8
Inventory of Distribution Underground Automatic Reclosers by Year of Installation
(as of year-end 2012)
Total = 38
12
13
14
7
8
5
6
3
4
1
2
9
10
11
Year
The estimated time to wear-out of an AR is assumed to be about 25 years.
35 This would make the long-term-steady-state replacement rate about 40 replacements per year.
36 There are approximately 249 ARs (about 24% of the population) that are older than 25 years.
The design of ARs has undergone extensive changes since we began installing them. The early ARs were oil-filled. The latest reclosers have a vacuum switch and electronic control arrangement. Many of the oldest ARs are no longer manufactured and cannot be repaired or are of an obsolete design, which cannot be repaired cost-effectively.
9.
PCB Transformers Replacement Program a) Program Description
The PCB Transformer Replacement program replaces distribution line transformers which are suspected of being contaminated with PCB oil. b) Program Necessity
For a period of about 20 years, transformer manufacturers made available to U.S. utilities transformers filled with insulating oil containing PCB. While SCE never ordered any
35 See Workpaper entitled “Automatic Reclosers.”
36 1,042 ARs divided by 25 years = 40 ARs per year.
63

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
23
24
25
26
27 transformers containing PCB oil, many transformers were nonetheless received and installed whose oil was contaminated with PCB.
PCB is believed to pose a threat to public health. Because transformers can leak and can occasionally fail catastrophically, the US-EPA has encouraged all U.S. utilities to remove any transformers containing significant levels of PCB. Furthermore, it is expected that the federal government will ultimately make elimination of PCB-containing equipment a legal requirement.
In the late 1970s, the United States Congress passed the “Toxic Substances
Control Act” which required the federal Environmental Protection Agency (EPA) to write regulations banning the manufacture, processing, distribution in commerce and use of polychlorinated biphenyls
(PCBs).
The EPA’s PCB regulations that were subsequently written provided specific
“authorizations” [40 CFR Part 761.30] allowing electric utilities to continue using transformers and other electrical equipment … “for the remainder of their useful lives” subject to … “Use conditions”
[761.30(a)(1)] and … “Disposal requirements” [761.60].
There are, to date, no federal regulations requiring utilities to proactively remove equipment containing PCBs. However, the U.S. was a participant at the Stockholm Convention on
Persistent Organic Pollutants, which set non-binding goals for the elimination of PCB use in electrical equipment by 2025. We believe that the federal government will ultimately pass legislation requiring all utilities to remove from their systems equipment containing more than 50 PPM of PCB by the year
2025. In April 2010, the EPA published an Advance Notice of Proposed Rulemaking describing its reassessment of PCB use authorizations and its consideration of mandatory removal of all equipment containing PCB at levels greater than 50 ppm.
37
The most substantial challenge that electric utilities have faced since the inception of the PCB regulations is that most transformers require analytical testing to determine if they contain regulated levels of PCBs. And, while the EPA does not require testing as a condition of use, the Agency has a very stringent set of assumption standards [761.2 “PCB concentration assumptions for use”] when levels are unknown. In sum, with few exceptions, all distribution transformers owned by SCE that were
37 Federal Register, Volume 75, No. 66, Wednesday, April 7, 2010, Proposed Rules, pp. 17645 - 17667, “Environmental
Protection Agency, 40 CFR Part 761, Polychlorinated Biphenyls (PCBs) Reassessment of Use Authorization.” http://www.gpoaccess.gov/fr/retrieve.html
64

13
14
15
16
9
10
11
12
17
18
7
8
5
6
3
4
1
2 manufactured prior to July 2, 1979 and whose PCB concentration are unknown must be assumed to contain regulated levels of PCBs (i.e., 50-499 parts per million).
These EPA “assumption” rules pose significant management and liability concerns for SCE. This is due primarily to the fact that the EPA regulates spills and even minor leaks from transformers containing PCBs 50 parts per million or greater as “improper disposal” of PCBs
[761.60]. Under the EPA’s “Penalty Policy”, such improper disposal of PCBs can result in penalties/fines of up to $32,500 per day per incident.
We believe that there are approximately 3,200 older distribution transformers in our system which may contain more than 50 ppm PCBs. If and when older transformers in our system leak and a release of PCBs 50 ppm or greater occurs, even if unknown, SCE is out of compliance with the EPA’s regulations ( i.e
., “improper disposal of PCBs”) and subject to enforcement action. Although
SCE has in place very specific protocol for the proper response and cleanup of PCB spills in accordance with the EPA’s “PCB Spill Cleanup Policy” [761.125] and performs well in that regard, it is virtually impossible to monitor the thousands of older distribution transformers remaining in our system for the presence of minor leaks. c) Historical And Forecast Spending
Table II-18 below indicates SCE’s historical and forecast spending for its PCB-
Contaminated Transformer Replacement program.
38
38 See Workpaper entitled “Cost of PCB-Contaminated Transformer Replacement.”
65

2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
Year
Recorded/Forecast
Replacements of
PCB Transformers
Forecast Unit
Cost of
Replacement
(Nominal dollars)
0
157
152
67
82
250
250
250
250
250
$6,948
$7,121
$7,272
$7,435
$7,636
Recorded/Forecast Cost of
PCB Transformer
Replacements (Nominal $ x
1,000 )
$0
$916
$1,783
$719
$514
$1,737
$1,780
$1,818
$1,859
$1,909
66

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
9
10
11
12
7
8
5
6
3
4
1
2 d) Justification Of Forecast Work
As stated earlier, we believe that the federal government will ultimately pass legislation requiring all utilities to remove from their systems equipment containing more than 50 PPM of PCB by the year 2025.
In light of this, SCE has instituted a PCB-contaminated Transformer replacement program which has, thus far, been highly effective. See Figure II-34 above. Each distribution transformer removed from service (most removals are through our G.O. 165 inspection program) is analyzed for PCB concentration. The PCB concentration is recorded in conjunction with the serial number. Because serial numbers are assigned sequentially during the manufacturing process, transformers whose serial numbers are numerically close are likely to have been filled with the same transformer oil. Operating transformers whose serial numbers are close to those of removed transformers found to be contaminated are then targeted for removal by the PCB-contaminated
67

13
14
15
9
10
11
12
7
8
5
6
3
4
1
2
Transformer Removal program. In 2012, 93% of the targeted transformers were found to contain PCB levels greater than or equal to 50ppm PCB.
Going forward, we assume that roughly 5% of the estimated 3,200 remaining
PCB-contaminated transformers will be removed from service each year as part of routine inspectiondriven replacements. Our PCB-Contaminated Transformer Replacement program, with its forecast replacement rate of 250 transformers per year should eliminate the balance of all PCB-contaminated transformers by 2023.
C.
Substation Infrastructure Replacement (SIR) Program
The Substation Infrastructure Replacement program preemptively replaces major pieces of aging or obsolete substation equipment in order to minimize the negative effect of aging on system reliability, safety, and operability/maintainability. Two functions are overseen by the SIR program: Transformer
Replacement and Circuit Breaker Replacement. An overview of the SIR program is provided in two workpapers, one providing an outline of the program and one describing the process flow.
39
Figure II-35 below provides an overview of our transmission and distribution system and where our AA, A, and B substations fit in.
39 See Workpaper entitled “Substation Infrastructure Replacement Program.”
See Workpaper entitled “Substation Infrastructure Replacement Program Five Year Development Plan Process Flow.”
68

3
4
1
2
5
1.
Transformer Bank Replacement
Substation transformers are major pieces of equipment used to either (a) increase electricity voltage in order to reduce energy losses during its transmission over long distances, or (b) reduce electricity voltage in order to make it more practical for the customer.
SCE has several classes of substation transformers as shown in Table II-19.
69

Primary (high) Voltage Side
500 kV (AA-bank)
220 kV (A-bank)
115 or 66 kV (B-bank)
Number Currently in Service
77
162
2,596
6
7
4
5
8
9
1
2
3 a) AA-Bank Replacement
AA-Bank transformers are located in major substations where they take electricity at the 500kV transmission level and transform it down to 220kv. The SIR program identifies and replaces AA-Bank transformers that are approaching the end of their service lives, that contain parts which are known to be seriously problematic or are no longer available, or that can no longer be costeffectively maintained.
The costs of AA-Bank transformer replacement scheduled for years 2013 through
2017 are all under FERC jurisdiction and are, therefore, not discussed further in this testimony. See
Figure II-36 below.
70

(Constant 2012 and Nominal $000, includes FERC and CPUC jurisdictional expenditures)
9
10
11
12
7
8
5
6
13
14
15
1
2
3
4 b) A-Bank Replacement
(1) Description Of Program
A-Bank transformers are located in major substations where they take electricity at the 220kV transmission level and transform it down to a subtransmission voltage, either
115kV or 66kv. The SIR program identifies and replaces A-Bank transformers that are approaching the end of their service lives, that contain parts which are known to be seriously problematic or are no longer available, or that can no longer be cost-effectively maintained.
(2) Necessity Of Program
The consequences of an in-service failure of an A-Bank transformer are highly undesirable. A-Bank transformers typically supply power to large portions of SCE’s distribution system servicing hundreds of thousands of customers. While redundancy is built into the A-Bank system, an in-service failure would place the system into an “N-1” condition, wherein a second failure or system disturbance could result in a massive blackout affecting significantly large areas. So severe are the consequences of such a blackout that SCE believes that every reasonable precaution must be taken to prevent it.
71

7
8
5
6
3
4
1
2
9
10
11
Although infrequent, in-service failures of A-Bank transformers can be violent. These transformers are oil-filled and catastrophic failures and ensuing fires can endanger the safety of SCE employees and the operability of nearby equipment. Inspections are extremely helpful in identifying many incipient failures. However, because of the speed at which failure mechanisms can arise and progress, inspections cannot prevent all failures. Therefore, planned preemptive replacements under controlled conditions of transformers clearly approaching the end of their service lives is a prudent and responsible action to minimize the risk of in-service failures.
(3) Historical And Forecast Spending
Table II-20 below indicates the number of A-Bank transformers replaced and the recorded spend from 2008 through 2012 and SCE’s forecast work and spend from 2013 through
2017.
40
40 See Workpaper entitled “Cost of Substation Transformer Replacements.”
72

