sce-07 v.03 testimony...application no.: a.19-08- exhibit no.: sce-07, vol. 3 witnesses: d. gunn r....

Application No.: A.19-08- Exhibit No.: SCE-07, Vol. 3 Witnesses: D. Gunn

R. White

(U 338-E)

2021 General Rate Case

Depreciation Study

Before the

Public Utilities Commission of the State of California

Rosemead, California August 30, 2019

SCE-07, Vol. 3: Depreciation Study

Table Of Contents

Section Page Witness

i

I. INTRODUCTION .............................................................................................1 D. Gunn

A. Purpose and Scope .................................................................................1

B. Organization of Testimony ....................................................................1

C. SCE’s Depreciation Proposals ...............................................................1

D. 2018 GRC Compliance Requirement ....................................................2

E. Summary Tables ....................................................................................2

II. DEPRECIATION CONCEPTS .........................................................................6

A. Purpose of Depreciation .........................................................................6

B. Depreciation Systems.............................................................................7

1. Depreciation Methods ................................................................8

a) Straight-Line Depreciation Methods (e.g., Book Depreciation Methods) .........................................9

b) Accelerated Depreciation Methods (e.g., Tax Depreciation Methods) ...........................................9

c) Decelerated Depreciation Methods (e.g., Interest-Based Valuation Methods) ...............................9

d) Expense Accounting and Retirement Accounting .....................................................................9

2. Depreciation Procedures ..........................................................10

a) Individual Unit .............................................................10

b) Broad Group.................................................................10

c) Vintage Group ..............................................................11

d) Equal Life Group .........................................................11

3. Depreciation Techniques .........................................................11

a) Whole Life ...................................................................11


Table Of Contents (Continued)


ii

b) Remaining Life ............................................................12

4. Depreciation System ................................................................13

5. Depreciation Calculation .........................................................13

III. DEPRECIATION STUDY FOR T&D NET SALVAGE ...............................15

A. Summary of Results .............................................................................15

B. Net Salvage Concepts ..........................................................................15

1. Accounting for Net Salvage .....................................................17

2. Definition of Net Salvage ........................................................17

a) Removal Cost ...............................................................17

b) Gross Salvage...............................................................18

C. Mass Property Net Salvage Estimation ................................................18

1. STANDARD PRACTICE U-4 Form D-6: Analysis Of Net Salvage Rates ....................................................................18

2. Mass Property Accounts Reflect a Significant Quantity and Variety of Retirement Circumstances ................20

3. Basic Judgment Factors in Analyzing Net Salvage Rates .........................................................................................22

a) Retirement Age Impact on Future Net Salvage .........................................................................22

b) Asset Retirement Mix Impact on Future Net Salvage Estimate ..........................................................25

c) Other Impacts on Future Net Salvage Estimate........................................................................26

d) Property Units in Relation to Form D-6 Net Salvage Rates ...............................................................26

D. Analysis of Historical Net Salvage Rates for Mass Property ..............29

E. Account-by-Account Discussion .........................................................30




iii

1. Transmission Plant Net Salvage ..............................................31

a) Account 352: Transmission Substation Structures and Improvements (Authorized -35%, Proposed -35%) .............................31

b) Account 353: Transmission Substation Equipment (Authorized -15%, Proposed -15%) ............................................................32

c) Account 354: Transmission Towers (Authorized -60%, Proposed -80%) .............................34

d) Account 355: Transmission Poles (Authorized -72%, Proposed -90%) .............................35

e) Account 356: Transmission Overhead Conductor and Devices (-80% Authorized, -100% Proposed) ......................................39

f) Account 357: Transmission Underground Conduit (0% Authorized, 0% Proposed) .....................41

g) Account 358: Transmission Underground Conductor and Devices (-15% Authorized, -30% Proposed) ........................................42

h) Account 359: Transmission Roads and Trails (0% Authorized, 0% Proposed) .........................44

2. Distribution Plant Net Salvage.................................................44

a) Account 361: Distribution Substation Structures and Improvements (-25% Authorized, -40% Proposed) ........................................44

b) Account 362: Distribution Substation Equipment (-25% Authorized, -40% Proposed) .....................................................................46

c) Account 364: Distribution Poles (-210% Authorized, -210% Proposed) ......................................47




iv

d) Account 365: Distribution Overhead Conductor and Devices (-115% Authorized, -190% Proposed) ......................................49

e) Account 366: Distribution Underground Conduit (-30% Authorized, -80% Proposed) ...............52

f) Account 367: Distribution Underground Conductors and Devices (Authorized -60%, Proposed -100%) ..........................................................54

g) Account 368: Distribution Line Transformers (Authorized -20%, Proposed -50%) ............................................................58

h) Account 369: Services (Authorized -100%, Proposed -100%) ..........................................................60

i) Account 370: Meters (Authorized -5%, Proposed -5%) ..............................................................62

j) Account 371: Infrastructure Installed on Customer Premises.......................................................62

k) Account 373: Streetlighting and Signal Systems (Authorized -30%, Proposed -50%) ..............63

3. General Plant Net Salvage .......................................................64

a) Account 390: General Buildings ..................................64

IV. DEPRECIATION STUDY FOR T&D SERVICE LIFE .................................66 R. White

A. Development of T&D Service Lives ...................................................66

B. 2019 Service-Life Study ......................................................................68

V. DEPRECIATION STUDY FOR GENERATION PLANT .............................73 D. Gunn

A. Average Service Lives .........................................................................73

B. Generation Net Salvage .......................................................................75

1. Analysis of Net Salvage for Generation Property....................75




v

2. Future Decommissioning Estimates ........................................76

C. Palo Verde Nuclear Generating Station (PVNGS) ..............................77

1. Average Service Life ...............................................................77

2. Interim Retirement Net Salvage and Decommissioning ....................................................................77

D. Hydro Generation .................................................................................78


2. Interim Retirements and Net Salvage ......................................79

3. Hydro Decommissioning .........................................................80

E. Pebbly Beach .......................................................................................83


2. Net Salvage ..............................................................................83

F. Mountainview ......................................................................................83


2. Net Salvage and Decommissioning .........................................84

G. Peakers .................................................................................................84



H. Solar Photovoltaic ................................................................................85

1. Average Service Life (Authorized 20 years, Proposed 20 years) ...................................................................85


3. SPVP044 - Perris Solar Retirement .........................................86

I. Fuel Cells .............................................................................................87




vi

J. Energy Storage .....................................................................................87

VI. DEPRECIATION STUDY FOR GENERAL AND INTANGIBLE PLANT .............................................................................................................89

A. General Plant ........................................................................................90

1. Account 391.1 – Office Furniture ............................................91

2. Account 391.2 And 391.3 – Computer Equipment ..................91

3. Account 391.4 – Power Management System .........................91

4. Account 391.5 and 391.6 – Office Equipment ........................92

5. Account 393 – Stores Equipment ............................................92

6. Account 394 – Tools & Work Equipment ...............................92

7. Account 395 – Laboratory Equipment .....................................92

8. Account 397 – Telecommunication Equipment ......................92

9. Account 398 – Miscellaneous ..................................................93

B. Intangibles ............................................................................................93

1. Miscellaneous Intangibles ........................................................93

2. Capitalized Software ................................................................93

3. Easements ................................................................................95

Appendix A 2019 Service-life Study ............................................................................... R. White

Appendix B Witness Qualifications for Dr. Ronald E. White .........................................

1

I. 1

INTRODUCTION 2

A. Purpose and Scope 3

This volume of the Results of Operations discusses depreciation concepts, assumptions, and 4

estimation procedures, and judgment SCE applied to determine depreciation rates. Those proposed 5

depreciation rates were used to develop the depreciation expense and accumulated depreciation amounts 6

shown in Exhibit SCE-07, Volume 2, Chapter II for 2021 through 2023. The estimated depreciation 7

rates presented in this volume are consistent with Commission and industry-accepted depreciation 8

practices. The proposed depreciation rates are reasonable and should be adopted. 9

The most significant depreciation-related issue SCE is asking the Commission to address in this 10

proceeding is setting appropriate accruals to recover future cost of removal (i.e., the most significant 11

component of negative net salvage). In each of the five rate cases over the past 20 years, SCE has 12

requested that the Commission authorize increases to the cost of removal accruals. Although some 13

progress has been made, the gap between authorized and recorded net salvage rates continue to increase. 14

SCE’s proposals are designed to narrow this gap. 15

B. Organization of Testimony 16

The remainder of this chapter summarizes the results of SCE’s depreciation study. Chapter II 17

offers an overview of foundational depreciation concepts and discusses how SCE’s analyses adhere to 18

the Commission’s STANDARD PRACTICE U-4, Determination of Straight-Line Remaining Life 19

Depreciation Accruals (STANDARD PRACTICE U-4 or SP U-4). Chapter III presents the Transmission and 20

Distribution (T&D) net salvage study results on an account-by-account basis. As a part of this 21

discussion, SCE addresses some aspects impacting the level of historical removal costs and the role 22

expert judgment plays in the analysis. Chapter IV, sponsored by Dr. Ronald E. White, presents the 23

results of the T&D actuarial life analysis. Chapter V presents the results of SCE’s Generation study and, 24

new to this case, a request to begin including accruals for decommissioning small hydro assets. Finally, 25

Chapter VI concludes with SCE’s depreciation study for General and Intangible (G&I) assets. 26

C. SCE’s Depreciation Proposals 27

As shown in Table I-1, below, SCE’s total proposed depreciation expense resulting from the 28

study’s revised parameters is $226 million higher than 2018 GRC authorized depreciation expense based 29

on year-end 2018 CPUC plant balances. 30

2

Table I-11 Impact of Proposed Depreciation Rates by Class of Plant

(Based on Year-End 2018 CPUC-Jurisdictional Plant Balances, $M)

D. 2018 GRC Compliance Requirement 1

D.19-05-020 required SCE to “present a workshop, including a question and answer session, to 2

the Energy Division and any interested parties of its depreciation testimony in the next GRC.” After 3

filing the GRC application, SCE will schedule a workshop with the Energy Division and interested 4

parties to present the results of this depreciation study. Should stakeholders see benefit to more than one 5

workshop, or to having the assigned Administrative Law Judge(s) in attendance, SCE will work with 6

interested parties to develop agenda items. 7

E. Summary Tables 8

Table I-1, Table I-3, and Table I-4, below, summarize the life and net salvage parameters 9

resulting from the analyses described in the following chapters. 10

1 Refer to WP SCE-07 Vol. 03, Book A pp. 14-17 (Depreciation Proposal Impacts).

2018 GRC 2021 GRCCPUC Basis Authorized Net Salvage Life Total Proposed

A B C D E=C+D F=B+ETransmission & Distribution $1,072 $199 ($15) $183 $1,256Generation 118 6 (4) 2 120 Hydro Decommissioning - 30 - 30 30 General & Intangible 413 - 12 12 425 Total 1,604 234 (8) 226 1,830

Impact due to

3

Tab

le I

-2

Su

mm

ary

of S

CE

’s P

ropo

sed

Dep

reci

atio

n P

aram

eter

s T

ran

smis

sion

, Dis

trib

uti

on, a

nd

Gen

eral

Bu

ildi

ngs

2

2 Refer to WP SCE-07 Vol. 03, Book A p. 15 (Depreciation Proposal Impacts).

FERC

Net S

alvag

e Rat

esCu

rves a

nd Li

ves

Depr

eciat

ion R

ates

Acct

Desc

riptio

nAu

thor

ized

Prop

osed

Chan

geAu

thor

ized

Prop

osed

Chan

geAu

thor

ized

Prop

osed

Chan

geA

BC

DE=

D-C

FG

H=G-

FI

JK=

J-ITr

ansm

ission

Plan

t35

2St

ructu

res a

nd Im

prov

emen

ts-3

5%-3

5%L 1

.0 - 5

5L 1

.0 - 5

52.4

1%2.4

2%0.0

1%35

3St

atio

n Equ

ipm

ent

-15%

-15%

R 0.5

- 45

L 0.5

- 45

2.58%

2.59%

0.01%

354

Towe

rs an

d Fix

ture

s-6

0%-8

0%-2

0%R

5.0 -

65R

5.0 -

652.4

6%2.8

9%0.4

3%35

5Po

les an

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ture

s-7

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0%-1

8%SC

- 65

SC -

652.5

4%2.9

6%0.4

2%35

6Ov

erhe

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ondu

ctors

& De

vices

-80%

-100

%-2

0%R

3.0 -

61R

3.0 -

612.8

3%3.3

1%0.4

8%35

7Un

derg

roun

d Co

nduit

0%0%

R 3.0

- 55

R 3.0

- 55

1.73%

1.82%

0.09%

358

Unde

rgro

und

Cond

ucto

rs &

Devic

es-1

5%-3

0%-1

5%S 1

.0 - 4

5S 1

.0 - 4

52.3

0%2.8

8%0.5

8%35

9Ro

ads a

nd Tr

ails

0%0%

R 5.0

- 60

R 5.0

- 60

1.65%

1.65%

0.00%

Distr

ibutio

n Pla

nt36

1St

ructu

res a

nd Im

prov

emen

ts-2

5%-4

0%-1

5%L 0

.5 - 5

0L 0

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55

2.27%

2.38%

0.11%

362

Stat

ion E

quip

men

t-2

5%-4

0%-1

5%L 0

.5 - 6

5S -

0.5 -

651.9

0%2.1

5%0.2

5%36

4Po

les, T

ower

s and

Fixtu

res

-210

%-2

10%

R 1.0

- 55

R 1.0

- 55

5.96%

5.99%

0.03%

365

Over

head

Con

ducto

rs &

Devic

es-1

15%

-190

%-7

5%R

0.5 -

55R

0.5 -

553.8

5%5.6

4%1.7

9%36

6Un

derg

roun

d Co

nduit

-30%

-80%

-50%

R 3.0

- 59

R 3.0

- 59

2.27%

3.42%

1.15%

367

Unde

rgro

und

Cond

ucto

rs &

Devic

es-6

0%-1

00%

-40%

R 1.5

- 43

L 1.0

- 47

43.5

1%4.3

0%0.7

9%36

8Lin

e Tra

nsfo

rmer

s-2

0%-5

0%-3

0%S 1

.5 - 3

3S 1

.5 - 3

34.3

5%5.6

6%1.3

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9Se

rvice

s-1

00%

-100

%R

1.5 -

55R

1.5 -

553.2

7%3.3

2%0.0

5%37

0M

eter

s-5

%-5

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3.0 -

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3.0 -

205.9

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371

Insta

llatio

ns o

n Cus

tom

er Pr

emise

s-1

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1.5 -

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1.5 -

554.4

4%3.6

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373

Stre

et Li

ghtin

g &

Signa

l Sys

tem

s-3

0%-5

0%-2

0%L 1

.0 - 4

8L 0

.5 - 5

02

2.79%

3.15%

0.36%

Gene

ral B

uildin

gs39

0St

ructu

res a

nd Im

prov

emen

ts-1

0%-1

0%R

0.5 -

45SC

- 50

52.0

8%1.8

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.26%

4

Table I-33 Summary of SCE’s Request for Book Depreciation

Generation Plant


Generation Facility Authorized Proposed ∆ Authorized Proposed ∆

A B C D=C-B E F G=F-EPalo Verde 23 23 0 42 66 24Hydro Production 34 31 (3) 119 125 5Hydro Decommissioning 0 15 15 0 446 446Mountainview Units 3&4 20 20 (0) 9 27 19Pebbly Beach 11 26 15 0 2 2Peakers 23 22 (1) 11 22 11Solar Photovoltaic 11 11 (0) 62 81 19Fuel Cell 2 3 1 0 3 3Energy Storage 10 20 10 0 0 0

Remaining LifeAs of Jan 1, 2021 (Years) Removal Cost ($M)

5

Table I-44 Summary of SCE’s Request for Book Depreciation

General and Intangible Plant


FERCAccount Description Authorized Proposed Authorized Proposed

A B C D E FGeneral Plant

389.2 Easements 60 60 1.67% 1.67%391 Office Furniture 20 20 5.00% 5.00%391 Office Equipment 5 5 20.00% 20.00%391 Computers 5 5 20.00% 20.00%391 Security Monitoring System 8.5 10 14.33% 10.00%392 Transportation Equipment 7 7 14.29% 14.29%393 Stores Equipment 20 20 5.00% 5.00%394 Garage, Shop, & Tools Equipment 10 10 10.00% 10.00%395 Laboratory Equipment 15 15 6.67% 6.67%396 Power Operated Equipment 15 15 6.67% 6.67%397 Telecommunication Equipment Various Various 9.66% 9.66%398 Miscellaneous Equipment 20 20 5.00% 5.00%

Intangible Plant302 Hydro Relicensing Various Various 1.95% 2.06%302 Miscellaneous Intangibles 20 20 5.00% 5.00%303 Radio Frequency 40 40 2.50% 2.50%303 Capitalized Software

5-Year 5 5 20.00% 20.00%7-Year 7 7 14.29% 14.29%10-Year 10 10 10.00% 10.00%15-Year 15 15 6.67% 6.67%

Lives Depreciation Rates

6

II. 1

DEPRECIATION CONCEPTS 2

A. Purpose of Depreciation 3

To provide service to its customers, SCE incurs both operations and maintenance (O&M) 4

expenses and capital expenditures. Generally Accepted Accounting Principles (GAAP) and regulatory 5

principles (i.e., the Matching Principle5 and Intergenerational Equity) govern whether a cost is 6

capitalized or expensed. While the return on SCE’s capital assets is made by applying an authorized rate 7

of return to its net investment, the return of investors’ capital is made through depreciation expense. 8

Depreciation is a major expense representing the recovery of the original cost of fixed capital less 9

estimated net salvage over an asset’s useful life. The depreciation rates proposed in this exhibit are 10

designed to accomplish that objective. 11

The Federal Energy Regulatory Commission (FERC) defines depreciation as follows: 12

Depreciation, as applied to depreciable electric plant, means the loss in service value not 13 restored by current maintenance, incurred in connection with the consumption or prospective 14 retirement of electric plant in the course of service from causes which are known to be in 15 current operation and against which the utility is not protected by insurance. Among the 16 causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, 17 obsolescence, changes in the art, changes in demand, and requirements of public authorities.6 18

The National Association of Regulatory Utility Commissioners (NARUC) defines depreciation 19

essentially the same as FERC, except that it refers to “utility plant” instead of “electric plant.”7 20

An important aspect of this definition is the concept of “loss in service value.” The difference represents 21

the service value loss to be allocated and recorded as depreciation expense over an asset’s life. 22

The Financial Accounting Standards Board (FASB) emphasizes the cost allocation aspect in its 23

definition of depreciation accounting: 24

This procedure is known as depreciation accounting, a system of accounting which aims to 25 distribute the cost or other basic value of tangible capital assets, less salvage (if any), over the 26 estimated useful life of the unit (which may be a group of assets) in a systematic and rational 27 manner. It is a process of allocation, not valuation.8 28

5 The Matching Principle requires that each expense item related to revenue earned must be recorded in the

same accounting period as the revenue it helped to earn.

6 18 CFR, Part 101.

7 PUBLIC UTILITY DEPRECIATION PRACTICES, NARUC, 1996, p. 13.

8 ASC 360-10-35-4.

7

The FASB’s definition makes two important points: (1) depreciation should allocate capital costs 1

and net salvage over the useful life of the asset (or group of assets); and (2) the allocation should be 2

systematic and rational. 3

Depreciation accounting is intended to systematically and rationally allocate the service value 4

over the life of the asset, in a manner ensuring that SCE’s customers pay for the portion of the assets’ 5

cost (including future net salvage) from which they receive benefit. A reasonable allocation of service 6

value requires an estimate of the assets’ useful lives and future costs to retire. Otherwise, current 7

ratepayers could pay less (or more) than their fair share, thereby causing future ratepayers to pay too 8

much (or too little). 9

SCE conducted a thorough analysis of its accounting records, and drew on the observations and 10

expertise of field personnel with many years of operational experience to develop the depreciation rates 11

presented in this exhibit. The resulting depreciation proposals are reasonable, are consistent with 12

longstanding depreciation concepts and practices, reflect SCE’s costs to provide service, and are 13

designed to advance the goal of intergenerational equity. 14

B. Depreciation Systems 15

A depreciation system describes the dynamic process through which capital is recovered through 16

depreciation expense accruals. Estimates of service life and net salvage, along with recorded plant, are 17

the basic inputs to the depreciation system. The accumulated depreciation provides “a measure of the 18

state of the system at any time.”9 For example, if the depreciation rate has been insufficient, the recorded 19

accumulated depreciation will be lower than the proper level given the account’s age. The appropriate 20

specification of the depreciation system will depend on the purpose of the system – e.g., book 21

(financial), tax, or valuation. 22

The depreciation system SCE follows is based on the Commission’s STANDARD PRACTICE U-4, 23

DETERMINATION OF STRAIGHT-LINE REMAINING LIFE DEPRECIATION ACCRUALS. SP U-4 sets forth “the 24

determination of depreciation accruals and describes methods of calculating these accruals” with the 25

purpose of assisting “the Commission staff … in determining proper depreciation expenses.”10 Although 26

over 55 years old, SP U-4 represents conventional utility depreciation practices and the CPUC continues 27

9 DEPRECIATION SYSTEMS; Frank K Wolf and W. Chester Fitch, Iowa State University Press, pp. 69-70. Herein

after, DEPRECIATION SYSTEMS.

10 STANDARD PRACTICE U-4, p. 5.

8

to adhere to this standard. The depreciation system is rational and systematic, and is in harmony with 1

industry accounting and regulatory practice in California and the United States.11 2

The three basic dimensions commonly used to define a book depreciation system are designated 3

as: (1) method; (2) procedure; and, (3) technique. SCE’s determination of depreciation expense accruals 4

follows a depreciation system consisting of (1) the straight-line method; (2) the broad group, average life 5

procedure; and, (3) the remaining life technique. The specification of these dimensions is important as 6

they can significantly affect the level of depreciation expense and accumulated depreciation. 7

In establishing its systematic approach, STANDARD PRACTICE U-4 stated the Commission’s intent to 8

meet the “basic depreciation objective … of recovering the original cost of fixed capital (less estimated 9

net salvage) over the useful life of the property by means of an equitable plan of charges to operating 10

expenses.”12 SP U-4 states that “the straight-line remaining life method presented [in SP U-4] and used 11

as standard procedure by the staff meets this objective.”13 12

Because of their importance to SP U-4’s depreciation system, the method, procedure, and 13

technique will each be discussed in turn. 14

1. Depreciation Methods 15

As discussed earlier, cost allocation is the foundational concept for book depreciation; the 16

depreciation method specifies the rate of allocation over an asset’s service life. There are three 17

categories of depreciation methods: (1) Straight-Line; (2) Accelerated; and, (3) Decelerated. As the 18

authors of DEPRECIATION SYSTEMS state: 19

The straight line method of allocation is the method of allocation most often used 20

when calculating book depreciation. Accelerated methods of allocation are 21

commonly used for tax purposes. Decelerated methods of allocation are not in 22

common use for book or tax purposes, but they are of historical interest and are 23

used in valuation problems.14 24

11 Although the Commission STANDARD PRACTICE U-4 was last revised in 1961, the principles it established

still apply and the document is cited by depreciation experts (e.g., DEPRECIATION SYSTEMS pp. 86-88, 149-150). The Commission has continued to maintain its applicability in determining depreciation expense.


13 Id.

14 DEPRECIATION SYSTEMS, p. 74 (emphasis added).

9

a) Straight-Line Depreciation Methods (e.g., Book Depreciation Methods) 1

Consistent with the CPUC’s longstanding practice, SCE applies the straight-line 2

depreciation method. This method distributes the depreciation expense in equal proportions over an 3

asset’s service life. As such, it follows generally accepted accounting principles and is recognized as 4

providing intergenerational equity for determining utility rates. As NARUC observes, “[t]he straight-line 5

method is almost universally used in the utility rate making process.”15 6

b) Accelerated Depreciation Methods (e.g., Tax Depreciation Methods) 7

Accelerated methods, including “Declining Balances” methods and the “Sum-of-8

the-Years-Digits” method, are mathematical approaches that allocate more depreciation to the earlier 9

years. These have been used for income tax purposes, but are not generally accepted methods for book 10

depreciation. 11

c) Decelerated Depreciation Methods (e.g., Interest-Based Valuation Methods) 12

Decelerated (or deferred) methods allocate a greater amount of depreciation to the 13

later years of an asset’s life. A “Sinking Fund,” (or “Present Worth”) method is a decelerated method. 14

When used, it is generally in connection with economic valuation of capital investments, not book 15

depreciation.16 NARUC points out that, for regulatory purposes, “[i]nterest methods, such as the sinking 16

fund method, are no longer in general use.”17 Among some of the reasons cited are the “problems of 17

annuity mathematics; and difficulties of proper accruals near the end of a property’s life.”18 18

d) Expense Accounting and Retirement Accounting 19

The accelerated and decelerated methods include two extreme allocations; 20

(1) expensing the total cost at the time of installation (“expense” accounting), and (2) charging the total 21

cost at the time of retirement (“retirement” accounting).19 As NARUC points out, these are inappropriate 22

for both accounting and regulatory purposes: 23

15 PUBLIC UTILITY DEPRECIATION PRACTICES, NARUC, 1996, p. 61 (emphasis added).

16 DEPRECIATION SYSTEMS, p. 80.


18 Id.


10

The expense and retirement accounting methods fail to achieve the goal of 1

distributing costs to the accounting periods during the property’s life. 2

Therefore, they would not properly match revenues and costs, and the 3

accounting representation of net income would be distorted. Furthermore, 4

the appropriate customer would not pay a fair share of the cost, assuming 5

depreciation expense is included in the cost of service. Generally accepted 6

accounting principles require expenses, such as depreciation, to be 7

allocated by systematic and rational procedures to the periods during 8

which the related assets are expected to provide benefits.20 9

2. Depreciation Procedures 10

Depreciation procedures refer to how property is grouped together for purposes of 11

calculating depreciation. While some assets, such as a generating station, are sufficiently unique as to 12

allow them to be separately identified for depreciation purposes, other assets, such as distribution poles, 13

are not. Instead of depreciating “mass” assets individually, they are usually combined into groups. 14

Property groups can experience a wide range of service lives and retirement characteristics whereas an 15

individual property unit will have a single service life of a specific number of years. For example, a 16

group of distribution poles will face different combinations of factors affecting their retirements, 17

including deterioration, being hit by cars, and relocation or undergrounding of distribution lines. 18

Because of the range of lives and retirement characteristics, the selected grouping of assets will affect 19

the level of depreciation accruals and accumulated depreciation. The following procedures represent the 20

most commonly recognized groupings. 21

a) Individual Unit 22

The Individual Unit depreciation procedure depreciates each property or 23

retirement unit separately. With the exception of large and uniquely identifiable assets, such as a 24

generating station, this method is seldom used in the utility industry. 25

b) Broad Group 26

The Broad Group procedure groups certain categories of plant, usually of a 27

specific plant account or subaccount, and depreciates them as a single group. Because of the averaging 28

across the broad group, this method results in reasonably stable depreciation accruals over time. The 29

Broad Group depreciation procedure is what SCE uses to determine depreciation, and is the most widely 30

used in the electric utility industry. 31

20 Id.

11

c) Vintage Group 1

The Vintage Group procedure groups assets within a category by vintage (i.e., all 2

of the account assets placed into service in the same year). Under this procedure the depreciation 3

characteristics for each vintage are analyzed separately and subsequently combined for a single 4

depreciation rate. For example, the depreciation expense for all poles installed in 1980 would be 5

determined separately from those poles installed in other vintage years. The results for each vintage 6

group would individually contribute to the determination of the total depreciation for the entire group of 7

poles. 8

d) Equal Life Group 9

The Equal Life Group procedure groups plant assets that have the same service 10

lives and depreciates them over the group’s life. The ELG procedure provides full depreciation recovery 11

of the shorter-lived units while they are in service. This is similar to the vintage group procedure except 12

that instead of grouping the assets by vintage year, the assets are grouped by expected service lives. For 13

example, all poles expected to live 10 years are grouped together, those expected to live 11 years are 14

grouped together, and so forth. The depreciation expense for these equal life groups is calculated 15

individually before being combined to determine the total depreciation for the entire group. Since the 16

expected lives of individual poles are generally indeterminate, the equal life grouping is made using 17

survivor curve determinations of what percentage of the assets will retire at each age. 18

3. Depreciation Techniques 19

The two common depreciation techniques are “Whole Life” and “Remaining Life.” These 20

techniques represent different approaches to handling imbalances in the accumulated depreciation. To 21

the degree a past depreciation rate has been either too high or too low, the proper balance of the recorded 22

accumulated depreciation will be wrong. In the event that past authorized depreciation rates have been 23

too low, the recorded accumulated depreciation will be insufficient and the going forward depreciation 24

expense will need to recover the past accumulated depreciation deficit, as well as the going-forward 25

costs. The depreciation techniques handle the past imbalances in two different ways: (a) Whole Life; 26

and, (b) Remaining Life. Each of these approaches is discussed below. 27

a) Whole Life 28

The whole life technique does not incorporate an adjustment for prior over- or 29

under-accruals into the depreciation rate. Instead, the whole-life depreciation rate calculation is equal to 30

(100% - Average Net Salvage%) / Average Service Life. For example, in the case of SCE’s line 31

12

transformers, applying the authorized net salvage and life parameters, the whole-life depreciation rate is 1

3.64%.21 However, this whole life depreciation rate is not sufficient to recover prior depreciation under-2

collections. SCE’s accumulated depreciation for distribution line transformers is $708 million behind the 3

level it ought to be at the end of 2018.22 This shortfall occurs largely because prior depreciation rates 4

were authorized between 0% and -20% net salvage even though the account has been experiencing 5

a -84%23 net salvage. 6

In the case of the whole-life technique, the recovery of a deficit or surplus in 7

accumulated depreciation is made as an amortization amount separate from the account depreciation 8

rate. In the case of the line transformer account, the depreciation rate would be set at 3.64% and would 9

require a separate amortization of the $708 million deficiency over some established period (e.g., 5 or 10 10

years). 11

b) Remaining Life 12

The most widely used depreciation technique in the industry is the remaining life 13

technique. It is designed to recover the undepreciated plant amount less future net salvage over the 14

remaining life of the surviving plant balance. In this manner, any over- or under-accrued depreciation in 15

the accumulated depreciation is adjusted over the remaining life of the group. For example, in the case 16

of distribution line transformers discussed above, the normal depreciation rate of 3.64% would be 17

increased to 4.35%24 to incorporate the recovery of the $708 million past accumulated depreciation 18

deficit into the depreciation rate. 19

SP U-4 favors the remaining life technique because “remaining life straight-line 20

depreciation method is designed to ratably recover the cost of plant, less net salvage and less 21

depreciation reserve, over the remaining life of plant.”25 NARUC also points out that “[t]he desirability 22

of using the remaining life technique is that any necessary adjustments of depreciation reserves [i.e., 23

21 Based on a 33 year average service life and a -20% net salvage rate, the formula is

(100%-(-20%))/33years=3.64%.