7
8
5
6
9
3
4
1
2
Year
Number of A-Bank
Replacements
Completed/Forecast
Forecast Unit Cost
(Nominal $ x
1,000)
Total Recorded/Forecast
Spend CPUC & FERC
Jurisdictions Combined
(Nominal $ x 1,000)
Total Recorded/Forecast
Spend CPUC Jurisdiction
Only (Nominal $ x 1,000)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
3
(3-phase units)
3
(3-phase units)
3
(3-phase units)
3
(3-phase units)
4
(3-phase units)
3
(3-phase units)
5
(3-phase units)
5
(3-phase units)
5
(3-phase units)
5
(3-phase units)
$4,028
$4,119
$4,228
$4,298
$4,402
$11,235
$13,213
$15,120
$13,193
$13,957
$12,085
$24,712
$21,141
$21,488
$22,011
$11,235
$13,213
$15,120
$13,193
$13,957
$8,057
$20,594
$21,141
$21,488
$22,011
In 2013, the A-Bank replacement at Victor substation is under FERC jurisdiction while the remaining two replacements are under CPUC jurisdiction. In 2014, the A-Bank replacement at Kramer substation is under FERC jurisdiction, while the remaining four replacements are under CPUC jurisdiction. In 2015 – 2017, all A-Bank replacements are under CPUC jurisdiction.
(4) Justification Of Forecast Work
Prior to 2012, SCE identified the volume and specific transformers to be replaced each year largely on the basis of expert judgment, i.e., the judgment of those individuals responsible for maintaining the equipment. Beginning in 2012, formal engineering analysis was incorporated into the evaluation process.
73

3
4
1
2
The initial stage of that engineering analysis was an evaluation of historic removals and failures of substation transformers in order to develop a relationship between age and the probability of in-service failure. That relationship for A-Bank transformers is shown as a Weibull curve in Figure II-37 below.
41
7
8
5
6
9
From this curve, the mean time to wear-out of A-Bank transformers can be shown to be determined to be 37 years.
There are 162 A-Bank transformers in SCE’s system.
42 The age distribution of these transformers is shown in Figure II-38 below. The average age of SCE’s A-Bank transformers is currently 28 years.
41 See Workpaper entitled “Substation Transformer Reliability Model.”
42 Of these 162 transformers, 34 are single-phase and 128 are three-phase.
74

1
2
3
By multiplying the probability of failure by the number of transformers in each age group, the number of transformers expected to reach the end of their service lives over the next ten years can be determined. That forecast is shown in Table II-21 below.
10
11
8
9
6
7
4
5
2013
2014 2015 2016 2017 2018 2019 2020 2021 2022
N um be r of A -B a nk
T ra nsform e rs fore c a st to re a c h e nd of se rvic e life
5 5 5 5 5 5 5 5 5 5
Having determined the number of A-Bank transformers that will need to be replaced each year, what remains is the selection of those transformers whose replacement is most urgent. To accomplish this, SCE developed a process to assess each transformer’s physical condition or
“Health Index.” This Health Index, (which is effectively the inverse of its probability of failure), is a function of a transformer’s age, loading, fault counts, maintenance orders, oil quality, oil dissolved gas analysis results, and manufacturer. In addition to its Health Index, each transformer is evaluated for its
“Criticality” or severity of consequences that would result from an in-service failure. The primary indicator of a transformer’s urgency for replacement is its Risk Ratio, which is a function of its Health
75

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
20
21
22
17
18
19
Index and its Criticality. From this algorithm-derived replacement prioritization, a five-year replacement schedule is drafted.
Two adjustments are made to this draft schedule. The first is made by a team of technical experts (managers and supervisors responsible for maintaining these transformers) to ensure that factors difficult to quantify are incorporated into the prioritization process such that high-risk transformers are not overlooked. A second adjustment to the schedule is made to optimize the construction aspects of the replacements. Planning, work setup, and equipment tear-down at a substation are expensive. Therefore, every effort is made to combine multiple projects (involving transformer replacement, circuit breaker replacement, or some other major work activity) at a substation into a larger single project in order to avoid return visits to that substation within a three-year period.
In summary, the replacement of A-Bank transformers is managed by the
Substation Infrastructure Replacement program which combines engineering analysis and expert judgment to ensure that the appropriate number of A-Bank transformers are replaced each year and that those which are replaced are the most risk-significant.
The names, locations, ages, and reasons for replacement of all A-Bank
Transformers to be replaced each year 2012 – 2017 are provided in workpapers.
43 c) B-Bank Replacement
(1) Description Of Program
B-Bank transformers are typically located in neighborhood substations where they take electricity at the subtransmission level, usually 66kV but sometimes 115kV, transform it down to 33kV, 16 kV, 12 kV, or 4 kV, and then send it out onto distribution circuits to feed polemounted, pad-mounted, or subsurface line transformers.
43 See Workpapers entitled “SIR A-Bank Transformer Replacements - 2012”
“SIR
“SIR
“SIR
“SIR Replacements
76

13
14
15
16
17
9
10
11
12
7
8
5
6
3
4
1
2
The SIR program identifies and replaces B-Bank transformers that are approaching the end of their service lives, that contain parts which are known to be seriously problematic or are no longer available, or that can no longer be cost-effectively maintained.
(2) Necessity Of Program
The consequences of an in-service failure of a B-Bank transformer are highly undesirable. B-Bank transformers typically supply power to multiple distribution circuits and an in-service failure could result in an outage to thousands of customers. Although infrequent, in-service failures of B-Bank transformers can be violent. These transformers are oil-filled and catastrophic failures and ensuing fires can endanger the safety of SCE employees and the operability of nearby equipment. Inspections are extremely helpful in identifying many incipient failures. However, because of the speed at which failure mechanisms can arise and progress, inspections cannot prevent all failures.
Therefore, planned preemptive replacement of transformers approaching the end of their service lives is a prudent and responsible action to minimize the risk of in-service failures.
(3) Historical And Forecast Spending
Table II-22 below indicates the number of B-Bank transformers replaced and the recorded spend from 2008 through 2012 and SCE’s forecast work and spend from 2013 through
2017.
44
44 See Workpaper entitled “Cost of Substation Transformer Replacements.”
77

(CPUC-Jurisdictional $(000)
Year Voltage Class
Number of B-Bank
Transformer
Replacements
Completed/Forecast
Forecast Unit
Cost (Nominal $ x 1,000)
Total Recorded/Forecast
Cost (Nominal $ x 1,000)
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
115kV
66kV
33kV
16kV
12kV
Total
9
16
6
2
1
3
19
4
4
3
3
19
4
4
3
3
19
4
4
3
4
19
7
9
3
0
21
1
4
4
4
13
5
4
2
0
2
3
4
3
3
0
2
4
1
0
2
3
0
0
5
10
12
34
28
30
42
33
33
33
$1,648
$971
$912
$801
$570
$1,685
$992
$932
$819
$583
$1,730
$1,019
$957
$840
$598
$1,758
$1,035
$972
$854
$608
$1,801
$1,061
$996
$875
$623
$5,253
$0
$0
$1,750
$0
$7,003
$2,281
$3,303
$3,115
$0
$225
$8,924
$3,312
$6,156
$0
$1,038
$2,428
$12,934
$14,856
$16,337
$5,412
$1,422
$622
$38,649
$4,496
$11,764
$4,719
$3,571
$4,941
$29,491
$0
$20,381
$912
$3,203
$2,280
$26,776
$6,741
$18,853
$6,524
$7,369
$1,749
$41,236
$5,190
$19,355
$3,827
$3,362
$1,795
$33,529
$5,275
$19,672
$3,890
$3,417
$1,825
$34,079
$5,404
$20,151
$3,985
$3,500
$1,869
$34,909
78

7
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5
6
3
4
1
2
9
10
11
12
All of SCE’s expenditures for B-Bank transformers are under CPUC jurisdiction.
(4) Justification Of Forecast Work
Prior to 2012, SCE identified the volume and specific transformers to be replaced each year largely on the basis of expert judgment, i.e., the judgment of those individuals responsible for maintaining the equipment. Beginning in 2012, formal engineering analysis was incorporated into the evaluation process.
The initial part of that engineering analysis was an evaluation of historic removals and failures of substation transformers in order to develop a relationship between age and the probability of in-service failure. That relationship for B-Bank transformers is shown in Figure II-39 below as a Weibull curve.
45
45 See Workpaper entitled “Substation Transformer Reliability Model.”
79

3
4
1
2
5
From this curve, the mean time to wear-out of B-Bank transformers can be shown to be 57 years.
There are 2,596 B-Bank transformers in SCE’s system.
46 The age distribution of these transformers is shown in Figure II-40 below. The average age of SCE’s B-Bank transformers is 40 years.
46 Of these 2,596 transformers, 930 are single-phase and 1,666 are three-phase.
80

3
4
1
2
By multiplying the probability of failure by the number of transformers in each age group, the number of transformers reaching the end of their service lives in each future year,
2013 – 2022, can be determined. For B-Bank transformers, the average number of transformers reaching the end of their service lives each year over the next ten years is shown below in Table II-23.
Voltage Class 2013
115kV
66kV
3
20
33kV
16kV
12kV
Total
4
9
5
41
2014
3
20
4
6
4
37
2015
3
19
4
4
3
33
2016
3
19
4
4
3
33
2017
3
19
4
4
3
33
2018
3
19
4
4
3
33
2019
3
19
4
4
3
33
2020
3
19
4
4
3
33
2021
3
19
4
4
3
33
2022
3
19
4
4
3
33
9
10
11
12
7
8
5
6
Having determined the average number of B-Bank transformers that will need to be replaced each year, what remains is the selection of those transformers whose replacement is most urgent. To accomplish this, SCE developed a process to assess each transformer’s physical condition or “Health Index.” This Health Index, (which is effectively the inverse of its probability of failure), is a function of a transformer’s age, loading, fault counts, maintenance orders, oil quality, oil dissolved gas analysis results, and manufacturer. In addition to its Health Index, each transformer is evaluated for its “Criticality” or consequences that would result from an in-service failure. The primary indicator of a transformer’s urgency for replacement is its Risk Ratio, which is the product of its Health
81