22 The $708 million deficiency is based on the current authorized net salvage rate of -20%. Updating to SCE’s proposed net salvage rate of -50% indicates an under-collection of $1,089 million.

23 Based on recorded retirement experience between 2009 and 2018. See Account 368 Net Salvage discussion in Chapter III.E.2.g, below.

24 The 4.35% is based on the current authorized net salvage rate of -20%. The depreciation rate based on SCE’s proposed service life and -50% net salvage rate is 5.66%.


13

accumulated depreciation], because of changes to the estimates of life [or] net salvage, are accrued 1

automatically over the remaining life of the property.”26 2

4. Depreciation System 3

As the full title of SP U-4 indicates, the commission has specified certain aspects of the 4

depreciation system – namely the straight-line method and the remaining life technique. Although SP 5

U-4 does not apply the more contemporary terms for depreciation group procedures, it does address 6

“unit accounting” and “group accounting,” and refers to groupings as including “all units of an account” 7

(i.e., Broad Group), “Age Groups” (also referred to as “Vintage” Groups by SP U-4), as well as other 8

potential groupings to account for plant with similar life and retirement characteristics.27 SP U-4 states 9

that “[b]ecause of greater simplicity in maintaining records, the group basis is more feasible for most 10

classes of utility property where large numbers of units are involved.”28 The specific examples set forth 11

by SP U-4 demonstrating the straight-line, remaining life technique apply the broad group method using 12

plant accounts as the group. 13

5. Depreciation Calculation 14

The STANDARD PRACTICE U-4’s remaining life method for calculating depreciation accrual 15

can be represented by the following formulas: 16


27 STANDARD PRACTICE U-4, pp. 9-10.

28 Id.

14

Figure II-1 Depreciation Rate and Accrual Calculations

The above formulas provide the basic parameters required for the determination 1

of a depreciation rate: (1) Plant; (2) Accumulated Depreciation (sometimes referred to as “Depreciation 2

Reserve” or simply “Reserve”); (3) Future Net Salvage (equal to future gross salvage minus future cost 3

of removal); and (4) Remaining Life. The first two parameters, plant and accumulated depreciation, 4

come from accounting records. The other two parameters, remaining life and future net salvage, are 5

estimates and, as such, the focus of much of this depreciation study. For T&D, the life analysis portion 6

of the depreciation study, presented by Dr. Ronald E. White in Chapter IV, determines an account’s 7

average service life, retirement characteristics, and remaining life. The net salvage analysis portion of 8

the depreciation study (Chapter III) summarizes SCE’s proposal for each net salvage rate.9

15

III. 1

DEPRECIATION STUDY FOR T&D NET SALVAGE 2

A. Summary of Results 3

Table III-5 Summary of Net Salvage Proposals and Impact

(based on Year-End 2018 CPUC Jurisdictional Plant ($M))

B. Net Salvage Concepts 4

Net Salvage is a key element in determining depreciation expense and rates. STANDARD PRACTICE 5

U-4 states that: 6

FERC Net Salvage Rates ImpactAcct Description Auth. Prop. Change ($M)

A B C D E=D-C FTransmission Plant352 Structures and Improvements -35% -35%353 Station Equipment -15% -15%354 Towers and Fixtures -60% -80% -20% $0.3355 Poles and Fixtures -72% -90% -18% $3.3356 Overhead Conductors & Devices -80% -100% -20% $1.4357 Underground Conduit 0% 0%358 Underground Conductors & Devices -15% -30% -15% $1.3359 Roads and Trails 0% 0%

Distribution Plant361 Structures and Improvements -25% -40% -15% $2.2362 Station Equipment -25% -40% -15% $7.4364 Poles, Towers and Fixtures -210% -210%365 Overhead Conductors & Devices -115% -190% -75% $29.8366 Underground Conduit -30% -80% -50% $25.8367 Underground Conductors & Devices -60% -100% -40% $68.1368 Line Transformers -20% -50% -30% $54.8369 Services -100% -100%370 Meters -5% -5%371 Installations on Customer Premises -100% -100%373 Street Lighting & Signal Systems -30% -50% -20% $4.2

General Buildings390 Structures and Improvements -10% -10%

Total $198.8

16

Future net salvage as included in the accrual equation represents an estimate of the dollars 1 which will be realized from the future retirement of all units now in service. Net salvage is 2 gross salvage realized from resale, re-use or scrap disposal of the retired units less cost of 3 removal. It is customary to arrive at the net salvage in dollars by applying an estimated 4 percentage to gross plant.29 5

The important points are that 1) the net salvage included in SP U-4 is the future amount expected 6

to be realized from all assets currently in service (i.e., not simply those expected to retire in the near-7

term) and 2) is equal to the gross salvage minus the removal cost associated with a plant retirement. Cost 8

of removal at the end of a T&D asset’s life generally far exceeds any salvage value and the future net 9

salvage is commonly negative. Net salvage can be expressed either as a dollar amount or as a percent of 10

the original plant cost (the net salvage rate). In the case of mass plant, the net salvage rate is typically 11

multiplied by the surviving plant to estimate the dollar amount of future net salvage.30 The standard 12

industry practice for net salvage follows the same approach set forth in the Commission’s STANDARD 13

PRACTICE U-4.31 14

To illustrate, when a transformer is placed into service, the company includes in depreciation 15

expense an estimate of the future gross salvage value minus its removal cost expected at the end of its 16

service life. Recognition of both an asset’s original cost and its net salvage in depreciation expense 17

allocates the asset’s total capital cost (i.e., its service value) over its expected life. Because removal costs 18

for a T&D asset often exceed its gross salvage value,32 the total costs to allocate are greater than the 19

original cost of the asset. DEPRECIATION SYSTEMS instructs: 20

The original cost less net salvage is called the depreciable base. It represents the capital 21 consumed during the life of the unit and the amount to be recovered through depreciation. If 22 the net salvage is positive, then the capital consumed is less than the original cost. If the net 23 salvage is negative, the capital is greater than the original cost.33 24

NARUC states that “most regulatory commissions have required that both gross salvage and cost 25

of removal be reflected in depreciation rates.”34 NARUC points out that there are sound principles for 26

29 STANDARD PRACTICE U-4, pp. 12, emphasis added.

30 When net salvage is shown as a percent of the original plant cost, it is commonly referred to as the “Net Salvage Rate” or “NSR.”

31 STANDARD PRACTICE U-4, pp. 8, 12.

32 See the discussion on age and forces of net salvage in Section III.C.4.a, below.

33 DEPRECIATION SYSTEMS, p. 51 (emphasis added).


17

the requirement “that the estimated cost of removal of plant be recovered over its life.”35 Those 1

principles include “the accounting principle that revenues be matched with costs and the regulatory 2

principle that utility customers who benefit from the consumption of plant pay for the cost of that plant, 3

no more, no less.”36 4

1. Accounting for Net Salvage 5

SCE’s accounting for net salvage follows the requirements of the FERC Uniform System 6

of Accounts (USoA), which states that “depreciation, as applied to depreciable electric plant, means the 7

loss in service value.”37 The USoA includes in its definition of service value the original cost of plant 8

and its net salvage. Because the USoA provides accruals for both the plant investment and the future net 9

salvage, when a retirement occurs, FERC requires that the net salvage be recorded to Accumulated 10

Depreciation along with the plant cost. The USoA declares that Account 108 – Accumulated 11

Depreciation shall “be charged with the book cost of the property retired and the cost of removal and 12

shall be credited with the salvage value.”38 Account 108 - Accumulated Depreciation is designated as the 13

appropriate account to record net salvage regardless of whether or not a retirement unit is being 14

replaced: 15

When a retirement unit is retired from electric plant, with or without replacement, 16

the book cost thereof shall be credited to the electric plant account in which it is 17

included…. If the retirement unit is of a depreciable class, the book cost of the 18

unit retired and credited to electric plant shall be charged to the accumulated 19

provision for depreciation applicable to such property. The cost of removal and 20

the salvage shall be charged [i.e., debited] or credited, as appropriate, to such 21

depreciation account.39 22

2. Definition of Net Salvage 23

a) Removal Cost 24

The FERC Uniform System of Accounts (FERC USoA) defines removal cost as 25

“the cost of demolishing, dismantling, tearing down or otherwise removing electric plant, including the 26

35 Id.

36 Id.

37 18 CFR, Part 101.

38 Id.

39 18 CFR, Part 101 (emphasis added).

18

cost of transportation and handling incidental thereto.”40 Removal cost generally consists of labor, but 1

also includes other items such as associated equipment charges, transportation costs, and disposal costs. 2

The labor and equipment elements that make up removal costs for the mass property accounts are 3

similar to the non-material costs capitalized with the new plant additions. For example, the replacement 4

of a distribution pole requires the same crew of linemen to expend some of its time removing the 5

existing pole and some of its time installing the replacement pole. As such, the non-material replacement 6

costs are assignable to removal cost or plant-in-service according to the relative time spent removing an 7

existing pole or installing a replacement pole. 8

b) Gross Salvage 9

The FERC USoA defines gross salvage as “the amount received for property 10

retired, less any expenses incurred in connection with the sale or in preparing the property for sale; or if 11

retained, the amount at which the material recoverable is chargeable to materials and supplies, or other 12

appropriate account.”41 The salvage value of used equipment (e.g., power operated equipment, meters, 13

etc.) and the scrap value from retired equipment (e.g., copper conductor) are the most readily 14

recognizable types of salvage along with other salvage values including third-party reimbursements 15

(i.e., joint pole credits, damages claims, etc.). 16

C. Mass Property Net Salvage Estimation 17

SP U-4 provides a framework and tools for the traditional depreciation estimation, but is not 18

prescriptive in the analytical approach or method required and does not provide a step-by-step approach 19

to arriving at a future net salvage estimate. The following describes factors and considerations used in 20

SCE’s study. 21

1. STANDARD PRACTICE U-4 Form D-6: Analysis Of Net Salvage Rates 22

SP U-4 sets forth that in determining the future net salvage “[i]t is customary to arrive at 23

the net salvage in dollars by applying an estimated percentage to gross plant.”42 That is, the future net 24

salvage, gross salvage, and removal cost rates are determined as percentages of the associated future 25

retirement dollars for the gross plant currently in service. 26

40 Id.

41 Id.


19

It is helpful to understand the underlying calculations, when evaluating future net salvage 1

rates. A net salvage rate is composed of a numerator with gross salvage and removal cost dollars as 2

recorded on the books in the year the expenditures were incurred (generally, the “retirement year”). The 3

denominator is the plant retirements, which are the original recorded plant costs when the assets were 4

first put into service. See Figure III-2, below. 5

Figure III-2 Formulation of Net Salvage Rates

To determine reasonable future net salvage rates applicable to existing plant, STANDARD 6

PRACTICE U-4 provides “detailed procedures … applicable to larger utilities or larger accounts where 7

they may be used as an aid in arriving at estimates of proper future net salvage.”43 SP U-4 establishes 8

that analyzing historical recorded retirement and net salvage information is a reasonable starting point 9

for estimating future net salvage rates. 10

Where records are available recorded [net] salvage for each account may be 11

determined by analyzing the credits and debits to the reserve. To do this, total the 12

retirements for each year and determine the corresponding totals of gross salvage 13

and cost of removal. Dividing each of the latter by the retirements gives the 14

percent gross salvage and percent cost of removal realized for each year. This 15

calculation for a series of years is illustrated in the upper portion of the … 16

standard form D-6. In using this information for determining estimates it is often 17

helpful to plot a graph of successive values each year.”44 18

The SP U-4’s Standard Form D-6 arranges the historical retirement experience for the 19

recorded retirements, gross salvage, removal cost, and the resulting net salvage amounts by retirement 20

year. The associated salvage, removal and net salvage rates associated with those plant retirements are 21

also calculated. An example is shown for Account 367 in Table III-6, below. 22



20

Table III-6 Form D-6: Net Salvage History for Account 367 – U.G. Conductor

(in millions of dollars)

The above example shows that, based on the $405 million of retirements (column B) over 1

the past ten years, the average cost to remove the plant at the time of retirement was 173% (column D) 2

more than the original installed plant cost when initially placed into service decades ago. The average 3

salvage dollars (column E) are significantly smaller, about seven percent (column F) of the original plant 4

cost. Before making any additional judgments or evaluations, the last ten years of retirement history lead 5

to a reasonable conclusion that the future net salvage rate (column H) for Underground Conductor could 6

be about -165%. To estimate future net salvage rates, experts often consider analysis in addition to these 7

historical rates summarized in Form D-6. 8

2. Mass Property Accounts Reflect a Significant Quantity and Variety of Retirement 9

Circumstances 10

T&D plant accounts are designated as “mass property” because of the volume of assets. 11

T&D assets are accounted for in 19 separate accounts representing various functions that have a vast 12

number of discrete assets, component types, technical specifications, configurations, locations, and ages. 13

Each of these factors has an impact on each asset’s overall cost to remove. For example, replacing a pole 14

on a rural road set in dirt with no hardscape will cost less than replacing a pole set in concrete in a busy 15

urban area. It is even more difficult and costly to replace a pole in a backyard that has no vehicle access 16

and requires the use of special equipment. 17

21

Despite the quantity and diversity of SCE’s T&D plant assets, the depreciation system 1

requires a single average future net salvage rate for each account’s depreciation rate. However, given the 2

differences in retirement units and the large number of retirement work orders processed annually, it 3

would not be possible to specifically analyze all of the tens of thousands of work orders and individual 4

factors affecting net salvage. Fortunately, the large volume of retirement transactions makes that level of 5

effort largely unnecessary. 6

Between 2009 and 2018, T&D assets experienced a significant level of retirements 7

totaling $2.1 billion, representing millions of assets. In 2018 alone there were more than 46,000 8

retirement work orders processed totaling $324 million of T&D retirements under a variety of 9

circumstances. Some are performed on an over-time versus normal-time basis; some are scheduled while 10

other activity is performed in an emergency. Some plant components require careful testing and 11

handling because of chemical contents or because special disposal is required. Some assets retire early in 12

their service life and some retire at significantly more advanced ages. SCE’s retirement history reflects a 13

wide variety of conditions and provides a reasonable sample from which to draw conclusions about 14

future net salvage rates. By considering the numerous retirements over a ten-year period, the practice of 15

analyzing historical net salvage rates provides a reasonable basis for estimating future net salvage costs. 16

Regarding the numerous removal cost factors, NARUC states that “making detailed 17

forecasts are usually not justified by the results.” Instead, “it is believed that an analyst, cognizant of the 18

factors that may cause future cost of removal experience to differ from that of the past, is able to 19

adequately estimate the future cost of removal as a percent of retirements.”45 Furthermore, regarding 20

gross salvage, NARUC suggests that the result of analyzing individual salvage prices “does not justify 21

the time and effort involved.”46 In addition to NARUC, other authorities acknowledge the 22

reasonableness of using historical net salvage rates as the basis for estimating net salvage. The CPUC’s 23

STANDARD PRACTICE U-4 adopts this approach,47 as does the text DEPRECIATION SYSTEMS.48 24



47 STANDARD PRACTICE U-4, pp. 37-40.

48 DEPRECIATION SYSTEMS, pp. 53-68.

22

3. Basic Judgment Factors in Analyzing Net Salvage Rates 1

On the surface, the net salvage rates appear as a simple calculation of net salvage 2

occurring at retirement divided by the original plant balance associated with that retirement. A deeper 3

look reveals a number of factors affecting the net salvage rates. While every individual plant retirement 4

has its own unique set of circumstances affecting its specific net salvage rate, there are common factors 5

that should be considered when making judgments how representative historical retirements are of the 6

future. Rather than simply relying on the historical average net salvage rates, STANDARD PRACTICE U-4 7

references a number of judgment factors that should be considered when evaluating historical versus 8

future net salvage. Some considerations include assumptions about the future, age-related impacts, 9

changes in costs over time, asset composition, differences in asset characteristics, and the otherwise 10

representative nature of the historical experience versus future expectations. Along these lines, for the 11

larger accounts, the Commission has previously indicated its desire for quantitative (not just qualitative) 12

support with respect to historical and anticipated future cost of removal using quantities, the 13

implications associated with the historical and anticipated future retirement mix (i.e., retirements among 14

different asset classes), and implication of the service life (i.e., average age at retirement) to the original 15

cost of plant assets being retired in relationship to cost of removal on both a historical and anticipated 16

future basis.49 17

a) Retirement Age Impact on Future Net Salvage 18

Retirement age and the associated cost escalation over time has the most 19

significant impact on net salvage rates. The reason is that the costs in the numerator and denominator of 20

the net salvage rate reflect costs from different periods depending on the length of the service life of the 21

retiring asset. That is, the rate represents the net salvage costs of an asset being replaced (numerator) 22

divided by the original installed plant costs of the very same asset (denominator). For example, an asset 23

placed into service in 1970 and retired in 2018 will have the original installed costs as incurred back in 24

1970 in the denominator, and the net salvage dollars reflecting the removal costs incurred in 2018 when 25

the plant was retired from service in the numerator. 26

49 D.15-11-021, pp. 554-555.

23

Whereas the original plant cost remains fixed at the cost recorded in the 1

installation year (or vintage year), as the number of years between installation and retirement increase, 2

the removal costs will increase, as demonstrated in the following equations:50 3

Figure III-3 Embedded Cost Escalation in Net Salvage Rates

Other factors being equal, older-lived plant retirements will exhibit a greater 4

percentage of removal cost to original plant cost than younger retirements because of the cost escalation 5

between the time of original installation and the time of removal. As a plant account matures and the 6

average composition of retirements is older, the account’s removal cost rates will increase. To 7

demonstrate the impact of cost escalation on removal cost rates, assume, for example, that seven 8

distribution assets were placed into service in 1955 at a cost of $500 per asset. Furthermore, assume that 9

the first asset retires during the first year and is removed at a cost of about $250. Assume that an 10

additional asset retires each tenth year thereafter. Assuming a reasonable average cost increase of 3 11

percent annually, the removal cost (i.e., net salvage) rates for these six assets would increase with age as 12

shown in Table III-7, below: 13


1. Net Salvage % Net Salvage $ Retirement Year $

Plant Retirement $ Vintage Year $

2. Net Salvage % Net Salvage $ Vintage Year $ ∗ 1 Escalation Rate Retirement Age

Plant Retirement $ Vintage Year $

24

Table III-7 Plant Retirement and Removal Cost

As the hypothetical example above shows, cost escalation and service life 1

increases will impact recorded net salvage rates and their impacts should be considered, as the 2

Commission has expressed.51 The text DEPRECIATION SYSTEMS, also indicates the impact of increasing 3

retirement age and cost escalation on net salvage.52 4

Whereas removal cost rates increase with the age of the plant retirements, gross 5

salvage rates generally decrease with age. The decline in the functionality and advances in technology as 6

an asset ages is one cause for salvage rates to decrease. Fitch and Wolf discuss this decline in salvage 7

value: 8

Gross salvage of early retirement will be high if the property is in good 9

condition and the technology is current, because the property will be 10

valuable for sale or reuse. Older retirements would be less valuable 11

because, besides their added wear, they would be competing for use with 12

property that has a more current technology.53 13

Where there has been an increasing trend in plant balances, retirement dispersion 14

curves demonstrate that, on average, past retirements will be younger than the future retirement of 15

existing plant.54 16

51 See Ordering Paragraph 9.i of D.15-11-021.


53 DEPRECIATION SYSTEMS, p. 52.

54 This is borne out by comparing the recent average age of retirement compared to the average service life of the T&D accounts.

Age Plant Removal Removal Year (years) Retirement Cost Cost Ratio1955 0 $500 $250 50%1965 10 $500 $336 67%1975 20 $500 $452 90%1985 30 $500 $607 121%1995 40 $500 $816 163%2005 50 $500 $1,096 219%2015 60 $500 $1,473 295%

25

b) Asset Retirement Mix Impact on Future Net Salvage Estimate 1

As previously discussed, although T&D plant is grouped in 19 FERC accounts, 2

the assets recorded in each account are not identical. When evaluating the mix of assets in the historical 3

net salvage rates it is important to consider whether the composition of historical retirements is 4

reasonably representative of the composition of anticipated future retirements (i.e., existing plant). 5

For example, the plant balance for Account 373 generally consists of three major 6

components – poles (45%), cable and conduit (33%), and light fixtures (20%). Although light fixtures 7

make up about 20% of the anticipated future retirements (i.e., plant investment), they represent 63% of 8

the account’s historical retirements. Moreover, the light fixtures have a -50% net salvage, which is a less 9

negative net salvage than the other streetlight assets, which collectively have a -273% net salvage rate. It 10

is reasonable that the retirement history reflects a higher level of retirements for light fixtures because 11

the luminaires have a shorter service life than the other equipment. It is also reasonable that the negative 12

net salvage is lower given that the younger retirement age for light fixtures. 13

Table III-8 Account 373 Net Salvage Analysis Results 2009-2018


Relying solely on retirement history in Form D-6, without considering the true 14

composition of the plant balance, underweights the net salvage experience related to the streetlight 15

assets that make up the vast majority (80 percent) of the account balance. STANDARD PRACTICE U-4 16

specifically addresses how to avoid this. Recognizing that future retirements can be “materially different 17

from past experience” because of a “difference in characteristics,” SP U-4 suggests weighting net 18

salvage estimates for different classes of property using the plant balances to determine a composite 19

estimate:55 20


Major Retirement Mix Plant MixComponent Retirements Percent Balance Percent $ Percent Ret. Wtd. Plant Wtd.

A B C D E F G=F/B H=C*G I=E*GOther Streetlight Assets1 $36 37% $680 80% ($100) -290% -101% -233%Fixtures $62 63% $168 20% ($31) -50% -31% -10%Total $98 $848 ($130) -133% -243%

Net Salvage Weighted NSR

26

When separate estimates are developed for different classes of property or 1

different age groups, the composite estimate for the account should be 2

determined by direct weighting. That is, by multiplying each percent 3

estimate times its related dollars of plant, totaling these products and 4

dividing by the total plant dollars. This gives the composite net salvage 5

expressed as a ratio or a percent. 6

Differences between historical and future net salvage rates can be significant 7

depending on the level of difference in the asset mix of plant balances compared to the asset mix of 8

retirements. In the streetlight example above, reweighting the historical retirement experience using the 9

anticipated future retirement mix for this plant account results in a more negative average net salvage 10

rate of -243%, instead of the -133% reflected in the unadjusted historical results. 11

c) Other Impacts on Future Net Salvage Estimate 12

As previously discussed, there are enumerable factors affecting the life of millions 13

of utility assets. Most of these will be captured in the significant, ongoing retirement experience. The 14

above factors of service life and retirement age, cost escalation, and historical asset retirement mix 15

represent impacts that can have the most significant effect when evaluating historical versus future 16

anticipated net salvage rates. Of course, there can be other considerations. For example, if the retirement 17

experience in a particular account is too thin, the historical results may need to be augmented with 18

additional information regarding the expected net salvage. Also, emergent changes affecting the 19

circumstances surrounding future retirement activity can be considered: change in average service lives, 20

plant removal practices, disposal practices, environmental requirements, extraordinary events, and so 21

forth. Most of these would more likely tend toward a more negative net salvage. However, given the 22

relative gap between proposed net salvage rates and the levels recently experienced, there are no 23

fundamental changes in retirement practice expected that would require a change in the proposed 24

estimates. 25

d) Property Units in Relation to Form D-6 Net Salvage Rates 26

Units of Property (or retirement units) are an integral part of mass plant 27

accounting. The plant unitization is prescribed by FERC USoA and provides necessary cost information 28

when recording additions and retirements to the plant and depreciation ledgers. Plant costs and 29

associated quantities are recorded to specific retirement units within a plant account for each installation 30

year. Dividing the plant dollars by the unit quantity provides the amount to be removed from the plant 31

ledger when a plant asset is retired. Retirement units are also involved when recording removal costs 32

27

associated with mass property, which can be important when evaluating the impact of the retirement mix 1

on anticipated future net salvage. 2

Understanding the relationship between historical net salvage rates at a retirement 3

unit level is helpful when evaluating the reasonableness of net salvage rates, which can otherwise be 4

difficult to interpret. As the following equations show, analyzing net salvage rates at a unit level is 5

equivalent to analyzing recorded net salvage rates in Form D-6. 6

Figure III-4 Formulation of Historical Net Salvage Rates on a Quantity Basis

1. Net Salvage % $ $

$ $


$ $


$ $

For example, the five-year net salvage rate for Distribution Overhead Conductor 7

is -216%, calculated by dividing the recorded net salvage dollars of $231 million by the plant retirement 8

dollars of $107 million. Interpreting the historical -216% can be challenging without deconstructing the 9

elements underlying the net salvage ratio. Determining the unit-level amounts for the net salvage 10

(numerator) and retirements (denominator) results in the same net salvage rate of -216% as Form D-6, 11

but is easier to understand. 12

28

Figure III-5 Account 365 Net Salvage Rate per Foot of Conductor Retired

The above calculation shows that the original installation of 52.7 million feet of 1

overhead conductor distribution assets recently retired between 2014 and 2018 cost about $2.03 per foot 2

of conductor when placed into service about 37 years ago (i.e., the average age when retired). Over 3

nearly four decades, the level of net removal cost escalated to $4.38 per foot of conductor by the time of 4

retirement (216% of the original plant cost). 5

The five-year average net salvage rate of -216% reflects the average 37-year life 6

of the recent retirements and as such represents a historical basis. As the Commission has recognized, it 7

is important to evaluate the “life of assets and original cost of assets being retired, in relation to the 8

COR,” not only on a historical basis, but on an “anticipated future basis.”56 Whereas the historical net 9

salvage rate reflects original costs of $2.03 per conductor-foot and a service life of 37 years, the 10

anticipated future basis for the current plant balance reflects original costs of $2.33 per foot of conductor 11

and an average life expectancy of about 68 years (i.e., a remaining life of 36 years, based on an average 12

age of 32 years and an R0.5 retirement curve with a 55-year average service life). As will be 13

demonstrated below, with the underlying difference in life expectancies, the anticipated future negative 14

net salvage rate for the distribution overhead conductor account will be significantly higher than the 15

historical rate. That is, better estimates of the future removal cost obligation can be made given that (1) 16

the unit costs in the denominator are fixed based on the original (vintage year) recorded amounts in the 17

plant ledger, and (2) the current unit-level removal costs in the numerator will continue to escalate 18

throughout the asset’s remaining life (retirement year). As demonstrated in the bottom equation of the 19

figure below, taking the recent unit net salvage amounts and considering the potential cost escalation 20

over the plant’s remaining life estimates the future net salvage rate. 21

56 D.15-11-021.

Net Salvage $ / Feet Retired /Retirement $ / Feet Retired /

Net Salvage $ / Feet RetiredRetirement $ / Feet Retired

($230,813,957) 52,694,494 $106,720,924 52,694,494

= ($4.38) = -216%$2.03

=

29

Figure III-6 Escalation Rate in Historical Net Salvage Rates


$ $

2. Net Salvage % $ $ ∗

$ $

Continuing with our example, applying this equation to Account 365 yields an 1

anticipated future net salvage rate of -464%: 2

Figure III-7 Formulation of Future Net Salvage Rate for Account 365

Net Salvage % – $4.38 ∗ 1 Escalation Rate

$2.33

Net Salvage % – $4.38 ∗ 1 2.86%

$2.33

Net Salvage % – $10.80

$2.33 – 464%

Although the basic Form D-6 provides a historic net salvage rate of -216% for the 3

past five years, the differences between historic and future age and life expectancies yields an 4

anticipated future negative net salvage rate of -464%. Moreover, while using the property unit level 5

information does not change the results of STANDARD PRACTICE U-4’s Form D-6 analysis, it does provide 6

greater visibility into some of the factors affecting the historic and anticipated future net salvage rates. 7

D. Analysis of Historical Net Salvage Rates for Mass Property 8

SCE uses average net salvage rates as a basis for analyzing future net salvage and incorporating 9

the net salvage into the calculation of the depreciation rate. The net salvage rate approach analyzes the 10

change in net salvage component amounts as a percent of original plant costs. As NARUC states, “the 11

process should start by analyzing past salvage and cost of removal data and by using the results of this 12

30

analysis to project future gross salvage and cost of removal.”57 In the case of mass property, the 1

historical net salvage elements are analyzed in relationship to retirements. SCE analyzes these rates for 2

bands of years in order to smooth out the year-to-year fluctuations inherent in retirement accounting data 3

and provide an indication of trends. For the depreciation study, five- and ten-year historical averages 4

were considered along with three-year rolling bands. Where there were significant fluctuations in the 5

data or relatively fewer retirements, SCE generally considered longer year bands. Where there were 6

general trends in the data, the shorter five-year averages were considered along with the rolling bands. 7

Moreover, SCE’s judgment also included an evaluation of the historical results versus future 8

expectations with respect to retirement age, changes in cost levels, the asset composition, and other 9

variations. Lastly, when practical, SCE determined the average underlying removal cost dollars by major 10

component for T&D line accounts when evaluating the net salvage rates. The recorded component cost 11

information provides a straightforward way to understand the removal costs included in SCE’s proposed 12

net salvage rates. 13

E. Account-by-Account Discussion 14

Table III-9, below, compares the authorized and proposed net salvage rates to the recorded 15

levels. An overall comparison demonstrates that SCE’s net salvage cost recovery has been substantially 16

less than the recorded levels of net salvage over the past ten years across the majority of T&D accounts. 17

The weighted average authorized net salvage rate for the transmission and distribution accounts is -57% 18

which compares to a -148% average net salvage experienced over the past ten years. The account-by-19

account analysis in this section of the chapter further substantiates this conclusion. Note that the plant 20

balances presented in the account-by-account analysis presented below differ from the plant balances 21

presented in the rate determination schedule (RDS) for two reasons. The first reason for the difference is 22

that the RDS includes a reduction in plant balances associated with write-offs required by the 2018 GRC 23

decision. The second reason is that during the data-gathering phase of the depreciation study, SCE 24

identified pro-forma adjustments that resulted in transfers of small amounts (less than $4 million) 25

between FERC accounts. 26

57 PUBLIC UTILITY DEPRECIATION PRACTICES, NARUC, 1996, pp. 157-158.

31

Table III-9 Comparison of T&D Net Salvage Rates

1. Transmission Plant Net Salvage 1

a) Account 352: Transmission Substation Structures and Improvements 2

(Authorized -35%, Proposed -35%) 3

The currently authorized net salvage rate for transmission substation structures 4

is -35%. While a more negative net salvage rate is warranted based on the historical results SCE is 5

proposing to maintain the authorized -35% net salvage rate at this time. 6

This account consists of $984 million58 in structures and improvements at more 7

than 180 transmission substations. During the last ten years, SCE has retired $13 million of plant from 8

this account, representing approximately 2% of the average plant balance over this time. The realized 9

net salvage rate from these retirements over the past ten years averages -77%. The composition of assets 10

being retired in this ten-year net salvage rate reasonably matches the plant balance. Reweighting the 11

58 $340 million on a CPUC jurisdictional basis.