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2
17
18
19
20
21
22
23
24
Index and its Criticality. From this algorithm-derived replacement prioritization, a five-year replacement schedule is drafted.
Two adjustments are made to this draft schedule. The first is made by a team of technical experts (managers and supervisors responsible for maintaining these transformers) to ensure that factors difficult to quantify are incorporated into the prioritization process such that high-risk transformers are not overlooked. A second adjustment to the schedule is made to optimize the construction aspects of the replacements. Planning, work setup, and equipment tear-down at a substation are expensive. Therefore, every effort is made to combine multiple projects (involving transformer replacement, circuit breaker replacement, or some other major work activity) at a substation into a larger single project in order to avoid return visits to a substation within a three-year period.
In summary, the replacement of B-Bank transformers is managed by the
Substation Infrastructure Replacement program which combines engineering analysis and expert judgment to ensure that the appropriate number of B-Bank transformers are replaced each year and that those which are replaced are the most risk-significant.
The names, locations, ages, and reasons for replacement of all B-Bank
Transformers to be replaced each year 2012 – 2017 are provided in workpapers.
47
In its Decision on SCE’s 2012 GRC, the CPUC stated on p. 155:
“ We expect that SCE will continue to make 30 replacements annually through 2014. To assist the
Commission, SCE shall document the replacements performed and submit the names, locations, and ages of the replaced transformers in support of future GRC requests in this category.”
Due to the late receipt of the 2012 GRC Decision and its funding authorization, SCE was able to replace only 28 B-Bank transformers instead of the 30 originally planned. The Workpapers cited above are responsive to the Commission’s request for the names, locations, and ages of B-Bank transformer replacements.
47 See Workpapers entitled “SIR B-Bank Transformer Replacements - 2012 Rev 1”
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11
12
13
14
7
8
5
6
3
4
1
2
2.
Circuit Breaker Replacement
Circuit breakers are major pieces of equipment used to interrupt the flow of electricity through a transmission or distribution circuit. Circuit breakers are essential in preventing equipment damage and public injury when faults occur in their downstream circuits.
SCE has several major classes of circuit breakers:
Currently Service
500
115 (distribution)
1,522
4.8 – 2.4 kV (distribution) 1,400
83

(Constant 2012 and Nominal $000, includes FERC and CPUC jurisdictional expenditures)
7
8
5
6
3
4
1
2
9
10
11
12
13 a) Bulk Power Circuit Breaker Replacement
Bulk power circuit breakers interrupt the flow of electricity in transmission lines at the 500kV and 220kV voltage levels. The SIR program identifies and replaces bulk power circuit breakers that are approaching the end of their service lives, that contain parts which are known to be seriously problematic or no longer available, or that can no longer be cost-effectively maintained.
The replacement of bulk power circuit breakers is completely under FERC jurisdiction and is, therefore, not discussed further in this testimony. b) Distribution Circuit Breaker Replacement
(1) Description Of Program
Distribution circuit breakers are typically located in residential and commercial area substations (“B” substations) where electricity is transformed from a subtransmission level voltage, usually 66kV but sometimes 115kV, down to a distribution level voltage of either 33kV,
16 kV, 12kV, 4 kV, or 2.4kV. The Distribution Circuit Breaker Replacement program identifies and
84

13
14
15
16
9
10
11
12
7
8
5
6
3
4
1
2 replaces breakers that are approaching the end of their service lives and therefore becoming increasingly unreliable, that contain parts which are known to be problematic or unavailable, or that can no longer be cost-effectively maintained.
(2) Necessity Of Program
Circuit breakers perform the critical function of “turning off” the flow of electricity to a circuit which has encountered a “problem.” These “problems” are typically events which result in conductors coming into contact with the ground, i.e., “faults.” These faults, left unmitigated, would allow massive amounts of energy to be drawn through the upstream portion of the circuit destroying the conductor/cable, distribution switches, and substation buses and transformers. Most importantly, faulted conductors which remain energized are serious hazards to the public. Circuit breakers must operate quickly. A properly functioning circuit breaker is expected to detect the overcurrent condition and isolate the circuit is less than one-tenth of a second.
(3) Historical And Forecast Spending
Table II-24 indicates the number of distribution circuit breakers replaced and the recorded spend from 2008 through 2012 and SCE’s forecast work and spend from 2013 through
2017.
48
48 See Workpaper entitled “Cost of Distribution Circuit Breaker Replacements.”
85

(CPUC-Jurisdictional $(000)
Year Voltage Class
Number of Circuit
Breaker
Replacements
Completed/Forecast
Forecast Unit
Cost (Nominal
$ x 1,000)
Total
Recorded/Forecast
Cost (Nominal $ x
1,000)
1
2
3
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
115 - 66kV
33 - 2.4kV
Total
35
31
35
139
64
38
75
28
38
52
44
155
46
173
45
187
45
187
45
187
66
174
102
103
90
199
219
232
232
232
$209
$110
$214
$112
$220
$115
$223
$117
$229
$120
$5,576
$3,450
$9,026
$5,576
$10,649
$16,225
$11,238
$3,719
$14,957
$15,977
$3,334
$19,311
$7,122
$5,650
$12,772
$9,211
$17,012
$26,223
$9,846
$19,413
$29,259
$9,888
$21,542
$31,430
$10,050
$21,895
$31,945
$10,295
$22,428
$32,723
(4) Justification Of Forecast Work
Prior to 2012, SCE identified the volume and specific circuit breakers to be replaced each year largely on the basis of expert judgment, i.e., the judgment of those individuals
86

3
4
1
2
5
6 responsible for maintaining the equipment. Beginning in 2012, formal engineering analysis was incorporated into the evaluation process.
Part of that engineering analysis was an evaluation of historic removals and failures of circuit breakers in order to develop a relationship between age and the probability of inservice failure. That relationship for distribution circuit breakers is shown below in Figure II-42 as a
Weibull curve.
49
7
8
9
From this curve, the mean time to wear-out of distribution circuit breakers was determined to be 48 years. There are 10,822 distribution circuit breakers in SCE’s system, of which
3,826 breakers are either 115kV or 66kV and 6,996 breakers are 33kV through 2.4kV. The average age
49 See Workpaper entitled “Substation Circuit Breaker Reliability Model.”
87

3
4
1
2 of the population of 115kV – 66kV circuit breakers is 18 years. The average age of the population of
33kV – 4kV circuit breakers is 32 years.
The distribution of the 115kV – 66kV circuit breakers by year of installation is shown below in Figure II-43.
5
6
The distribution of the 33kV – 2.4kV circuit breakers by year of installation is shown below in Figure II-44.
88

3
4
1
2
5
By multiplying the probability of failure of distribution circuit breakers
(shown in Figure II-40) by the number of circuit breakers in each age group, the number of circuit breakers reaching the end of their service lives in each future year, 2013 – 2022, can be determined. For
115kV – 66kV circuit breakers, the average number of circuit breakers reaching the end of their service lives each year over the next ten years is provided below in Table II-25.
6
7
Circuit Breaker Voltage 2013
115 Ͳ 66 kV 44
2014
45
2015
46
2016
47
2017
48
2018
50
2019
50
2020
51
2021
51
2022
52
For 33kV – 2.4kV circuit breakers, the average number of circuit breakers reaching the end of their service lives each year over the next ten years is forecast in Table II-26 below.
89

13
14
15
16
17
9
10
11
12
7
8
5
6
3
4
1
2
22
23
24
18
19
20
21
Circuit Breaker Voltage 2013
33 Ͳ 2.4
kV 206
2014
206
2015
205
2016
205
2017
203
2018
201
2019
199
2020
194
2021
190
2022
185
Having determined the average number of circuit breakers that will need to be replaced each year, what remains is the selection of those circuit breakers whose replacement is most urgent. To accomplish this, SCE developed a process to assess each circuit breaker’s physical condition or “Health Index.” This Health Index, (which is effectively the inverse of its probability of failure), is a function of a circuit breaker’s age, number of operations, number of faults experienced, the type of mechanism, the number of corrective maintenance orders, and results of oil analysis if applicable. In addition to its Health Index, each circuit breaker is evaluated for its “Criticality” or consequences that would result from an in-service failure. The primary indicator of a circuit breaker’s urgency for replacement is its Risk Ratio, which is a function of its Health Index and its Criticality.
From this algorithm-derived replacement prioritization, a five-year replacement schedules are drafted.
Two adjustments are made to these draft schedules. The first is made by a team of technical experts (managers and supervisors responsible for maintaining these circuit breakers) to ensure that factors difficult to quantify are incorporated into the prioritization process such that highrisk circuit breakers are not overlooked. A second adjustment to the schedule is made to optimize the construction aspect of the replacements. Planning, work setup, and equipment tear-down at a substation are expensive. Therefore, every effort is made to combine multiple projects (involving transformer replacement, circuit breaker replacement, or some other major work activity) at a substation into a larger single project in order to avoid return visits to a substation within a three-year period.
In summary, the replacement of distribution circuit breakers is managed by the Substation Infrastructure Replacement program which combines engineering analysis and expert judgment to ensure that the appropriate number of circuit breakers are replaced each year and that those which are replaced are most risk-significant.
The names, locations, ages, and reasons for replacement of all Circuit
Breakers to be replaced each year 2012 – 2017 are provided in workpapers.
50
50 See Workpapers entitled “SIR CB 33 – 4kV Replacements - 2012”
“SIR –
( Continued )
90