Transmission: 352 353 354 355 356 357 358 359 Total*Recorded

10-yr Average -77% -22% NM** -190% -254% -203% -35% NM** -72%5-yr Average -80% -32% NM** -200% -202% NM** -41% NM** -97%

Proposed vs. AuthorizedSCE Proposed -35% -15% -80% -90% -100% 0% -30% 0% -47%Authorized -35% -15% -60% -72% -80% 0% -15% 0% -38%

Distribution: 361 362 364 365 366 367 368 369 370 373 Total*Recorded

10-yr Average -40% -69% -508% -242% -223% -166% -84% -474% -3% -133% -172%5-yr Average -49% -77% -469% -216% -257% -164% -104% -438% -3% -161% -185%

Proposed vs. AuthorizedSCE Proposed -40% -40% -210% -190% -80% -100% -50% -100% -5% -50% -97%Authorized -25% -25% -210% -115% -30% -60% -20% -100% -5% -30% -68%

* Recorded history weighted based on retirements; Proposed/Authorized weighted based on plant balance** Retirement data unrepresentative or insufficient, not meaningful (NM)

32

historical net salvage rates consistent with the asset mix indicates that the net salvage rate experienced is 1

the same at -77%. The retirements and net salvage are shown in Table III-10, below. 2

Table III-10 Account 352 Recorded Net Salvage Rates


Given the limited level of retirements and likely synchronization issues related to 3

the timing of removal cost and retirement transactions, the year-to-year net salvage rates fluctuate 4

significantly, ranging from -22% to -158%. The fluctuations support examining three-year rolling 5

averages and the longer-term average. Three-year rolling averages range from -61% to -113% and the 6

ten-year average is -77%. While the historical results support a more negative net salvage rate, given the 7

limited retirement history, SCE proposes maintaining the currently authorized -35% net salvage rate. 8

b) Account 353: Transmission Substation Equipment (Authorized -15%, 9

Proposed -15%) 10

The currently authorized net salvage rate for transmission substation equipment 11

is -15%. Although historical net salvage experience supports a more negative rate, SCE proposes 12

retaining the authorized net salvage rate of -15% at this time. 13

Plant Net SalvageYear Retired Amount % of Ret. 3-yr Avg % 2009 $0.9 ($0.2) -22%2010 $0.3 ($0.3) -93%2011 $1.1 ($0.9) -82% -61%2012 $0.2 ($0.2) -100% -87%2013 $0.2 ($0.1) -68% -83%2014 $0.9 ($1.1) -117% -108%2015 $2.3 ($2.1) -91% -97%2016 $1.0 ($1.6) -158% -113%2017 $2.7 ($1.5) -56% -87%2018 $3.8 ($2.3) -60% -72%

2009-2018 $13.3 ($10.2) -77%2014-2018 $10.7 ($8.5) -80%

33

This account consists of $6,071 million59 in station equipment at more than 180 1

transmission substations. Transmission substations convert high voltage loads to lower voltages to be 2

distributed to distribution circuits. To do so, substations include a variety of assets such as circuit 3

breakers, transformers, steel racks and structures, switches and switch gear, cables, and other devices 4

recorded in nearly 200 retirement units. Over the past ten years, SCE has retired $337 million of plant 5

(7% of the average plant balance) at a net removal cost of $73 million for an overall net salvage rate 6

of -22% as reflected in the Form D-6 and as summarized in Table III-11, below. 7



The annual realized net salvage rates from these retirements have ranged 8

from -4% to -48% and the three-year rolling average rates ranged from -10% to -34%. The overall 9

average net salvage rate for the ten-year period is -22%. The composition of the historical retirements 10

are reasonably representative of the mix of surviving plant. Re-weighting the historical net salvage 11

results to more accurately reflect the composition of the account balance results in a slightly more 12

59 $2,612 million on a CPUC jurisdictional basis.


2009-2018 $337.0 ($73.0) -22%2009-2013 $185.8 ($25.0) -13%2014-2018 $151.2 ($48.0) -32%

34

negative net salvage rate, changing from -22% to -24%. Net salvage rates increased from an average 1

of -13% for 2009 to 2013, compared to -32% for the most recent five years. Although the average net 2

salvage rates have increased, the most recent five years are supported by fewer retirements and point to 3

relying on the longer 10-year average. A significant portion of the retirements during the past ten years 4

relate to investment in large renewable and reliability-related transmission projects such as Tehachapi 5

Renewable Transmission Project (TRTP). However, the overall net salvage rate for these renewable and 6

reliability-related projects was not significantly different than for other projects having an overall net 7

salvage rate of -19%. Given the ten-year average, the transmission project experience, and currently 8

authorized net salvage rate, SCE proposes to retain the authorized -15% at this time. 9

c) Account 354: Transmission Towers (Authorized -60%, Proposed -80%) 10

The currently authorized net salvage rate for transmission towers and fixtures 11

is -60%. This level of net salvage has been unchanged since the 1995 GRC and is currently allocating 12

future net salvage at levels below the cost SCE incurs for present-day removal activities. SCE proposes 13

a net salvage rate of -80%. As part of transmission, 97% of the account’s costs are allocated to FERC 14

rates, limiting the rate impact of SCE’s proposed increase to $0.3 million on a CPUC-jurisdictional 15

basis. 16

This account consists of $2,356 million60 in over 31,000 transmission towers. 17

During the last ten years, SCE retired $4 million of plant from this account, representing less than 1% of 18

the average plant balance over this time. Although this is a very low level of retirement on a percentage 19

basis, it is not unexpected given the long lifespans of these assets. Despite limited retirement history the 20

cost to remove each tower can be reasonably estimated because of the similarity of the investment in the 21

account. The historical negative net salvage rates exhibit extreme fluctuations with a low of -167% and 22

highs many times more negative, making the historical analysis more challenging. The aggregate 23

average net salvage over the ten-year historical period is -868%, with an average retirement age of 61 24

years. Given the very long lives of these assets, along with the general cost increases that have been 25

experienced, very negative net salvage rates are reasonable. 26

Over the past ten years, SCE retired 1,242 towers and structures with the vast 27

majority (976 or 79%) being retired in the last five years. This quantity of retirements collectively 28

provides a reasonable basis for estimating future net salvage costs. These tower retirements occurred 29


35

over a variety of removal and replacement circumstances and can be considered representative of the 1

types of costs that SCE will experience in the future. However, 380 of these retirements include activity 2

driven by large transmission construction projects integrating renewable generation, such as the TRTP. 3

Because some of these towers are in mountainous terrain and were completed under tight timelines, their 4

costs to retire generally exceeded the average costs experienced under more “normal” circumstances. 5

Although these kinds of situations will be encountered in the future, the full level of net salvage 6

experienced in the recent past may not be reflective of the level expected in the future and, as such, were 7

removed from the analysis. After removing these transactions, the remaining 862 towers yield an 8

average recorded cost to retire of approximately $42,000 per tower between 2009 and 2018.61 The 9

authorized net salvage rate of -60% yields only approximately $37,000 per tower. SCE’s proposed net 10

salvage rate of -80% is below future expectations but sets the net salvage rate at a level that avoids 11

collecting below recently experienced costs and represents a conservative step toward the expected level 12

for future retirements. 13

d) Account 355: Transmission Poles (Authorized -72%, Proposed -90%) 14

The currently authorized net salvage rate for transmission poles is -72%. SCE 15

proposes a -90% net salvage rate supported by recent retirement experience and SCE’s analysis of 16

historical data. As part of transmission, 26% of the account’s costs are allocated to FERC rates, limiting 17

the impact of SCE’s proposed increase in this case to $3.3 million on a CPUC-jurisdictional basis. 18

This account consists of $1,500 million62 of transmission poles. Major 19

components of the account include wood poles and tubular steel poles. Between 2009 and 2018, SCE 20

retired more than 30,000 transmission poles, or $89 million in plant (10% of the average plant balance). 21

More than 70% of these retirements took place between 2014 to 2018. The 2009 to 2013 net salvage 22

rates exhibited greater variability ranging from -83% to -298%, and averaging -160%. More recent net 23

salvage rates recorded between the years 2014 and 2018 demonstrated less variability averaging -200%, 24

and were consistently more negative than -170%, as shown in Table III-12, below. 25

61 The $42,000 average cost to retire each tower will increase with escalation over the 18-year average

remaining life.

62 $1,114 million on a CPUC-jurisdictional basis.

36



Deconstructing the experienced net salvage rates on a per-pole basis aids in 1

understanding the historical results of the analysis. Analyzing per pole costs allows costs to be compared 2

against recent experience, engineering estimates, and future expectations. Dividing both the numerator 3

(Net Salvage $) and the denominator (Retirement $) for the 2014-2018 recorded net salvage rate by the 4

number of poles retired during the period restates the -200% net salvage rate on a per-pole basis (see 5

Figure III-8 below). 6


2009-2018 $89.1 ($169.6) -190%2009-2013 $20.9 ($33.4) -160%2014-2018 $68.2 ($136.2) -200%

37

Figure III-8 Recorded Net Salvage Rate Per Transmission Pole

(2014-2018 in dollars)

As shown in Figure III-8, the average recorded costs to retire and dispose 1

transmission poles were $6,140 per pole, which is two times the $3,075 average recorded plant cost per 2

transmission pole when placed into service about 50 years earlier. The $6,140 cost for transmission 3

poles is also about twice as high as the recorded average retirement cost for the distribution poles (see 4

Account 364 discussion). This incremental cost is reasonable because transmission projects are greater 5

in scale than distribution. The larger pole size and numerous internal and external stakeholders 6

associated with transmission poles increase costs at every stage in the replacement process. For example, 7

transmission projects require more planning and coordination related to permitting and outage 8

schedules. During replacement efforts, a transmission pole requires a larger crew and equipment 9

(frequently requiring cranes and larger boom trucks). Most often transmission lines must be de-10

energized and due to the effects on outages, the work must be completed during non-peak load hours 11

(premium time). Disposal costs are charged by weight, and transmission poles, which range from 65 to 12

125 feet, are significantly heavier than the average 45-foot distribution pole. Finally, due to the longer 13

span between transmission poles, there are fewer joint owners on the transmission system sharing the 14

cost to retire, resulting in lower gross salvage. 15

Although the account investment is split almost evenly between wood and steel 16

poles, the recorded -200% net salvage rate is most heavily driven by the wood poles, which make up the 17

largest portion of recorded retirements (both quantity and dollars). Steel poles, despite being nearly three 18

times as costly as wood poles to remove and dispose of, experienced a less negative net salvage rate 19

(i.e., -77% for steel versus -218% for wood) because of their higher average original cost. The lower net 20

salvage rate for steel poles results from two factors affecting the denominator: the higher original plant 21

Net Salvage $ ($136,176,544)Retirement $ $68,195,119

Net Salvage $/ Pole Retired ($136,176,544) / 22,180 Retirement $/ Pole Retired $68,195,119 / 22,180

Net Salvage $/ Pole Retired -$6,140Retirement $/ Pole Retired $3,075 -200%

= = -200%

=

= =

38

cost and the younger retirement age. First, other factors being equal, the net salvage rate for steel poles 1

has a higher cost to install the original poles due to higher material and labor costs. Additionally, the 2

steel pole population is less mature than wood poles as reflected in the average age of retirements (27 3

years for steel poles vs. 52 years for wood poles). As a result, the denominator is higher, resulting in a 4

less negative net salvage rate. 5

Table III-13 Net Salvage by Type of Pole


Because the net salvage rates for recorded retirements represent an over-6

weighting of wood poles, it is reasonable to adjust the weighted average net salvage rates to reflect the 7

current mix of surviving steel and wood pole plant investment. Re-weighting results in a less 8

negative -144% as shown in Table III-14, below. 9

Table III-14 Re-Weighted Net Salvage by Type of Pole


SCE’s experienced net salvage rates are a conservative indicator of future net 10

salvage costs because net salvage rates for both steel and wood poles will be more negative in the future 11

Major Percent of Net Salvage WeightedComponent Investment Rate (NSR) NSR

Wood, Fiberglass, & Composite Poles 48% -218% -104%Steel & Concrete Poles 52% -77% -40%Total -144%

39

as the costs in the numerator (net salvage $) continue to escalate with age.63 Although recorded history 1

supports a more negative net salvage rate of at least -144%, SCE conservatively proposes a net salvage 2

rate of -90%. 3

e) Account 356: Transmission Overhead Conductor and Devices (-80% 4

Authorized, -100% Proposed) 5

The currently authorized net salvage rate for transmission overhead conductor 6

is -80%. SCE proposes a -100% net salvage rate supported by recent retirement experience and SCE’s 7

analysis of historical data. As part of transmission, 80% of the account’s costs are allocated to FERC 8

rates, limiting the impact of SCE’s proposed increase to $1.4 million on a CPUC-jurisdictional basis. 9

This account consists of $1,653 million64 of transmission overhead conductors and 10

devices. Most of the account consists of overhead conductor and the remainder of the account consists 11

of ground wire/other and switches. A significant portion of this account’s retirement activity is related to 12

the TRTP. The large retirement activity associated with TRTP was removed because the size and scope 13

of the project is atypical of expected retirement activities. 14

63 The expected average service life of the transmission poles account is 65 years, the average retirement age for

the current plant balance will be older than the recent retirement experience (averaging about 50 years).

64 $342 million on a CPUC-jurisdictional basis.