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9
10
11
12
17
18
19
7
8
5
6
3
4
1
2
In SCE’s 2012 GRC Decision, p. 156, the CPUC stated: “We expect SCE to replace 175 distribution circuit breakers within the authorized funding in 2012 and report on this activity in the next GRC.”
SCE was able to replace only 90 distribution circuit breakers in 2012 due to the late receipt of the 2012 GRC decision.
D.
4kV Circuit Replacement
1.
Overview Of 4kV System
There are approximately 4,600 distribution circuits in SCE’s system, fed by about 727 substations. Most of these circuits operate at modern standard voltages of either 12 kV, 16 kV, or 33 kV. But, approximately 1,100 of our circuits (and 211 substations) operate at voltages of 4kV or lower.
4kV is the voltage for which circuits were designed over one hundred years ago, when electricity consumption by each customer was substantially lower than today. With the continually growing demand for electricity from each customer, 4kV circuits present significant operational challenges today.
First, 4kV circuits have limited capacity. The typical 4kV circuit is capable of delivering only about 2.4 MW of power to its customers (due to the physical limitations of its cable, conductors, and equipment.) This is approximately one-fifth the amount of power that can be delivered by a modern
12kV circuit and approximately one-seventh the power that can be delivered by a 16kV circuit.
Second, by today’s standards 4kV circuits are inefficient and wasteful. Because they require three times more current (amps) to supply the same amount of power as a 12kV circuit, and
Continued from the previous page
CB –
CB –
CB –
CB 4kV
“SIR CB 115 - 66kV Replacements - 2012”
“SIR CB 115 - 66kV Replacements - 2013”
“SIR CB 115 - 66kV Replacements - 2014”
“SIR CB 115 - 66kV Replacements - 2015”
“SIR CB 115 - 66kV Replacements - 2016”
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30
22
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24
25
17
18
19
20
21
13
14
15
16
9
10
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12
7
8
5
6
3
4
1
2 because the heat losses from a distribution line are a function of the square of the current, the losses from a 4kV circuit are nine times greater than those from a 12kV circuit supplying an equivalent load.
Third, 4kV circuits are comprised of equipment designed and built many decades ago.
Many 4kV circuits are fed by substation equipment which are obsolete and for which no replacements are available or installable.
Finally, 4kV circuits often lack flexibility in responding to outages. In areas served by
12kV circuits, the circuits are usually interconnected. If one of these circuits sustains a fault, then the faulted part of that circuit can be isolated and the rest of the circuit can be connected to an adjacent circuit. This means that many customers can be re-energized long before the fault is repaired. However, most 4kV circuits are not tied together in large interconnected networks. They are typically found in small isolated groups surrounded by 12kV circuits. Because it is not possible for a 4kV circuit to connect to a 12kV or 16 kV circuit, when a 4kV circuit sustains a fault the entire circuit will often remain without power until the repair is completed. This inability of many 4kV circuits to be fed from adjacent circuits will become more of a challenge to reliability as infrastructure ages and the number of faults increases.
2.
4kV Circuit Overload-Driven Cutover Program a) Description Of Program
The 4kV Circuit Overload-Driven Cutover program is SCE’s response to the growth of load on 4kV circuits. This work involves permanently transferring the outer-most sections of a 4kV circuit over to a neighboring 12 or 16kV circuit. The effect is that the 4kV circuit is reduced in size and load while the neighboring 12 or 16kV circuit increases in size and load. b) Necessity Of Program
Customers are increasing the amount of electricity they are using due to a variety of reasons, (e.g., installation or increase of air conditioning, purchase of new electrical appliances and devices, home remodeling, etc.).
When the load required by all the customers on a 4kV circuit approaches the limit of what the circuit can handle, there are four options.
First, we could ignore the problem. This option would result in an overload condition causing either the circuit breaker to trip or equipment to fail. In either case, reliability and customer satisfaction would decline.
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13
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16
9
10
11
12
17
18
19
7
8
5
6
3
4
1
2
20
21
22
Second, we could implement rolling blackouts during high load conditions. This option would involve deliberately cutting-off customers located toward the end of the circuit, whenever there is a high load situation, in order to prevent a trip of the entire circuit or to ensure that equipment is not damaged by overloading. As in the previous option, this will result in the decline of reliability and customer satisfaction.
Third, we could increase the capacity of the circuit. This option would involve wholesale replacement of the entire 4kV circuit and substation. It would involve constructing a new circuit in parallel with the existing circuit, constructing a new substation in parallel with the existing substation, transferring all customers over to the new circuit, and dismantling the old circuit. This option would be physically impossible for most 4kV circuits since there would no place available to build another substation and unnecessarily expensive.
Fourth, we could perform a partial circuit “cutover.” A partial circuit cutover involves “cutting off” some of the outer-most sections of the overloaded 4kV circuit and reconnecting those “cut off” sections to neighboring 12kV or 16kV circuits. This reduces load on the 4kV circuit to within its capacity and transfers that load over to 12 or 16kV circuits which typically have excess capacity. We believe this to be the most cost-effective option. This typically requires replacement of all line transformers, older wood poles, and conductors. From the perspective of both reliability and lifecycle cost, performing a partial circuit cutover is the most attractive option for dealing with overloaded
4kV circuits and the one we have selected. c) Historical And Forecast Spending
Table II-27 below provides the historical and forecast units and costs of 4kV circuit overload-driven cutovers.
51
51 See Workpaper entitled “Cost of a 4kV Circuit Overload-driven Cutover.”
93

94

( 100% CPUC-Jurisdictional Constant 2012 and Nominal $000 )
10
11
8
9
6
7
4
5
1
2
3
SCE spent less than what was authorized in 2012 for 4 kV overload-driven cutovers as shown in Figure II-45 above. The reason for this was that the 2012 Decision was received so late in the year that the work could not be planned and executed in time. d) Justification Of Forecast Work
SCE monitors the loading on each of its 4kV circuits and substations (as well as all its circuits and substations) and, using best estimates of future load increases, produces a forecast of when circuits would be overloaded during a period of high demand (i.e., a one-in-ten year heat storm).
Our current forecast over the next 20 years of the total 4kV circuit overload (in terms of amps) is provided below in Table II-28. This table indicates the number of amps beyond circuit capacity that will be added each year. These over-capacity amps added each year for the next 40 years are shown graphically in Figure II-46 below:
95

Year Total Amps Cumulative Amps
2013
2014
2015
2016
2017
2018
2019
15,416
315
795
554
998
1,506
2,006
15,416
15,731
16,526
17,080
18,078
19,584
21,590
2027
2028
2029
2030
2031
2032
2020
2021
2022
2023
2024
2025
2026
2,213
1,935
3,576
1,750
3,658
1,634
1,252
2,702
1,585
2,178
1,471
3,596
470
22,842
25,544
27,129
29,306
30,777
34,373
34,843
37,056
38,991
42,567
44,317
47,974
49,608
1
2
The upshot of this forecast is that SCE will need to have offloaded a total of
18,000 amps by the end of 2017.
96

5
6
7
3
4
1
2
Due to the delay in receipt of our 2012 GRC Decision and the uncertainty in overall funding levels, we will be able to cut over only 2,080 amps in 2013. In 2014 and each year 2015
– 2017, SCE will need to cut over about 2,500 amps per year in order to reduce the likelihood of rolling blackouts in the event of a one-in-ten year heat storm to the acceptable level specified in our design standards.
The 4kV circuits from which excess load will be removed via cutovers each year
2013 – 2017 are listed in Table II-29through Table II-33.
Substation Name Circuit Cutover Amps Circuit Name
San Vicente 190 Regent
Upland
Fair Oaks
Sharon
Clark
Stirrup
Cudahy
Sharon
Fairfax
139
130
127
123
115
110
110
108
Klusman
Piedmont
Dyer
Decca
Nancy
Senga
Brookhill
Sweetzer
Granada
Sunnyside
Cudahy
Brewster
Newmark
Rivera
La Canada
Ganesha
Fairfax
Newmark
108
108
104
92
92
90
89
86
86
73
Roanoke
Adair
Hartle
Alberta
Kenmore
Sunglow
Montrose
Ramsey
Gilmore
Riggin
97

Substation Name Circuit Cutover Amps Circuit Name
Badillo 86 Foxdale
Mayflower
Topaz
83
80
Owl
Spinel
Stirrup
Temple
Clark
Badillo
Rivera
Bedford
San Gabriel
Sharon
80
80
78
76
75
70
69
68
Eastfield
Cloverly
Fanwood
Woodside
Regina
Rebel
La Presa
Mayfield
Ravendale
San Gabriel
Bartolo
Bedford
San Vicente
Arcadia
Bedford
Lakewood
Olympic
Monrovia
Amador
Monrovia
Temple
Somerset
Dolores P.T.
Daisy
Naples
Brewster
China Ranch P.T.
68
66
66
65
60
56
55
50
45
40
40
30
177
148
101
112
112
109
4
Endicott
Del Mar
Bexley
Magnetic
East Montana
Joyce
Squires
Carfax
Smithwood
Commercial
Arden
Myrtle
Nadine
Dunbar
Dolores
Dot
Prospect
Vita
China Ranch
98

Substation Name Circuit Cutover Amps Circuit Name
Alhambra 80 Commonwealth
Rivera
Woodruff
153
152
Maxine
Dunrobin
Michillinda
Manhattan
Arro
Woodruff
Michillinda
Ramona
Downey
Arro
110
97
129
126
133
132
124
120
Track
No Beach
Mountain
Alondra
Cole
Guest
Paramount
Alexander
Manhattan
Naples
Oldfield
Arro
Belmont
Ramona
Beverly
Morningside
Clark
Arcadia
Fair Oaks
85
121
82
108
105
110
133
74
126
106
95
Hill
Toledo
Bentree
Pershing
Elko
Sarah
Alden
Manchester
Josie
Acorn
Sacramento
99

Substation Name Circuit Cutover Amps Circuit Name
Clark 103 Metz
Downey
Lakewood
102
101
Avon
Viking
Downey
Howard
Walteria
Beverly
Walteria
Clark
Olympic
Sunnyside
Brewster
96
96
89
93
92
107
62
90
61
Otto
Denker
Codona
Oakhurst
Ridgeland
Stevely
Lasky
Killdee
Platt
Michillinda
Anita
Ramona
Newmark
Hedda
Naomi
Ivar
South Gate
Cudahy
Granada
Broadway
Anita
Floraday
Ditmar
Mayflower
Greenhorn
Palos Verdes
Alhambra
Papaya P.T.
83
87
106
85
103
55
79
78
72
66
71
90
69
73
85
44
68
87
17
Woolley
Fiesta
Hellman
Ackley
Rocket
Clemont
Noel
Missouri
Liberty
Cordova
Trimble
Manor
Jessup
Borden
Ashmont
Pascoe
Major
Brunner
Papaya
100

Ontario
Kempster
Sunnyside
Fairfax
Somerset
Longdon
Ditmar
Belding
Los Cerritos
Pomona
Ravendale
Culver
Duarte
Los Cerritos
Upland
Culver
Ravendale
Euclid
Pomona
Beverly
Howard
Monrovia
Ditmar
Lucas
Oldfield
Euclid
Amador
Downey
Cudahy
Bowl
Los Cerritos
South Gate
Oldfield
Amador
Ramona
Hedda
Michillinda
Garfield
Floraday
Fruitland
Ravendale
Substation Name Circuit Cutover Amps Circuit Name
South Gate
Woodruff
62
62
Evergreen
Ferina
Woodruff
Perry
Rolling Hills
Davidson City
64
59
59
51
Alma
Talent
Orchid
Wise
Pearl
Ontario
Sunnyside
Beverly
La Canada
Costa Mesa
Lakewood
Granada
41
58
70
65
68
50
64
60
Ashland
Curran
Raton
Maple
Lane
Cliff
Shipway
Elgin
51
49
46
56
45
59
45
48
44
51
44
53
52
51
39
38
38
33
46
Harkness
Faculty
Market
Galvin
Cogswell
Nash
Sales
Norman
Canton
Webbwood
Dollar
Bayse
Mayfair
Fidler
Altura
Grevelia
Kenney
Moore
Myda
39
47
38
37
34
25
36
44
29
39
39
38
39
31
38
27
36
35
34
33
28
38
Nocta
Rochholtz
Osgood
La Brea
Amos
Charity
Pullman
Mccallum
Wardlow
Thomas
Kinghurst
Goldwyn
Bonnie
Eldridge
Colburn
Stevens
Tamworth
Village
Garey
Rodeo
Wagner
Ivy
101

9
10
11
12
13
14
7
8
5
6
3
4
1
2
3.
4kV Substation Elimination Program a) Description Of Program
The 4kV Substation Elimination Program will address the growing and serious problem of aging of 4kV substation equipment by transferring (i.e., cutting over) all of a substation’s
4kV circuits to neighboring 12kV or 16kV circuits. This will eliminate the need to replace the 4kV substation equipment under the Substation Infrastructure Replacement program. b) Necessity Of Program
There are about 666 B-substations in SCE’s distribution system. Of these, 211 are at a voltage of 4kV or lower. As previously stated, 4kV was a design standard established over one hundred years ago.
Table II-34 below lists some of our 4kV substations containing the oldest transformers and circuit breakers. The purpose of including this table is simply to provide objective evidence for SCE’s assertion that its 4kV system is very old. As can be seen, there are 36 substations with transformers 80 years old or older, most with circuit breakers over 50 years old.
102

Substation
Naples
Lynwood
Grangeville
Ditmar
Cedarwood
Pioneer
Gage
Culver
Amador
Sharon
Playa
Montecito
Haveda
Graham
Doheny
Beaumont
Modoc
Sangar
Hedda
Ganesha
Wave
Lancaster
Imperial
Sepulveda
San Vicente
Porterville
Perry
Lindsay
Bicknell
Topanga
Pearl
Morningside
Linden
Lawndale
Fairfax
Cypress
Norco
Daisy
Santa Barbara
Lunada
Tulare
Windsor Hills
Ventura
Hanford
Brewster
Lennox
Exeter
Fremont
Corona
Visalia
Oldest Circuit
Breaker Age (years)
45
54
56
52
65
57
55
57
57
52
56
56
55
57
57
57
56
56
55
49
56
56
65
56
57
53
65
56
54
55
57
65
56
65
19
57
55
66
51
58
56
48
57
48
56
57
57
58
88
19
Oldest Transfomer
Age (years)
73
73
72
76
76
75
72
71
71
76
76
76
76
82
81
76
83
83
83
82
83
83
83
84
84
84
83
84
84
84
85
85
85
84
85
85
85
87
86
86
85
88
88
87
90
89
89
89
88
88
Substation
Delano
Somerset
Westgate
Maywood
Edgewater
Broadway
Bowl
Arch Beach
Newmark
Bedford
Sunnyside
Rubidoux
Rialto
Pomona
Perez
Moneta
Los Cerritos
Garvey
Flanco
Redondo
West Barstow
Oxnard
Garfield
Bristol
Arroyo
Repetto
Alhambra
Tippecanoe
Palos Verdes
Olympic
Naomi
Lucas
Inglewood
Cudahy
Bullis
Bartolo
Artesia
Rivera
Larder
Davidson City
Anita
Edgemont
Bryman
Kempster
Sullivan
Badillo
Porter
Ontario
Hoyt
Euclid
Oldest Circuit
Breaker Age (years)
56
56
55
54
55
57
83
57
57
57
58
49
55
40
40
43
44
60
40
57
55
57
54
52
57
53
57
56
57
60
57
56
57
58
66
55
56
53
55
58
56
58
57
59
57
66
56
57
49
63
Oldest Transfomer
Age (years)
62
62
62
62
62
62
61
61
61
62
62
62
62
64
63
63
64
64
64
64
65
64
64
65
65
65
65
65
65
65
66
65
65
65
66
66
66
66
66
66
66
67
67
67
69
68
68
68
67
67
103

7
8
5
6
3
4
1
2
9
10
11
Many 4kV transformers and switchgear are expected to wear out and fail in the near term. SCE has only three options. The first is to wait until the switchgear fails in service. This could result in large and prolonged outages. We believe our customers would regard this approach unfavorably.
The second option is to replace existing 4kV equipment with modern 4kV equipment. In many cases, this will be the preferred option. However, in many other cases this will be highly impractical. Many substations, built decades ago, were constructed inside small buildings. These buildings are so small as to make it uncertain how, and even if, new equipment could be fit into the building. Modern equipment is typically larger than equipment manufactured 60 – 80 years ago. Figure
II-47 through Figure II-49 below are photographs of representative 4kV substations with limited inside space that will make replacement of equipment very difficult.
104

105

9
10
11
12
13
7
8
5
6
3
4
1
2
A third factor making replacement of this aging 4kV equipment unattractive is the fact that many 4kV substations are “islanded,” i.e., there is no way to feed its circuits from adjacent circuits. Therefore, there is no practical way to provide power to its customers while the substation’s equipment is being replaced.
Finally, rebuilding a substation with new 4kV equipment would only perpetuate a system design known to be archaic and inadequate for serving our customers. Our 4kV circuits deliver inadequate power, experience voltage stability problems, and lack the flexibility to interconnect to other circuits which is needed to provide reliability. Replacing 4kV substation equipment would be akin to installing a new engine in an rusted old car, i.e., a poor long-term investment.
The third option in dealing with aging 4kV substation equipment is to eliminate the 4kV substation entirely and transfer all of its circuits to adjacent 12kV or 16kV circuits fed from other substations. This option prevents in-service failure of equipment, obviates the need for emergency repairs, solves future problems with inadequate 4kV circuit capacity, enhances reliability by increasing
106

9
10
11
12
13
14
7
8
5
6
3
4
1
2 the number of circuit interconnections available to restore power following outages, and does so permanently.
We believe that the best long term solution to the growing problem of aging equipment in many of our 4kV substations is that of eliminating these substations by transferring their circuit to neighboring 12kV or 16kV circuits, via complete circuit cutovers. c) Historical And Forecast Spending
Table II-35 through Table II-39 below indicates SCE’s forecast volume and spend to eliminate 4kV substations.
52 It should be noted that there are two phases of work associated with each 4kV substation elimination. The first phase is the cutover of all the 4kV circuits fed by the substation. The second phase is the removal of the unutilized 4kV equipment and buildings located in the substation as well as any necessary soil remediation. Typically, these phases will be completed in different years. In some cases, the substation feeds both 4kV circuit and 16kV circuits. In those cases, only the unutilized 4kV equipment will be removed in the second phase and the 16kV equipment will remain.
Year Substation
2013 Hanford
Hemet
San Jacinto
Wilde
Type of Project
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Harper Lake Cut over all circuits
Daggett
Divisadero
Cut over all circuits
Remove unutilized property
Mooney
Zuma
Rindge
Camar
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Edgemont
Tulare
Carpenteria
Elsinore
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Total
Peak 4kV
Amps
(Criteria Proj.
Load)
Unit Cost
(Nominal $ x 1,000)
Forecast
Cost
(Nominal $ x 1,000 )
637
379
390
124
31
64
$10
$10
$10
$10
$10
$10
$1,022
$1,022
$255
$255
$255
$255
$255
$255
$255
$6,509
$3,873
$3,985
$1,267
$317
$654
$1,022
$1,022
$255
$255
$255
$255
$255
$255
$255
$20,436
Coordination with 4kV Circuit
Overload-Driven Cutovers
52 See Workpaper entitled “Cost of 4kV Substation Elimination.”
107

Year Substation
2014 Porter
Griswold
El Porto
Edgewater
Bristol
Idyllwild
Maywood
Hanford
Hemet
San Jacinto
Wilde
Type of Project
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over portion
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Peak 4kV
Amps
(Criteria Proj.
Load)
966
892
956
318
214
277
228
Unit Cost
(Nominal $ x 1,000)
Forecast
Cost
(Nominal $ x 1,000 )
$10
$10
$10
$10
$10
$10
$10
$262
$262
$262
$262
$10,116
$9,341
$10,011
$3,330
$2,241
$2,901
$2,388
$262
$262
$262
$262
Coordination with 4kV Circuit
Overload-Driven Cutovers
Coincident w/ Griswold.
Coincident w/ Porter.
Current load is 636 amps. Half will be cut over under Rule 20.
Current load is 1,788 amps. Portion to be cut over in 2014
Total
Harper Lake Remove unutilized property
Daggett Remove unutilized property
$262
$262
$262
$262
$41,889
108

Year Substation
2015 Maywood
Covina
Badillo
Cypress
Artesia
Montebello
Harding
Ventura
Type of Project
Cut over remainder
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Peak 4kV
Amps
(Criteria Proj.
Load)
Unit Cost
(Nominal $ x 1,000)
1560
1386
1061
244
707
1182
706
271
$11
$11
$11
$11
$11
$11
$11
$11
Forecast
Cost
(Nominal $ x 1,000 )
Coordination with 4kV Circuit
Overload-Driven Cutovers
$16,684 Remainder to be cut over in 2015
$14,823 Coincident w/ Badillo
Coincident w/ Covina. Current load is
1195 amps. By 2015, load will be 1061 amps due to cutovers on the Foxdale in
$11,347
$2,610
2014, and the Woodside in 2014.
Coincident w/ Artesia
$7,561 Coincident w/ Cypress
$12,641 Coincident w/ Harding
$7,551
$2,898
Coincident w/ Montebello
Current load is 271 amps.
Total
Sharon
Porter
Griswold
El Porto
Edgewater
Bristol
Idyllwild
Cut over portion
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
508 $11
$1,069
$1,069
$1,069
$267
$267
$267
$5,433
$1,069
$1,069
$1,069
$267
$267
$267
$85,556
Current load is 1614 amps. By 2015 load will be 1357 amps due to cutovers of
Dyer and Brookhill in 2013 and Mayfield in 2014. Cutover portion in 2015
109