40



Over the past ten years, SCE retired $20 million of plant from this account, 1

experiencing an overall net salvage rate of -254%. The composition of retired assets underlying the ten-2

year net salvage rate is over-weighted by switches. That is, the switches represented 30% of plant 3

retirements although they only represent 3% of the plant balance. Since overhead conductor has higher 4

negative net salvage rates, reweighting the historical net salvage rates consistent with the asset mix for 5

the account plant balance would change the net salvage rate from -254% to -308%. The average net 6

salvage rate from 2009 to 2013 was -375%, but in the most recent five years has become less negative 7

at -202%. Seventy percent of the account’s retirements occurred during this most recent five-year 8

period. Part of the reason for the less negative rate is an increase in planned retirement work, which 9

resulted in a lower cost to retire each asset. 10

Deconstructing the experienced net salvage rates on a conductor-foot basis aids in 11

interpreting the net salvage experience for this account. Overhead conductor comprises over 97% of the 12

account and, between 2014 and 2018, experienced an average net salvage cost of -$6.37 for each foot of 13

conductor. Dividing both the numerator (Net Salvage $) and the denominator (Retirement $) for the 14


2009-2018 $19.6 ($49.8) -254%2009-2013 $5.8 ($21.9) -375%2014-2018 $13.8 ($27.8) -202%

41

2014-2018 recorded net salvage rate by the feet of conductor retired during the period allows the -202% 1

net salvage rate to be restated on a per-foot basis. 2

Figure III-9 Recorded Net Salvage Rate Per Foot of Transmission OH Conductor


As shown in Figure III-9, above, the average recorded costs to retire and dispose 3

the overhead conductor assets were $6.37 per conductor-foot, which is 202% higher than the $3.15 4

average recorded plant cost per conductor-foot when placed into service about 45 years earlier. Given 5

the 21 years average remaining life of overhead conductor, the average cost to remove in the future 6

could be expected to increase from -$6.37 to about -$15.71 supporting a net salvage rate of -246%. 7

However, SCE proposes the less negative -100% which is equivalent to the recent five-year average 8

removal cost per conductor-foot. 9

f) Account 357: Transmission Underground Conduit (0% Authorized, 0% 10

Proposed) 11

The currently authorized net salvage rate for Transmission Underground (UG) 12

Conduit is 0%. SCE proposes to retain the authorized level of net salvage at this time. 13

This account consists of $273 million65 of conduit, trenches, and manholes/vaults. 14

In 2016, the Chino Hills Underground (CHUG) project went into service increasing the account 15

investment by nearly $200 million. Over the past ten years, this account has retired only $0.4 million, 16

representing less than 1% of the average plant balance. The limited retirement history makes it difficult 17

to draw conclusions about the overall net salvage rate expected in this account. 18




= ($27,843,526) 4,368,946 $13,763,802 4,368,946

= ($6.37) = -202%$3.15

Net Salvage $ = ($27,843,526) = -202%Retirement $ $13,763,802

42

Assets installed in this account for CHUG include 200,000 linear feet of UG 1

conduit, 42 vaults, and similar equipment. While some portion of this investment may be abandoned 2

underground, SCE expects it will be necessary to remove and replace the underground vaults to continue 3

safe and reliable service of the line in the future. However, due to limited retirement history, SCE 4

proposes a 0% net salvage rate until more information on the cost to retire CHUG becomes available. 5

g) Account 358: Transmission Underground Conductor and Devices (-15% 6


The currently authorized net salvage rate for Transmission Underground (UG) 8

Conductor and Devices is -15%. Analysis of the historical data supports a more negative net salvage rate 9

and SCE proposes the net salvage rate of -30% at this time. As part of transmission, 21% of the 10

account’s costs are allocated to FERC rates, limiting the impact of SCE’s proposed increase to $1.3 11

million on a CPUC-jurisdictional basis. 12

This account consists of $398 million66 of UG conductor, lightning arresters & 13

potheads, and cathodic protection & other. The average plant balance between 2009-2015 was $212 14

million. The balance in this account increased dramatically in 2016, primarily due to the CHUG project 15

for the construction of four miles of 500 kV underground transmission lines. Between 2009 and 2018, 16

SCE retired $21 million of plant from this account (8% of the average plant balance), 67% of which has 17

occurred in the past five years. The realized net salvage rate from these retirements ranged from -3% 18

to -70% with an overall ten-year average of -35% as shown in the Table III-16, below. 19

66 $315 on a CPUC-jurisdictional basis.

43



The asset composition for the historical net salvage rate has been over-weighted 1

for lightning arrestors & potheads retirements compared to the asset composition of surviving plant 2

balance. These assets which had a higher negative net salvage rate represented 52% of the plant 3

retirements occurring in the past ten years, but only represent 20% of the current plant balance. Re-4

weighting the historical net salvage results to more accurately reflect the composition of the plant 5

balance results in a slightly less negative net salvage rate of -33%. 6

Net salvage rates in the last five years show fluctuations, and there has been a 7

general trend towards more negative net salvage rates as demonstrated by the three-year rolling averages 8

and the recent five-year average of -41%. During this period, this account had significant programmatic 9

infrastructure replacement activity, which experiences a lower average cost of removal rate than 10

unplanned and breakdown related removal activities. In addition, the conservative ten-year average 11

supports a more negative net salvage rate. In light of recent retirement history, SCE proposes a net 12

salvage rate of -30% at this time. 13


2009-2018 $20.9 ($7.3) -35%2014-2018 $14.0 ($5.7) -41%

44

h) Account 359: Transmission Roads and Trails (0% Authorized, 0% 1

Proposed) 2

The $195 million67 in this account primarily consists of roads and trails, with a 3

small portion consisting of bridges and trestles and culverts. Retirements have been few and sporadic 4

resulting in limited net salvage experience. As such, SCE proposes retaining the currently authorized 0% 5

net salvage rate for this account. 6

2. Distribution Plant Net Salvage 7

a) Account 361: Distribution Substation Structures and Improvements (-25% 8


The currently authorized net salvage rate for Distribution Substation Structures 10

and Improvements is -25%. SCE proposes a net salvage rate of -40%. The impact of SCE’s net salvage 11

proposal is an increase in depreciation expense of $2.2 million. 12

This account contains the buildings, foundations, and other structures located at 13

over 750 distribution substation locations across SCE’s territory. The $697 million of investment in this 14

account is broadly distributed amongst these components. Retirement history is similarly distributed 15

across the broad array of assets. During the last ten years, SCE has retired $52 million of plant from this 16

account, representing 10% of the average plant balance over this time. Historical net salvage rates from 17

2009 to 2018 range from -15% to -64%, with a ten-year average of -40% as shown in Table III-17, 18

below. 19

67 $22 million on a CPUC-jurisdictional basis.

45



As demonstrated by the three-year rolling averages above, the historical 1

retirements have experienced more negative trends in the realized net salvage rates. The five-year 2

average for 2009 to 2013 of -26% increased to -49% for the most recent five years. These more negative 3

net salvage rates are driven in part by the advancing retirement age of infrastructure moving from an 4

average of 29 years to 35 years. The last five years are also more negative because of an increased share 5

of substation-related retirements (compared to service center related locations) which made up 6

approximately 30% of the total cost of removal during the period. These activities are also more 7

representative of the surviving plant balances, which have approximately 36% of the investment in 8

substations with the remainder in service center locations. Additionally, the composition of assets 9

reflected in the ten-year net salvage rate (-40%) is different than for the plant balance. Reweighting the 10

historical net salvage rates consistent with the asset mix for the plant balance would increase the net 11

salvage rate from -40% to -83%. Even though the most recent five-year retirement experience supports a 12

net salvage rate of about -50% based on the level of retirements, the increased retirement ages, and the 13


2009-2018 $52.5 ($21.2) -40%2009-2013 $20.0 ($5.2) -26%2014-2018 $32.4 ($16.0) -49%

46

asset composition of the surviving plant balances, SCE proposes a more conservative -40% based on the 1

10-year average net salvage rates realized for this account. 2

b) Account 362: Distribution Substation Equipment (-25% Authorized, -40% 3

Proposed) 4

The currently authorized net salvage rate for distribution substation equipment 5

is -25%. SCE proposes a net salvage rate of -40%. The impact of SCE’s net salvage proposal is an 6

increase in depreciation expense of $7.4 million. 7

This account consists of $2,728 million in station equipment at distribution 8

substations. The majority of the account is split between transformers, circuit breakers, monitoring 9

devices, and various substation equipment. During the last ten years, SCE has retired $131 million of 10

plant from this account, representing approximately 7% of the average plant balance over this time. 11



Generally the mix of retirements experienced over the past ten years is similar to 12

the mix of assets in SCE’s current plant balance. As such, reweighting the historical net salvage rates 13

consistent with the asset mix for the plant account increases the negative net salvage only slightly 14

from -69% to -75%. The three-year rolling average is frequently more negative than -40%. As such, 15

SCE proposes a conservative net salvage rate of -40% at this time. 16

47

c) Account 364: Distribution Poles (-210% Authorized, -210% Proposed) 1

The currently authorized net salvage rate for Distribution Poles is -210%. While 2

historical net salvage rates support an increase, SCE proposes retaining the authorized net salvage rate 3

of -210%. 4

This account consists of $3,148 million invested in 1.48 million distribution poles. 5

Between 2009 and 2018 SCE retired more than 292,000 distribution poles with an original cost of $163 6

million (8% of the average plant balance), with a significant portion of them occurring in the last three 7

years. Over the past ten years the annual realized net salvage rates from these retirements ranged 8

from -275% to -752% with an overall 10-year average of -508% as summarized in Table III-19, below. 9



Compared to the ten-year band, the net salvage rates in the last three years 10

(averaging -401%) were less negative than in prior years, but still substantially more negative than the 11

current authorized net salvage. The lower negative net salvage is partly attributed to increased gross 12

salvage from higher levels of third party joint pole credits recorded during that period. This increase was 13

due to a catch-up in joint pole billings related to the increase in pole removal volume starting in 2015. 14

Relying solely on the historical retirements and the net salvage rates the future net 15

salvage rate could reasonably be -400%. However, deconstructing the experienced net salvage rates on a 16


2009-2018 $162.8 ($826.4) -508%2016-2018 $94.5 ($378.4) -401%

48

per pole basis aids in interpreting and applying judgment to the results when comparing between past 1

and future retirements related to retirement age and cost escalation. Dividing both the numerator (Net 2

Salvage $) and the denominator (Retirement $) for the 2016-2018 recorded net salvage rate by the 3

number of poles retired during the period allows the -401% net salvage rate to be restated on a per-pole 4

basis (see Figure III-10 below). 5

Figure III-10 Recorded Net Salvage Rate Per Distribution Pole


GRA

The average net cost to remove, dispose and salvage each pole retired between 6

2016 and 2018 was $2,996 per pole (including joint pole credit offsets). Divided by the $748 average 7

original cost of each pole retired, reflecting SCE’s average cost to install a pole approximately 40 years 8

ago, yields the -401% net salvage derived from the Form D-6 9

In contrast to the historical retirements, the current plant balance has a greater 10

proportion of recent vintages and averages about 24 years old with an average original cost per pole of 11

$2,125. Adjusting the above net salvage rate by replacing the denominator with the $2,125 original plant 12

cost associated with the current plant balance results in a net salvage rate of -141% that would be 13

appropriate if the current plant balance were to retire today at an average age of 24 years. 14

With an average remaining life of about 27 years the current cost to remove can 15

be expected to increase from $2,996 to an average net removal cost of $6,415 at the time of plant 16

retirement Dividing this by the average cost of future retirements per pole ($2,125)68 results in an 17

68 $3,148M plant divided by 1.48M poles ≈ $2,125.

Net Salvage $ / Poles Retired /Retirement $ / Poles Retired /

Net Salvage $ / Poles RetiredRetirement $ / Poles Retired


= (2,996)$ = -401%$748

= ($378,387,974) 126,296 $94,450,369 126,296

49

estimated future net salvage rate of -302%, which is less than the historical results without the 1

judgments about the differences between recent retirements and the current plant balance. 2

Figure III-11 Net Salvage Rate Per Distribution Pole – Future Retirement


While SCE’s Form D-6 analysis and judgment supports a net salvage rate for 3

distribution poles of -300% or more negative, given the need in this rate case for the Commission to 4

address depreciation accruals in more accounts with wider gaps between the authorized level and SCE’s 5

currently experienced costs, SCE is proposing to retain the authorized rate of -210%. 6

d) Account 365: Distribution Overhead Conductor and Devices (-115% 7


The currently authorized net salvage rate for Distribution Overhead (OH) 9

Conductor and Devices is -115%. SCE proposes a -190% net salvage rate supported by recent retirement 10

experience and SCE’s analysis of historical data. The impact of SCE’s proposal is an increase in 11

depreciation expense of $29.8 million per year. 12

This account consists of $1,843 million of distribution OH conductor and devices. 13

The major components of this account are OH conductor (68%) and switches and devices (32%). 14

Between 2009 and 2018, SCE retired nearly 82 million linear feet of conductor and thousands of 15

switches and devices resulting in retirements of $145 million of plant (11% of the average plant 16

balance). More than 70 percent of this retirement activity took place between 2014 and 2018, largely due 17

to failure-based replacements and SCE’s OH Conductor Program and 4-kV Cutover Program. 18

Plant Balance (Future Retirement):

Net Salvage $ / Pole - Future X (1 + Escal Rate) ^(Rem'g Life)Original Plant $ / Pole

Net Salvage $ / Pole - Future X (1.0286) ^Original Plant $ / Pole

Net Salvage $ / Pole - FutureOriginal Plant $ / Pole

-$2,996

= -$6,415 = -302%$2,125

27 years$2,125

= -$2,996$2,125

=

50



Between 2009 and 2018, annual net salvage rates ranged from -206% to -341% 1

with an overall average of -242%. In aggregate, these experienced rates have fluctuated and are 2

becoming less negative, likely reflecting economies of scale realized from SCE’s OH Conductor 3

Program and 4-kV Cutover Program. However, the rates have remained more negative than -200% for 4

the entire ten-year period. A majority of the retirement activity has occurred in the last five years, 5

largely due to the aforementioned programs. The average net salvage rate experienced between 2014 6

and 2018 was -216% which is well above the authorized -115%. 7

The asset composition of the retirement history is not representative of the plant 8

balance. Retirements over-weight Switches and Other Devices and under-weight the OH conductor, 9

which has more negative net salvage rates. While Switches & Other Devices represent only 32% of the 10

plant balance at year-end 2018, these units represent double that level in the retirement history (64% 11

between 2009 and 2018). Switches & Devices had an average net salvage rate of -89% between 2009 12

and 2018, which is significantly less negative than the overall account average of -216%. On the other 13

hand, OH Conductor is under-represented in the retirement history, making up just 37% of the 14

retirements despite comprising 68% of the plant balance at year-end 2018. Re-weighting the historical 15

net salvage rates consistent with the asset mix for the account plant balance would make the ten-year net 16