Year Substation
2016 Sharon
Valencia
Total
Stirrup
Declez
Flanco
Sangar
Bedford
Maywood
Covina
Cypress
Artesia
Montebello
Harding
Ventura
Type of Project
Cut over remainder
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Friendly Hills Cut over portion
Cut over portion
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Peak 4kV
Amps
(Criteria Proj.
Load)
Unit Cost
(Nominal $ x 1,000)
849
597
1174
178
945
667
1400
1465
$11
$11
$11
$11
$11
$11
$11
$11
$1,093
$1,093
$1,093
$273
$1,093
$1,093
$1,093
$1,093
Forecast
Cost
(Nominal $ x 1,000 )
Coordination with 4kV Circuit
Overload-Driven Cutovers
$16,018
$1,093
$1,093
$1,093
$273
$1,093
$1,093
$1,093
$1,093
$87,469
$9,283 Remainder cut over in 2016
$6,528
Current load is 1266 amps. By 2016, load will be 1174 amps due to cutovers in
$12,837 Nancy in 2013 and Eastfield in 2014.
$1,946 Coincident w/ Flanco
$10,333 Coincident w/ Declez
$7,293
$15,308
Current load is 1858 amps. Cut over portion in 2016
Current load is 2181 amps. By 2016, load will be 2124 amps due to cutovers on
Rebel, Squires, & Magnetic in 2014. Cut over a portion in 2016.
110

Year Substation Type of Project
2017 Friendly Hills Cut over remainder
Total
Bedford
Oxnard
Topanga
Sepulveda
Norco
Larder
Hoyt
Sharon
Valencia
Stirrup
Declez
Flanco
Sangar
Cut over remainder
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cut over all circuits
Cathedral City Cut over all circuits
Thunderbird Cut over all circuits
Westgate Cut over all circuits
Cut over portion
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Remove unutilized property
Peak 4kV
Amps
(Criteria Proj.
Load)
Unit Cost
(Nominal $ x 1,000)
Forecast
Cost
(Nominal $ x 1,000 )
458
659
1187
239
658
211
760
1008
161
1058
$11
$11
$11
$11
$11
$11
$11
$11
$11
$11
1076 $11
$1,123
$1,123
$1,123
$281
$1,123
$1,123
Coordination with 4kV Circuit
Overload-Driven Cutovers
$5,143 Remainder cut over in 2017
$7,400 Remainder cut over in 2017
$13,329
$2,684
$7,389
$2,369
$8,534
$11,319 Coincident w/ Thunderbird
$1,808 Coincident w/ Catherdral City
$11,880 Current load is 1058 amps.
$12,082
$1,123
Current load is 1638 amps. Cut over portion in 2017.
$1,123 `
$1,123
$281
$1,123
$1,123
$89,832
111

(100% CPUC-Jurisdictional Constant 2012 and Nominal $000)
1
In SCE’s 2012 GRC Decision, p. 159, the CPUC stated:
12
13
14
15
16
6
7
8
9
2
3
4
5
10
11
Although it would seem there would be some correlation between SCE’s 4kV cutover projects and its 4kV substation elimination projects, this is not apparent from the listing of the identified projects in either program.
Moreover, we are not persuaded that SCE’s unit costs are reliable given they were developed two years before the subject projects were scheduled to be completed. In the previous section, we approved a more evenly paced cutover program which resulted in a 32% reduction to SCE’s 2012 forecast. We mirror that reduction here, and expect SCE to coordinate its cutover program and its substation elimination programs to best ratepayer advantage, including prompt removal of unutilized property from rate base.
We acknowledge the CPUC’s concern about the possible overlap of the 4kV
Circuit Overload-Driven Cutover Program and the 4kV Substation Elimination Program and possible duplication of forecast work. Indeed, it is possible that a 4kV circuit could be so overloaded that it cannot wait for its substation to be eliminated. To ensure clarity in our forecasts of 4kV Substation
Elimination projects and their interaction with 4kV Circuit Overload-Drive Cutovers, Tables II-34 – II-
112

27
28
29
30
23
24
25
26
19
20
21
22
13
14
15
16
9
10
11
12
17
18
7
8
5
6
3
4
1
2
38 include a column entitled, “Coordination with 4kV Circuit Overload-Driven Cutovers.” Information in this column explains how the forecasts for future 4kV substation elimination projects have been reduced to account for 4kV Circuit Overload-Driven Cutovers performed earlier. In short, all the amps forecast to be cut over under the 4kV Substation Elimination Program have been reduced by any partial cutovers performed earlier under the 4kV Circuit Overload-Driven Cutover program.
We also acknowledge the CPUC’s concern about the prompt removal of unutilized property from rate base. Therefore, we have included removal of unutilized property as specific line items associated with each 4kV substation elimination project. d) Justification Of Forecast Work
No 4kV substations were eliminated under the 4kV Substation Elimination program in 2012 due to the receipt of the 2012 Decision late in 2012. Some engineering and planning was completed in support of the elimination of the Porter and Griswold substations.
In 2013, the 4kV substations that will be eliminated are Hanford, Hemet, San
Jacinto, Wilde, Harper Lake, and Daggett.
In 2014, the 4kV substation that will be eliminated are Porter, Griswold, El Porto,
Edgewater, Bristol, Idyllwild, and a portion of the Maywood.
Brief justifications for the elimination of these 4kV substations are provided below.
Hanford Substation
The Hanford substation has both 66kV to 12kV and 66kV to 4kV sections. The
66kV operating and transfer bus arrangement is fed by three 66 kV source lines. The 66 to 4kV section of the substation is comprised of two positions in the 66 kV open switchrack, two 66kV circuit breakers, six single-phase 66/4kV transformers, sixteen-position 4 kV metalclad switchgear, and eleven 4kV circuit breakers, feeding five remaining 4 kV circuits, each with a 4kV step voltage regulator. There is also a 4kV switched substation capacitor installation.
The six single-phase transformers, manufactured by General Electric (a nonsupportive manufacturer) and Westinghouse (a non-supportive manufacturer), are up to 86 years old; specifically 8, 43, 44, 64, 81, and 86 years old. One of the two 66 kV circuit breakers is a 54 year old oil breaker, manufactured by General Electric (FK69-1500-2Y12), a non-supportive manufacturer. The other has failed and been replaced with a 2 year old SF6 gas circuit breaker. The 4 kV circuit breakers,
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The 4kV circuits out of Hanford have no ties to other substations. The 4kV portion of the substation is islanded. With Hanford isolated from any other 4 kV sources, it is difficult to perform maintenance on some of the 4 kV equipment, absent large and protracted customer outages.
Incorporation of the 4 kV circuits into the existing 12kV circuitry via cutovers allows for elimination of these portions of the substation, eliminating the need for maintenance, replacement, and rebuild of this equipment as well as dramatically improving the operability of the circuitry. Existing 12kV capacities at Hanford and Mascot substations are fully adequate for cutover of all of the 66/4 kV load. No new 12kV circuits will be needed to support this cutover.
SCE’s San Joaquin Region has the second lowest fraction of 4 kV substations, after the San Jacinto region, with just 7 remaining 4kV B-substations. All of these substations are completely islanded, compared to 28 percent system-wide. The region is also geographically remote from the bulk of SCE’s distribution system and can become difficult and sometimes impossible to physically access as a result of winter road closures. Since all other distribution in the region is 12kV, and all other B-substations are 66/12kV, elimination of the 4kV at the regional level would simplify stocking and spares provision, while improving storm response risks.
Hemet Substation
The Hemet substation has both 33kV to 12kV and 33kV to 4.8kV sections. The
33kV operating and transfer bus arrangement is fed by two 33 kV source lines. The 33 to 4.8kV section of the substation is comprised of a position in the 33 kV open switchrack, one 33kV oil circuit breaker, one three-phase 33/4.8kV transformer, and a seven-position 4.8 kV open switchrack with operating and transfer bus, and six 4kV oil circuit breakers, feeding three remaining 4.8 kV circuits. There is a spare
33/4.8kV transformer bank, fed from the 33kV transfer bus, and fused at that point, which is made up of three single-phase transformers. A 4.8kV ground bank is also installed, to provide a ground source for this delta-connected system.
The three-phase transformer, manufactured by Allis-Chalmers (a non-supportive manufacturer), is over 48 years old. The 33 kV oil circuit breaker manufactured by McGraw Edison
(CF37-34.5-1500-12), is over 41 year old. Replacement parts are not readily available, and the CB is considered at high risk of failure. The 4 kV circuit breakers, most of which are 45 years old, were
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The 4.8kV circuits out of Hemet have no ties to other substations. The 4.8kV portion of the substation is islanded. For this reason, a small spare transformer bank exists, although it is less than one third the size of the normally in service transformer. With Hemet isolated from any other 4.8 kV sources, it is difficult to perform maintenance on some of the 4.8kV equipment, absent large and protracted customer outages. Incorporation of the 4.8kV circuitry into the existing 12kV circuitry via cutover allows for elimination of these portions of the substation, eliminating the need for maintenance, replacement, and rebuild of this equipment as well as dramatically improving the operability of the circuitry, given the close ties to other 12kV substations.
SCE’s 4.8kV system voltage serves fewer than 0.2% of customers. Maintaining standards, spares, and equipment for these legacy systems within substations and on distribution circuitry has disproportionate costs yet will need to continue until all 4.8 kV substations have been eliminated. Hemet is one of only two 4.8kv substations remaining in the San Jacinto region of SCE.
The other is San Jacinto, which is discussed below. Eliminating both San Jacinto and Hemet substations removes all 4.8kV from one of the six remaining districts in which 4.8kV substations exist.
San Jacinto Substation
The San Jacinto substation is a 33kV to 4.8kV substation fed by a single 33 kV source line. The substation is comprised of a bank of three single-phase 33/4.8kV transformers fused on the 33 kV, a 4.8 kV step voltage regulator, a seven-position 4.8 kV open switchrack with operating and transfer bus, and three 4kV oil circuit breakers, feeding three remaining 4.8 kV circuits. A 4.8 kV ground bank is also installed, to provide a ground source for this delta connected system.
The three single-phase transformers, manufactured by Westinghouse (a nonsupportive manufacturer), are over 59 years old. The 4kV circuit breakers, of which some are 61 years old, were manufactured by Kelman (7.5F1-4), also a non-supportive manufacturer, and have had significant problems in the past.
The 4.8 kV circuits out of San Jacinto has no ties to other substations. The substation is islanded. This is one of only two 4.8kV substations in the San Jacinto Region. With San
Jacinto substation isolated from any other 4.8 kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages.
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SCE’s 4.8 kV system voltage serves fewer than 0.2% of SCE customers.
Maintaining standards, spares, and equipment for these legacy systems within substations and on distribution circuitry has disproportionate costs and will need to continue until all 4.8 kV substations and circuitry have been eliminated. Eliminating both San Jacinto and Hemet removes all 4.8 kV from one of the six remaining districts in which 4.8kV substations exist.
Wilde Substation
The Wilde substation is a 33kV to 4kV substation fed by a single 33 kV source line. The substation is comprised of a wooden switchrack, a bank of three single-phase 33/4kV transformers fused on the 33 kV, and two 4kv WVE automatic reclosers, feeding one remaining 4 kV circuit. There is no voltage regulation in the substation; there is a step voltage regulator on the second distribution structure.
One of the single-phase transformers was manufactured variously by
Westinghouse (a non-supportive manufacturer). The second single-phase transformer was manufactured by Wagner Electric (a non-supportive manufacturer). Both of these transformers are over 74 years old.
The third transformer is over 45 years old.
It must be noted that Wilde has only one transformer bank. There is no redundancy. If the transformer fails, there is no parallel transformer to pick up the load. This is exacerbated by the fact that the transformer bank is a set of three single-phase transformers instead of one three-phase transformer. The failure of any one transformer will incapacitate the station. This increases the likelihood of substation loss and increases the difficulty in finding a replacement transformer which will match the impedances of the remaining two transformers.
The 4 kV circuitry out of Wilde has no ties to other substations. The substation is islanded. With Wilde substation isolated from any other 4 kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages.
The 4kV circuitry overlaps geographically with adjacent 12kV circuitry from two geographically separate sources which do not currently tie. The substation fenceline is 42 feet by 35 feet and would not allow for a station rebuild to current design standards without substation expansion. A
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33/12 kV P.T.
53 was built in 2010 to allow partial cutover of Wilde 4kV loads for load growth reasons.
This allowed creation of a tie from the 12kV P.T. to the adjacent 12kV circuitry to the north. Cutover of the remaining 4kV loads to the existing 33kV to 12kv P.T. will allow for elimination of Wilde substation without obtaining additional property, avoids the cost of rebuilding the substation, and creates a 12kV circuit tie for the cutover circuitry as well as to the adjacent 12kV circuitry to the south.
Harper Lake Substation
The Harper Lake substation is a 33kV to 4.8kV substation fed by a single 33 kV source line. The substation is comprised of an open wooden switchrack, a bank of three single-phase
33/4.8kV transformers fused on the 33 kV, a 4.8 kV step voltage regulator, a two-position 4.8 kV open switchrack with operating and transfer bus, and two 4kV oil circuit breakers, feeding two 4.8 kV circuits. No ground source is provided for this delta connected legacy system.
The three single-phase transformers, manufactured by Allis-Chalmers (a nonsupportive manufacturer), are over 67 years old. The 4 kV circuit breakers, both of which are over 59 years old, were manufactured by Kelman (F1-4), also a non-supportive manufacturer, and have had significant problems in the past.
The 4.8kV circuitry out of Harper Lake has no ties to other substations. The
4.8kV portion of the substation is islanded. This is the only 4.8kV substation in the 10,000 square mile
Barstow District. With Harper Lake isolated from any other 4.8 kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages. The substation would be scheduled for a full rebuild in 2015 if not eliminated, a major expense which would solve none of the reliability and maintenance problems caused by the station’s being islanded.
The 4.8kV circuitry overlaps geographically with adjacent 12kV circuitry which is also islanded. The substation fenceline is 34 feet by 42 feet and would not allow for rebuild to SC&M standard without substation expansion. Cutover of the 4.8kV loads to a new 33kV to 12kv P.T. allows for elimination of the substation without obtaining additional property, avoids the cost of rebuild to
SC&M standard, and creates a 12kV circuit tie for the cutover circuitry as well as for the existing, adjacent islanded 12kV.
53 P.T. refers to what is typically a pole-mounted transformer which transforms one primary distribution voltage to another primary distribution voltage.
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SCE’s 4.8kV system voltage serves fewer than 0.2% of SCE customers.
Maintaining standards, spares, and equipment for these legacy systems within substations and on distribution circuitry has disproportionate costs and will need to continue until all 4.8 kV substations and circuitry have been eliminated. Eliminating Harper Lake removes all 4.8 kV from one of the six remaining districts in which 4.8kV substations exist.
Daggett Substation
The Daggett substation is a 33kV to 4kV substation fed by a single 33 kV source line. The substation is comprised of a wooden switchrack, a bank of three single-phase 33/4kV transformers fused on the 33 kV, and a 4.16 kV step voltage regulator, feeding one 4 kV circuit. There is no low side protection in the substation; there is an automatic recloser on the first distribution pole.
The single-phase transformers, manufactured variously by Pennsylvania
Transformer and by Westinghouse (a non-supportive manufacturer) and by General Electric (a nonsupportive manufacturer). The Pennsylvania and General Electric transformers are both over 76 years old. The Westinghouse unit is over 61 years old.
It must be noted that Daggett has only one transformer bank. There is no redundancy. If the transformer fails, there is no parallel transformer to pick up the load. This is exacerbated by the fact that the transformer bank is a set of three single-phase transformers instead of one three-phase transformer. The failure of any one transformer will incapacitate the station. This increases the likelihood of substation loss and increases the difficulty in finding a replacement transformer which will match the impedances of the remaining two transformers.
The 4 kV circuits out of Daggett have no ties to other substations. The substation is islanded. The nearest other 4kV source is more than ten miles to the west. With Daggett substation isolated from any other 4 kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages. The substation would be scheduled for a full rebuild in 2017 if not eliminated, a major expense which would solve none of the reliability and maintenance problems caused by the station’s being islanded.
The 4kV circuitry overlaps geographically with adjacent 12kV circuitry. The substation fenceline is 30 feet by 30 feet and would not allow for rebuild to SC&M standard without substation expansion. Cutover of the 4kV loads to a new 33kV to 12kv P.T. allows for elimination of the substation without obtaining additional property, avoids the cost of rebuild to SC&M standard, and creates a 12kV circuit tie for the cutover circuitry as well as for the existing, adjacent 12kV circuitry.
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Porter Substation
The Porter substation is fed by two 16 kV source lines. The substation is comprised of a three-position 16 kV open switchrack, two 16 kV oil circuit breakers, three 16/4 kV single-phase transformers, and a seven-position 4 kV open switchrack with operating and transfer bus, and six 4kV oil circuit breakers, feeding five 4kV circuits, each with a step voltage regulator.
The three transformers, manufactured by Wagner Electric (a non-supportive manufacturer), are over 61 years old.
The 16 kV oil circuit breakers are over 40 years old, were manufactured by a nonsupportive manufacturer, and are Kelman (15RA2TV). Replacement parts are not readily available.
They are oil filled. The 4 kV circuit breakers, most of which are over 53 years old, were also manufactured by Kelman (2.5RA2TV), and have had significant problems in the past.
Due to the limited space at this substation, there are operations and maintenance issues with approach distances around the open switchracks and equipment bushings, which create difficulties with grounding and clearances. The substation fenceline is just 66 feet by 43 feet, and most of the space is occupied by the equipment.
It must be noted that Porter has only one transformer bank. There is no redundancy. If the transformer fails, there is no parallel transformer to pick up the load. This is exacerbated by the fact that the transformer bank is a set of three single-phase transformers instead of one three-phase transformer. The failure of any one transformer will incapacitate the station. This increases the likelihood of substation loss and increases the difficulty in finding a replacement transformer which will match the impedances of the remaining two transformers. Finally, Porter has