2009-2018 $144.6 ($350.3) -242%2014-2018 $106.7 ($230.8) -216%

51

salvage rate more negative (moving from -242% to -383%) because overhead conductor has more 1

negative net salvage rates. 2

Deconstructing the experienced net salvage rates on a conductor-foot basis aids in 3

interpreting the net salvage experience for this account. Between 2014 and 2018 OH Conductor 4

experienced an average net salvage cost of -$4.38 for each foot of conductor. Dividing both the 5

numerator (Net Salvage $) and the denominator (Retirement $) for the 2014-2018 recorded net salvage 6

rate by the feet of conductor retired during the period allows the -216% net salvage rate to be restated on 7

a per-foot basis. 8

Figure III-12 Recorded Net Salvage Rate Per Foot of Distribution OH Conductor


As shown in Figure III-12, above, the average recorded costs to retire and dispose 9

the overhead conductor assets were $4.38 per conductor-foot, which is 216% higher than the $2.03 10

average recorded plant cost per conductor-foot when placed into service about 37 years earlier. The 11

average original cost of each foot of conductor retired is similar to the original cost of each conductor 12

foot still in service today, at $2.03 per conductor foot retired compared to $2.33 per conductor foot still 13

in service. If all conductor assets were to retire today, the realized net salvage rate would be -188%. 14

However, given the 32-year average remaining life of OH conductor, the average cost to retire in the 15

future is expected to increase from -$4.38 to -$10.80 supporting a much more negative net salvage rate 16

of -464%. 17

Weighting the net salvage results by major component (as per SP U-4), would 18

result in significantly more negative net salvage rates than the recently experienced -216% in this 19

account. Although recent retirements understate the expected future net salvage rate for this account due 20

to the under-weighting of the OH Conductor, SCE is proposing a more conservative -190% at this time. 21




= ($230,813,957) 52,694,494 $106,720,924 52,694,494

= ($4.38) = -216%$2.03

52

e) Account 366: Distribution Underground Conduit (-30% Authorized, -80% 1

Proposed) 2

The currently authorized net salvage rate for Distribution Underground (UG) 3

Conduit is -30%. SCE proposes a -80% net salvage rate supported by recent retirement experience and 4

SCE’s analysis of historical data. The impact of SCE’s proposal is an increase in depreciation expense 5

of $25.8 million per year. 6

This account consists of $2,391 million of Conduit (47%), Vaults (22%), and 7

above ground structures (31%). Between 2009 and 2018, SCE retired more than 900,000 feet of conduit, 8

1,100 vaults, and more than 80,000 above ground structures, amounting to $52 million in plant (3% of 9

the average plant balance). Approximately half of these retirements took place between the years 2016 10

to 2018. 11



The realized net salvage rates have ranged from -80% to -555% with an overall 12

average of -223%, and all rates are more negative than -190% from 2012 forward. The major 13

components of this account exhibit varying levels of negative net salvage rates with UG conduit being 14

the least negative net salvage rates and vaults being the most negative. The more negative net salvage 15


2009-2018 $51.6 ($115.0) -223%2014-2018 $35.2 ($90.5) -257%2016-2018 $26.2 ($57.2) -218%

53

rate for this account is driven by a greater volume of costly underground vault retirements. Even though 1

2015 produces the most negative net salvage rate of the ten-year history, isolating the study to the more 2

recent 3-year period (2016-2018) still produces a negative net salvage rate of -218%. 3

Conduit is used to house underground cables and has the most significant 4

investment in this account (47%), but is least represented in the retirement experience at just 2% of the 5

total account over the last three years. Sometimes retired underground conduit will be removed and in 6

other instances may be abandoned in place. Even when abandoned, costs to retire can still be incurred, 7

such as instances where it is necessary to dig down and cap the duct before it enters an underground 8

structure to keep debris from flowing into the structure. Even though the conduit retirement experience 9

is limited, the recorded experience shows the average net salvage rate between 2016 and 2018 10

was -104%. SCE retired 270,458 feet of conduit at a cost of $661,470 resulting in an average cost to 11

retire per foot of -$2.45. Dividing this by the average cost of each foot of conduit remaining on SCE’s 12

books ($5.24) results in a net salvage rate of -47% for the three-year period. 13

The majority of the retirements between 2016 and 2018 (89%) in this account 14

come from above-ground structures such as pull boxes and risers despite the fact that this group 15

represents only 31% of the plant investment. Over that three-year period, SCE retired 36,415 structures 16

at a cost of $38.6 million, resulting in an average cost per structure of $1,059. Dividing by the average 17

cost of each structure remaining on SCE’s books ($1,402) results in a net salvage rate of -76%. Future 18

negative net salvage rates are expected to be more negative due to inflation, increasing the future cost to 19

retire each structure. 20

Underground vaults are concrete structures used to house energized equipment 21

and represent 22% of the plant balance and 9% of retirements experienced. Vaults are very costly to 22

remove and there has been an increasing trend in the retirements of vaults due to age, deterioration and 23

the need to address safety concerns, as identified in the T&D infrastructure replacement program.69 Over 24

450 vaults were retired between 2016 and 2018 at an average cost of -$39,299. Nearly 30,000 vaults are 25

still in service as of year-end 2018 with an average surviving cost of $17,335. Dividing the cost to retire 26

(-$39,299) by the average surviving cost ($17,335) results in a net salvage rate of -227%. Future 27

negative net salvage rates are expected to be more negative due to cost escalation over the 32-year 28

remaining life, increasing the future cost to retire the vaults. Using the net salvage estimates for the asset 29

69 Refer to T&D testimony in Exhibit SCE-02, Vol. 01, for more information on underground structures.

54

components discussed above and weighting them based on the plant balance composition in accordance 1

with the STANDARD PRACTICE U-4 produces an aggregate net salvage estimate of -95%, as shown below: 2

Table III-22 Account 366 Composite Net Salvage Rate

(2016-2018)

Historical experience indicates a more negative net salvage rate is warranted for 3

this account. On an aggregate level, the most recent three-year average is 218%. A component re-4

weighted average also supports a more negative rate to at least as negative as 95% as shown in Table III-5

27, above. However, SCE is proposing a more conservative net salvage rate of -80% at this time. 6

f) Account 367: Distribution Underground Conductors and Devices 7

(Authorized -60%, Proposed -100%) 8

The currently authorized net salvage rate for Distribution Underground Conductor 9

and Devices is -60%. SCE proposes a net salvage rate of -100% supported by recent retirement 10

experience and SCE’s analysis of historical data. The impact of SCE’s net salvage proposal is an 11

increase in depreciation expense of $68.1 million per year. 12

This account consists of $6,487 million of Distribution Underground Conductors 13

and Devices. The majority of the account consists of Underground Conductor (83%) and the remainder 14

consists of Other Devices (17%). During the last ten years, SCE retired 53 million linear feet of 15

conductor from this account, or $405 million (8% of the average plant balance). The asset composition 16

of the retirement history and surviving plant is largely underground conductor.70 SCE incurred $673 17

million of net salvage costs to retire the $405 million of plant, resulting in a ten year average net salvage 18

rate of -166% as shown in Table III-23, below. 19

70 Retirements of underground conductor made up 71% of the total retirements in this account. Underground

conductor makes of 83% of the plant balance of this account.

Major Percent of Net Salvage Weighted Component Investment Rate (NSR) NSR

Above Ground Structures 31% -76% -24%Conduit 47% -47% -22%Vaults 22% -227% -50%Total -95%

55



The five-year rolling averages of net salvage rates over the recent retirement 1

history produce consistent estimates. The five-year averages shown above are all within the range 2

between -164% and -180%. The major driver of these net salvage rates is the average cost to remove UG 3

Conductor. SCE engineers state that under ideal conditions (e.g., there is easy access to the structure and 4

the ducts are not impaired by cable or underground apparatus) it takes a four-man crew between 8 and 5

16 hours to remove a 200 foot length of cable (i.e., a typical field assignment) depending upon the 6

conductor gauge. More difficult jobs can increase this work substantially resulting in higher removal 7

costs. For example, vaults that have filled with water will require draining. If the water appears to be 8

contaminated, a separate environmental crew is called to the site to drain the vault before work can 9

begin. In this case, contaminated or discolored water must be loaded into a tanker truck and disposed of, 10

rather than pumped into the street. This can take a crew of 2-3 men up to several hours to complete. 11

Relying solely on past experience, future net salvage rates could reasonably be 12

similar to the 10-year average of -166%. Deconstructing the experienced net salvage rates on a per asset 13

basis aids in interpreting the results of historical data. Dividing both the numerator (Net Salvage $) and 14

the denominator (Retirement $) for the net salvage rate by the number of assets retired during the period 15

allows the -166% net salvage rate to be restated on a per-asset basis (see Figure III-13, below). 16

Plant Net SalvageYear Retired Amount % of Ret. 3-yr Avg % 5-yr Avg % 2009 $24.4 ($36.5) -150%2010 $25.3 ($47.1) -186%2011 $36.5 ($63.1) -173% -170%2012 $38.7 ($66.5) -172% -176%2013 $34.8 ($58.0) -167% -170% -170%2014 $38.2 ($66.4) -174% -171% -173%2015 $49.1 ($101.3) -206% -185% -180%2016 $49.0 ($74.7) -152% -178% -175%2017 $60.5 ($104.7) -173% -177% -175%2018 $48.3 ($54.3) -112% -148% -164%

2009-2018 $404.9 ($672.6) -166%2014-2018 $245.2 ($401.4) -164%

56

Figure III-13 Recorded Net Salvage Rate Per UG Conductor Asset


The average net cost to retire each asset between 2009 and 2018 was $12.68 per 1

asset (e.g., conductor-feet). Given that the average age of the retirements was about 28 years, the 2

average plant amount retired from the books was $7.63 per asset. The recent net salvage of -$12.68 per 3

asset divided by the original plant amount of $7.63 per asset for these retirements results in the -166% 4

net salvage derived from Form D-6. This -166% net salvage reflects the cost escalation between the 5

original costs of the plant when originally installed (denominator) and the net removal costs (numerator) 6

when retired 28 years later. Applying the Form D-6-derived rate (e.g., -166%) to the current plant 7

balance to determine the net salvage included in the depreciation rate calculation assumes the 8

relationships in that rate will apply to future retirements. That is, it assumes that the following will 9

remain constant in the future: the net removal cost relationship to plant, the average retirement age, the 10

cost escalation rate, etc. If the fact pattern for the future is expected to be significantly different, then 11

some judgment is necessary to modify the historical results. 12

First, beginning with the denominator, the average original plant cost from the 13

retirements is $7.63 per asset, when placed into service on average about 28 years ago. The current plant 14

balance, on the other hand, averages about 18 years of age. Consequently, the average original plant cost 15

per asset for the current plant balance is much higher, at about $11.79. Adjusting the above net salvage 16

rate by replacing the denominator with the $11.79 original plant cost associated with the current plant 17

balance results in a net salvage rate of -108%. That is the rate that would be appropriate if the current 18

plant balance were to retire today at an average age of 18 years. 19

Net Salvage $ / Qty Retired /Retirement $ / Qty Retired /

Net Salvage $ / Qty RetiredRetirement $ / Qty Retired


= ($672,559,789) 53,060,289 $404,878,465 53,060,289

= ($12.68) = -166%$7.63

57

Figure III-14 Net Salvage Rate Per UG Conductor Asset – Current Retirement


However, the current plant balance will not be retired today and evaluating the 1

denominator alone goes only part way. It would take an additional 12 years for the current plant balance 2

to just reach the average age of the recent retirements. Moreover, the current plant has an average 3

remaining life of about 35 years. Therefore the numerator should be updated to reflect the retirement age 4

and cost escalation expected for the future retirements. The average net cost to retire each asset in the 5

future can be evaluated by taking the -$12.68 current cost and escalating it over the remaining life of the 6

account. As shown in the table below, applying a 2.86% annual escalation rate over the 35-year 7

remaining life would result in a future net removal cost of about $34 per asset retirement. Dividing this 8

by the average original asset cost of $11.79 results in an estimated future net salvage rate of -288%. 9

Recent Retirements:

Net Salvage $ / Qty - CurrentOriginal Plant $ / Qty

Plant Balance (If Retired Today):

Net Salvage $ / Qty - CurrentOriginal Plant $ / Qty

= -$12.68 = -166%$7.63

$11.79= -$12.68 = -108%

58

Figure III-15 Net Salvage Rate Per UG Conductor Asset – Future Retirement


The STANDARD PRACTICE U-4 Form D-6 approach supports a net salvage rate 1

estimate in excess of -160%. Deconstructing the net salvage rate demonstrates that (1) SCE’s recent 2

costs equate to a rate of about -110% before considering the cost escalation with asset aging, and 3

(2) based on the life expectancy of the assets, net salvage rates would increase to levels higher than 4

recent experience. SCE’s analysis supports net salvage rates much higher than the -60% currently 5

authorized, and although the analysis of this account justifies a larger increase, SCE proposes a 6

conservative net salvage rate of -100% at this time. 7

g) Account 368: Distribution Line Transformers (Authorized -20%, 8

Proposed -50%) 9

The currently authorized net salvage rate for Distribution Line Transformers 10

is -20%. Like many of the transmission and distribution accounts, the accumulated depreciation for this 11

account is currently under-accrued relative to the level it ought to be as a result of insufficient 12

depreciation accruals for negative net salvage. Unlike other accounts however, the degree of under-13

accrual is so excessive that SCE has incurred $150 million more in removal costs to retire assets than 14

has been authorized for net salvage in depreciation rates over the life of the account. That is, the 15

account’s accumulated depreciation balance for future removal cost is not only below the theoretical 16

levels, but has a negative balance. As previously discussed, the STANDARD PRACTICE U-4 provides for 17

recovery of accumulated depreciation imbalances over the remaining life. In this instance, the recovery 18

Plant Balance (Future Retirement):

Net Salvage $ / Qty - Future X (1 + Escal Rate) ^(Rem'g Life)Original Plant $ / Qty

Net Salvage $ / Qty - Future X (1.0286) ^Original Plant $ / Qty

Net Salvage $ / Qty - FutureOriginal Plant $ / Qty

35 years$11.79

= -$34.01 = -288%$11.79

= -$12.68$11.79

= -$12.68

59

of past under-accruals adds $31 million of annual accruals.71 To avoid adding to the deficit in the future, 1

the negative net salvage included in the depreciation rate should be addressed. SCE is requesting a net 2

salvage rate of -50% which would increase depreciation expense by $54.8 million per year. 3

This account consists of $4,218 million of Distribution Line Transformers. The 4

account consists of transformers (68%) and fuseholders and other devices (32%). Over the last ten years, 5

SCE retired 288,000 transformers and 451,000 fuseholders and devices, or $528 million (16% of the 6

average plant balance). SCE incurred $442 million of net salvage costs to retire the $528 million of 7

plant, resulting in a ten-year average net salvage rate of -84% as shown in Table III-24, below. 8



The retirement history demonstrates a fluctuating but increasingly negative annual 9

net salvage rate. The five-year averages move from -57% for the period 2009-2013 to -104% for the 10

most recent five-year period. The composition of the historical asset retirements reasonably represents 11

the composition of the surviving plant balance, with transformers making up 72% of the retirements and 12

71 Based on SCE’s currently authorized -20% net salvage rate.


2009-2018 $528.2 ($442.4) -84%2014-2018 $303.6 ($315.2) -104%

60

68% of the plant balance. Moreover, the net salvage rates experienced over the ten-year period are not 1

significantly different for the transformers (-83%) compared to the fuseholders (-84%). 2

If equipment is re-used, activities associated with making it ready for re-3

installation are charged to O&M. Prior to 2012, initial transformer removal costs were accounted for in 4

this way due to an assumption that the majority of the transformers would be refurbished. An estimated 5

amount was transferred from expense to cost of removal to account for the number of final retirements. 6