4kV circuits which tie only to Griswold 4 kV substation, which has little reserve capacity to pick up load should there be a failure at Porter. With Griswold and Porter isolated from any other 4kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages.
Griswold Substation
The Griswold substation is fed by two 16 kV source lines. The substation is comprised of a four-position 16 kV metal-enclosed switchgear, three 16/4 kV single-phase transformers, and an eight-position 4 kV metal-enclosed switchgear feeding three 4kV circuits. The cubicles in the switchgear are old and suffering from rust and corrosion due to water intrusion. The 16 kV source lines are lead cable with potheads that are leaking insulating compound.
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The transformers, manufactured by General Electric (a non-supportive manufacturer) are over 82 years old. Two of the three transformers have oil leaks. One of the transformers has failed and requires shop repair or replacement; the substation is being carried on a temporary transformer bank until a cutover occurs.
The 16 kV circuit breakers were manufactured by Kelman (17 LT 250-6) and installed in 1973. Replacement parts are not readily available. They are oil filled.
The 4 kV circuit breakers were manufactured by GE (AM 4 type), installed in
1957, and have had significant problems in the past. When racking the circuit breakers in and out, it is possible that the primary stabs (electrical contacts) on top of the breaker can become exposed due to a malfunction of the shutters. This is a safety hazard because it exposes personnel to high voltage conductors. The arc chutes in the breakers are prone to gumming up and causing the breaker to not fully operate in both the open and closed positions. Replacement parts for these breakers are not readily available.
The No. 1 transformer bank and Knox 4 kV circuit are conductored with asbestos jacketed cables which were installed in 1961. The riser conduits for the No. 1 transformer cables are asbestos as well. The circuit breakers and switchgear on the 16kV source lines are similar in design to those which failed at the Amalia Substation.
It must be noted that Griswold has only one transformer bank. There is no redundancy. If the transformer fails, there is no parallel transformer to pick up the load. This is exacerbated by the fact that the transformer bank is a set of three single-phase transformers instead of one three-phase transformer. The failure of any one transformer will incapacitate the station. This increases the likelihood of substation loss and increases the difficulty in finding a replacement transformer which will match the impedances of the remaining two transformers.
El Porto Substation
The El Porto substation is fed by two 16 kV source lines. It is comprised of a 16 kV metal-enclosed switchgear, two 16/4 kV three-phase transformers, and a seven-position 4 kV metalenclosed switchgear feeding four 4 kV circuits. Of the stations planned for elimination, El Porto is likely in the worst condition. Rust and corrosion have caused holes in the roofs of the cubicle gear.
SCE has been unable to make permanent repairs to the cubicle structure because this would, for safety reasons, require the entire switchgear to be de-energized and this is not possible without large and protracted customer outages. Most customers fed by El Porto would be without power during the repair
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26 time. Instead, temporary repairs to the enclosure roof have been made with roll-out heat-shrinkable roofing material.
El Porto substation has the circuit breakers and cubicle gear on the 16kV source lines similar to the equipment that failed at the Amalia substation. The 16 kV circuit breakers were manufactured by Kelman (17 LA2TV-B6-ID) and were installed in 1968. Replacement parts are not readily available.
The 4 kV circuit breakers were manufactured by Kelman and were installed in either 1955, 58, or 68, depending on type. Replacement parts are not readily available. Kelman is a non-supportive manufacturer. The three-phase transformers were manufactured by Westinghouse (a non-supportive manufacturer) and Pennsylvania Transformer, and are over 56 years old and over 59 years old.
All circuit breakers at El Porto are oil-filled which increases the risk of fire.
Because the 4 kV cubicles are all housed in the same enclosure, a fire in one cubicle will likely affect all the other cubicles.
The 16 kV cables on the No.2 transformer bank are asbestos-jacketed which could cause environmental concerns if an equipment failure were to occur. These cables were installed in
1959 and are several years past the average service life for substation power cable. Most if not all of the cable getaways at this substation are either lead or asbestos-jacketed making it difficult to work on. El
Porto has weak circuit ties to only a single other 4kV substation. If it were to become disabled, either by an event in the 16 kV or 4 kV switchgear, most customers would be without power until the substation could be restored. There is no way in which all customers can be supplied with power from adjacent circuits.
Edgewater Substation
The Edgewater 12kV to 4.16kV substation is fed from two 12 kV source lines. It is comprised of a 12kV metal-clad switchgear, four three-phase 16/4 kV transformers, and associated
4kV metal-enclosed switchgear feeding four 4kV circuits. The 4 kV switchgear is nearly unique at SCE
(but similar to Maywood substation) in that each cubicle has a transformer bank integrated with it, which complicates obtaining or designing replacements. The transformers are arranged in two “duplex” pairs, with each transformer feeding a single 4kV circuit breaker and circuit, but with a normally open tiebreaker circuit breaker between the two line circuit breakers of each pair.
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The duplex units which comprise the transformers and 4kV CB’s were manufactured by Westinghouse (a non-supportive manufacturer), and are over 58 years old and over 64 years old. There are no replacement parts readily available. The 12kV metalclad interrupter switchgear was manufactured by S & C Electric; it is over 56 years old.
Several years ago, there was a large mudslide from the bluff above the rear of this parcel which, with the associated electrical faults, damaged one of the duplex units. We have not been able to repair or find replacements for this equipment. One of the two units is out of service and needs repair or replacement, and the substation is operating in an abnormal condition, pending cutover, which presents loading problems for individual transformers and circuits. Temporary transformation is feeding a portion of the substation load.
The 4 kV circuitry out of Edgewater has no ties to other substations. The substation is islanded. With Edgewater substation isolated from any other 4 kV sources, it is virtually impossible to perform any kind of maintenance on any of the equipment, absent large and protracted customer outages. If it were to become further disabled, either by an event in the 12 kV or 4 kV switchgear, most customers would be without power until the substation could be restored.
Incorporation of the 4kV circuitry into the existing 12kV circuitry via cutover would allow for elimination of the entire substation, eliminating the need for maintenance, replacement, and rebuild of this deteriorated equipment as well as improving the operability of the circuitry.
Bristol Substation
The Bristol substation is fed by two 12 kV source lines. The substation is comprised of a 12 kV metal-clad switchgear, two 12kV circuit breakers, two 12/4 kV three-phase transformers, and a 4 kV metal-clad switchgear with seven 4kV circuit breakers feeding two remaining
4kV circuits. The transformers and the cubicles in the switchgear are old and suffering from rust and corrosion due to water intrusion.
The transformers were manufactured by Pennsylvania Transformer and are 64 years old. Both transformers have oil leaks which cannot be repaired in-place, requiring shop repair
(teardown and gasket replacement) or replacement. The 16 kV oil circuit breakers were manufactured by a non-supportive manufacturer. They were made by Kelman (14.4RA2TV-A6) and are now 53 years old. Replacement parts are not readily available. The 4 kV oil circuit breakers were also manufactured by Kelman (7.5L2-A/3), are up to 64 years old, and have had significant problems in the past. The rack in and rack out devices of these circuit breakers are very worn requiring two operating personnel to
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26 allow for racking in and out of these circuit breakers in a safe manner. The circuit breakers (both 12kv and 4kv) have historically had closing issues with the mechanism (closing latch springs, micro switches and dashpot failures, etc.) that requires maintenance crew to make constant repairs. Replacement parts for these breakers are not readily available. Most of the instrument transformers (both potential transformers and current transformers) at this substation are leaking no-void, which creates a substantial risk of failure, and a further risk of associated damage.
The substation is in need of wholesale rebuild, but the footprint of the substation building is just 65 feet by 19.5 feet, and would not allow for rebuild to current design standards without building demolition and substation property expansion. Cutover of the 4kV loads to the adjacent 12kv circuitry would allow for elimination of the substation without obtaining additional property, and avoid the cost of rebuilding.
Idyllwild Substation
The Idyllwild substation has both 33kV to 12kV and 33kV to 2.4kV sections.
The 33kV is fed by two 33 kV source lines. The 33 to 2.4kV section of the substation is comprised of a fused position in the 33 kV open switchrack, three single-phase 33/2.4kV transformers, a 2.4kV step voltage regulator, a 2.4 kV open switchrack with operating and transfer bus, and two 4kV oil circuit breakers, feeding two 2.4 kV circuits. A 2.4kV ground bank is also installed, to provide a ground source for this delta connected system.
The three single-phase transformers, manufactured by Maloney (a non-supportive manufacturer), are over 69 years old. The 4 kV circuit breakers, which are up to 67 years old, were manufactured by Kelman (7.5F1-4), also a non-supportive manufacturer, and have had significant problems in the past.
The 2.4kV circuitry out of Idyllwild has no ties to other substations. The 2.4kV portion of the substation is islanded. With Idyllwild isolated from any other 2.4kV kV sources, it is difficult to perform maintenance on any of the 2.4kV equipment, absent large and protracted customer outages. Incorporation of the 2.4kV circuitry into the existing 12kV circuitry via cutover would allow for elimination of these portions of the substation, eliminate the need for maintenance, replacement, and rebuild of this equipment as well as dramatically improving the operability of the circuitry.
SCE’s 2.4kV delta system voltage represents a small fraction of the remaining
4kV. These delta systems represent less than about 5% of all 4kV circuits. The distribution problems of the obsolescent 4kV systems are exacerbated for 2.4kV. Very little load can be carried by 2.4kV
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26 circuits. Even less inrush can be accommodated without voltage or flicker problems, since for the same kVA load, and same conductor size and distance, the primary voltage drop or flicker percentage is three times as great as for 4.16 kV and 25 times as great as for 12kV. Cutover of the Idyllwild 2.4 kV will eliminate the only 2.4 kV substation remaining in the San Jacinto region of SCE.
Maywood Substation
The Maywood 16kV to 4.16kV substation is fed from three 16 kV source lines. It is comprised of a 16kV metal-enclosed switchgear, eight three-phase 16/4 kV transformers, and associated 4kV metal-enclosed switchgear feeding eight 4kV circuits. The 4 kV switchgear is nearly unique at SCE in that each cubicle has a transformer bank integrated with it, which complicates obtaining or designing replacements. The transformers are arranged in four “duplex” pairs, with each transformer feeding a single 4kV CB and circuit, but with a normally open tiebreaker CB between the two line CB’s of each pair.
The transformers were manufactured by General Electric (a non-supportive manufacturer), and are over 64 years old with internal isolation switches that have a design flaw which makes them unsafe. There are no replacement parts readily available. The load tap changers also suffer from a design flaw and frequently require maintenance which is made difficult by the station’s design.
There are no replacement parts readily available. All of the transformer banks are conductored with lead-jacketed cable that was installed in 1950.
Several years ago, there was a catastrophic failure of the circuit breaker to one of the 4 kV circuits (Galion 4kV) which failed to operate following a fault on the circuit. The resultant heating destroyed the cubicle and damaged the adjacent two cubicles. We have not been unable to find replacements for this equipment and there is insufficient room in the substation to construct temporary accommodations. Two of the units are out of service and need repair or replacement, and the substation is operating in an abnormal condition, pending cutover, which presents loading problems for individual transformers and circuits. Cutovers to reduce loading have occurred and more are planned prior to the full elimination project.
The 16 kV oil-filled circuit breakers were manufactured by Kelman (a nonsupportive manufacturer) (17 LA2TV B6-ID) and installed in 1973. The breakers and cubicle gear on the 16kV source lines are similar those which failed at Amalia Substation. The 4kV circuit breakers were manufactured by General Electric (AM5-50-4) and were installed in 1969. They are old and unreliable. Replacement parts are unavailable.
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Maywood has weak circuit ties to only a single other 4kV substation. If it were to become further disabled, either by an event in the 16 kV or 4 kV switchgear, most customers would be without power until the substation could be restored. There is no way in which all customers can be supplied with power from adjacent 4kV circuits.
Incorporation of the 4kV circuitry into the existing 16kV circuitry via cutover would allow for elimination of the entire substation, eliminate the need for maintenance, replacement, and rebuild of this deteriorated equipment as well as improve the operability of the circuits, given the close ties of existing area 16kV substations.
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SOUTHERN CALIFORNIA EDISON COMPANY
QUALIFICATIONS AND PREPARED TESTIMONY
OF ROGER J. LEE
Q. Please state your name and business address for the record.
A. My name is Roger J. Lee. My business address is 1444 E. McFadden Ave., Santa Ana,
California 92705.
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Q. Briefly describe your present responsibilities at the Southern California Edison Company.
A. I am the Manager of Asset Management and System Reliability for Engineering and Technical
Services. My duties are to: (1) monitor, evaluate, and forecast SCE’s distribution system reliability; (2) resolve existing and anticipated deficiencies in distribution circuit reliability; and
(3) co-manage the preemptive replacement of substation major equipment.
Q. Briefly describe your educational and professional background.
A. I received my Bachelor of Science degree in Engineering from the University of California at
Irvine and hold a California Professional Engineer License in Mechanical Engineering. I joined
SCE in 1974. On the generation side of the business, I have managed nuclear-related risk and reliability oversight functions at the San Onofre Nuclear Generating Station. On the distribution side, I have managed distribution apparatus design functions and have, since 2004, overseen
SCE’s distribution infrastructure replacement program. Since 2010, I have co-managed SCE’s substation infrastructure replacement program.
Q. What is the purpose of your testimony in this proceeding?
A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-03, Volume 04, entitled Transmission and Distribution – Infrastructure Replacement Programs as identified in the Table of Contents thereto.
Q. Was this material prepared by you or under your supervision?
A. Yes, it was.
Q. Insofar as this material is factual in nature, do you believe it to be correct?
A. Yes, I do.
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Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best judgment?
A. Yes, it does.
Q. Does this conclude your qualifications and prepared testimony?
A. Yes, it does.
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