This estimate was found to be understated and in 2012 an accounting change was made to more 7

accurately reflect the costs to retire the transformers. SCE is focusing on the period of 2012 through 8

2018 as the starting point in evaluating the future net salvage. Between 2012 and 2018 the recorded cost 9

of removal per transformer has averaged about $1,600 per transformer. Dividing this cost by the average 10

cost of each transformer still in service of $3,862 supports a net salvage rate of at least -42%. Given the 11

19 year remaining life of transformers, the net salvage cost in the numerator is expected to increase to 12

$2,750 per transformer which results in a reasonable expectation of the future net salvage rate of -71% 13

Although this is lower than the average net salvage rate experienced since 2012 of -111% it is still much 14

more negative than the currently authorized net salvage rate of -20%. Although the analysis of this 15

account justifies a larger increase, SCE proposes a conservative net salvage rate of -50% at this time. 16

h) Account 369: Services (Authorized -100%, Proposed -100%) 17

The currently authorized net salvage rate Services is –100%. SCE proposes to 18

retain this currently authorized net salvage rate. 19

This account contains $1,494 million of overhead (OH) and underground (UG) 20

services and supporting infrastructure. Between 2009 and 2018 SCE retired $22 million of plant 21

representing 2% of the average plant balance. The realized net salvage rate over these ten years 22

was -474% as shown in Table III-25, below. 23

61



The net salvage rates in the most recent five years have decreased from an 1

average of -537% between 2009 and 2013, to -438% in the most recent five years. Net salvage rates over 2

the ten-year history tend to be more negative in years with more retirements from OH services. This is 3

because unlike UG services, OH services cannot be abandoned in place. 4

As discussed in the 2018 GRC,72 SCE believes that some of the retirement history 5

in this account may be impacted by quantity issues created in SCE’s accounting system. Prior asset 6

generations in this account required accounting for multiple phase service conductor as separate units of 7

property because the bare-wire services could be removed and replaced individually. SCE continued this 8

accounting practice after the bare-wire services were replaced with triplex and quadplex services which 9

could not be replaced on a phase-by-phase basis. While the overall quantity of assets on SCE’s books is 10

reasonable73 the inputs necessary to ensure that all three phases of a service are retired may have resulted 11

72 See SCE-25, Vol. 04 from SCE’s 2018 GRC (A.16-09-001).

73 The quantity of services on SCE’s books approaches 15 million for SCE’s 5 million customer accounts. This is reasonable assuming the majority of the services investment is in triplex with three phases.


2009-2018 $22.4 ($105.9) -474%2009-2013 $8.1 ($43.3) -537%2014-2018 $14.3 ($62.6) -438%

62

in under-retirements in the recorded history.74 Given how negative SCE’s recorded net salvage rates are, 1

even a tripling of the retirements (i.e., reducing the associated net salvage rates to one-third their levels) 2

would support net salvage rates more negative than SCE’s currently authorized -100%. At this time, 3

SCE proposes to retain the existing authorized net salvage rate of -100% while any potential data 4

inconsistencies, which are isolated to this account, are addressed. 5

i) Account 370: Meters (Authorized -5%, Proposed -5%) 6

The currently authorized net salvage rate for Meters is -5%. SCE is proposing to 7

retain the currently authorized net salvage rate of -5% at this time. 8

The $917 million investment in this account is almost entirely composed of 9

meters installed during SCE’s Smart Connect program implementation.75 The meters in this account are 10

relatively young in age, as this program was implemented between 2010 and 2012. Due to the young age 11

of the assets, limited retirement history76 is available from which to draw conclusions about the future 12

net salvage rate. Until more retirement history becomes available, SCE believes that it is reasonable to 13

apply the -5% net salvage rate that was authorized for SCE’s prior generation of meters. Since the 14

current average plant costs is $164 per meter, the -5% net salvage is equivalent to about $8 to remove 15

and dispose of the old meter when making a replacement. As such, SCE proposes to retain the currently 16

authorized net salvage rate of -5% at this time. 17

j) Account 371: Infrastructure Installed on Customer Premises 18

This account consists of $12 million of infrastructure installed to support SCE’s 19

Charge Ready program. Infrastructure installed in this account includes panels, conduit, trenching, and 20

conductor necessary to provide electric service to “make-ready” stubs that support electric vehicle 21

charging. The Commission Decision in SCE’s Charge Ready Application77 adopted revenue 22

requirements for beyond the meter infrastructure based in part on depreciation rates consistent with 23

SCE’s Services Account 369 due to the similarity of the infrastructure. The first installations in this 24

74 Because retirements have equal and offsetting impacts on plant and accumulated depreciation, there is no

direct impact to rate base as a result of any potential under-retirements.

75 This net salvage analysis focused on the retirement units associated with the ongoing investment in Smart Meters. The $95 million difference from the RDS is attributable to legacy meter retirement units, the costs of which were allocated to customers over six years between 2012 and 2018 per D.12-11-051.

76 Retirements of $8.4 million over the last ten years comprise roughly 1.1% of average plant balances.

77 A.14-10-014.

63

account were placed in service at the end of 2018 and as such, SCE does not have sufficient retirement 1

experience to recommend a change at this time. 2

k) Account 373: Streetlighting and Signal Systems (Authorized -30%, 3

Proposed -50%) 4

The currently authorized net salvage rate for Street Lighting & Signal Systems 5

is -30%. SCE proposes a net salvage rate of -50% supported by recent retirement experience and SCE’s 6

analysis of historical data. The impact of SCE’s net salvage proposal is an increase in depreciation 7

expense of $4.2 million per year. 8

This account consists of $864 million of Street Lighting and Signal Systems. The 9

majority of the account consists of poles, fixtures, and cable and conduit. During the last ten years, SCE 10

retired $98 million,78 which is 12% of the average plant balance. In 2017 and 2018 there was a large 11

increase in retirements due to the sale of streetlight assets to cities and local governments. Although 12

these sales are expected to continue through 2020, SCE will retain significant portions of its investment 13

in this account that is likely to have net salvage characteristics similar to what is shown in Table III-26, 14

below. 15

78 The analysis excludes retirements related to the sale of streetlight assets.

64


SCE incurred $130 million of net salvage costs to retire the $98 million of plant, 1

resulting in a ten-year average net salvage rate of -133%. A significant portion of the historical net 2

salvage results are driven by retirements of shorter-lived fixtures (luminaires). Due to the shorter lives of 3

these assets, the net salvage rate is less negative than other assets in the account such as electroliers, 4

conduit, etc. Weighting the net salvage results by the percent of investment results in a more negative 5

net salvage rate of -243%. Although a more negative net salvage rate is justified, SCE proposes a 6

conservative net salvage rate of -50% at this time. 7

3. General Plant Net Salvage 8

a) Account 390: General Buildings 9

The currently authorized net salvage rate for General Buildings is -10%. SCE 10

proposes to retain the authorized net salvage rate at this time. 11

This account consists of $1,080 million of buildings at SCE’s general offices, 12

operations centers, garages, and similar structures. During the last ten years, SCE had $100 million of 13

retirements (12% of the average plant balance). Most of the retirements in this account are related to the 14

interim removal of supporting systems such as HVAC, lease-hold improvements, water systems, etc. 15

65

SCE incurred $24 million of net salvage costs to retire the $100 million of plant, resulting in a ten-year 1

average net salvage rate of -23% as shown in Table III-27, below. 2


Over the ten-year period, average net salvage rates have remained consistent with 3

a five-year average between 2009 and 2013 of -24% and -23% over the last five years. Although the 4

consistency of the historical data supports a more negative net salvage rate, SCE is proposing to retain 5

the authorized net salvage rate of -10% at this time. 6


2009-2018 $100.3 ($23.5) -23%2009-2013 $42.6 ($10.2) -24%2014-2018 $57.7 ($13.3) -23%

66

IV. 1

DEPRECIATION STUDY FOR T&D SERVICE LIFE 2

This chapter presents the actuarial life analysis for T&D assets performed by external consultant, 3

Ronald E. White Ph.D. of Foster Associates Consultants, LLC. Dr. White provided SCE with life 4

parameters that SCE then used to support the calculation of the proposed depreciation rates. 5

A. Development of T&D Service Lives 6

Q. PLEASE EXPLAIN WHY DEPRECIATION STUDIES ARE NEEDED FOR 7

ACCOUNTING AND RATEMAKING PURPOSES. 8

A. The goal of depreciation accounting is to charge to operations a reasonable estimate of the cost 9

of the service potential of an asset (or group of assets) consumed during an accounting interval.79 10

A number of depreciation systems have been developed to achieve this objective, most of which 11

employ time as the apportionment base. 12

Implementation of a time-based (or age-life) system of depreciation accounting requires the 13

estimation of several parameters or statistics related to a plant account. The average service life 14

of a vintage, for example, is a statistic that will not be known with certainty until all units from 15

the original placement have been retired from service. A vintage average service life, therefore, 16

must be estimated initially and periodically revised as indications of the eventual average service 17

life become more certain. Future net salvage rates and projection curves, which describe the 18

expected distribution of retirements over time, are also estimated parameters of a depreciation 19

system that are subject to future revisions. Depreciation studies should be conducted periodically 20

to assess the continuing reasonableness of parameters and accrual rates derived from prior 21

estimates. 22

The need for periodic depreciation studies is also a derivative of the ratemaking process, 23

which establishes prices for utility services based on costs. Absent regulation, deficient or 24

excessive depreciation rates will produce no adverse consequence other than a systematic over or 25

understatement of the accounting measurement of earnings. While a continuance of such 26

practices may not comport with the goals of depreciation accounting, the achievement of capital 27

79 The service potential of an asset is the present value of future net revenue (i.e., revenue less expenses

exclusive of depreciation and other non–cash expenses) or cash inflows attributable to the use of that asset alone.

67

recovery is not dependent upon either the amount or the timing of depreciation expense for an 1

unregulated firm. In the case of a regulated utility, however, recovery of investor-supplied capital 2

is dependent upon allowed revenues, which are in turn dependent upon approved levels of 3

depreciation expense. Periodic reviews of depreciation rates are, therefore, essential to the 4

achievement of timely capital recovery for a regulated utility. 5

It is also important to recognize that revenue associated with depreciation is a significant 6

source of internally generated funds used to finance plant replacements and new capacity 7

additions. This is not to suggest that internal cash generation should be substituted for the goals 8

of depreciation accounting. However, the potential for realizing a reduction in the marginal cost 9

of external financing provides an added incentive for conducting periodic depreciation studies 10

and adopting proper depreciation rates. 11

Q. PLEASE DESCRIBE THE PRINCIPAL STEPS INVOLVED IN 12

ESTIMATING SERVICE LIVES. 13

A. The first step in estimating service lives is the collection of plant accounting data needed to 14

conduct a statistical analysis of past retirement experience. The data collection phase should 15

include a verification of the accuracy of the plant accounting records and a reconciliation of the 16

assembled data to the official plant records of the company. 17

The next step is the estimation of service life statistics from an analysis of past retirement 18

experience. The term life analysis is used to describe the activities undertaken in this step to 19

obtain a mathematical description of the forces of retirement acting upon a plant category. The 20

mathematical expressions used to describe these forces are known as survival functions or 21

survivor curves. 22

Life indications obtained from an analysis of past retirement experience are blended with 23

expectations about the future to obtain an appropriate projection life curve. This step, called life 24

estimation, is concerned with predicting the expected remaining life of property units still 25

exposed to the forces of retirement. The amount of weight given to the analysis of historical data 26

will depend upon the extent to which past retirement experience is considered descriptive of the 27

future. 28

68

B. 2019 Service-Life Study 1

Q. DID SCE PROVIDE FOSTER ASSOCIATES PLANT ACCOUNTING DATA 2

FOR ESTIMATING SERVICE LIFE PARAMETERS? 3

A. Yes. Service life statistics estimated in the 2019 study were derived from plant accounting 4

transactions recorded over the period 2002 through 2018. Detailed accounting transactions were 5

extracted from the Continuing Property Record (CPR) system and assigned transaction codes 6

which describe the nature of the accounting activity. Transaction codes for plant additions, for 7

example, were used to distinguish normal additions from acquisitions, purchases, 8

reimbursements and adjustments. Similar transaction codes were used to distinguish normal 9

retirements from sales, reimbursements, abnormal retirements and adjustments. 10

The accuracy and completeness of the assembled database was verified by SCE personnel 11

for activity years 2002 through 2018. Age distributions of surviving plant at December 31, 2018 12

were reconciled to the CPR. 13

Life statistics estimated in the 2019 service life study are dollar-weighted averages of the 14

unit-years of service derived from the age of aggregated retired property units. Retirement 15

vintages are assigned by SCE’s property accounting system using approved retirement frequency 16

distributions. The reported dollar amounts of units retired from service are obtained by 17

multiplying units retired by the average per-unit cost of associated vintage additions. This 18

approach eliminates issues related to tracking the original vintages of thousands of property units 19

and provides that the estimated “projection lives” in the 2019 study are based on retirements and 20

plant investment reflected in SCE’s plant ledger. 21

Q. HOW WERE SERVICE LIFE ESTIMATES DERIVED FOR SCE PLANT 22

AND EQUIPMENT? 23

A. As noted above, the first step in estimating service lives is called life analysis. All transmission, 24

distribution and general depreciable plant accounts were analyzed using a technique in which 25

first, second and third degree polynomials were fitted to a set of observed retirement ratios. The 26

resulting function was expressed as a survivorship function, which was numerically integrated to 27

obtain an estimate of the population projection life (i.e., mean of the parent population from 28

which observed retirements are viewed as a random sample). The observed proportions surviving 29

were then fitted by a weighted least-squares procedure to the Iowa curve family using the 30

69

estimated projection lives to obtain a mathematical description or classification of the dispersion 1

characteristics of the data. Service life indications derived from the statistical analyses were 2

blended with expectations about the future to obtain an appropriate projection life curve for each 3

plant category. The analysis of each plant account is contained in Appendix A. 4

Q. IS A PROJECTION LIFE THE SAME AS AN AVERAGE SERVICE LIFE? 5

A. No. A projection life is an estimate of the mean service life of the population from which 6

retirements are a random sample. The average service life of a plant category is a function of the 7

age distribution of surviving plant (i.e., plant currently in service by vintage year of installation) 8

and a selected level of asset grouping such as broad group, vintage group or equal life group. If 9

retirements are distributed over varying ages, the broad group procedure (which assumes that 10

each vintage has the same average service life) is the only grouping of assets that will produce an 11

average service life equal to the projection life estimated for a plant category. As noted above, 12

the projection life also reflects the plant investment retirements as recorded in the property 13

accounting system. 14

Q. PLEASE EXPLAIN IN GREATER DETAIL HOW LIFE ANALYSES WERE 15

CONDUCTED IN THE 2019 STUDY. 16

A. The fundamental probability distribution of interest in estimating the service life of industrial 17

property is called a hazard function. This function, which is also used in reliability theory, is an 18

equation that describes the conditional probability of retirement (called a hazard rate) during an 19

age interval given survival to the beginning of the interval. So, for example, the probability that 20

plant that has been in service, say for 5 years, will be retired during the 6th year is a conditional 21

probability of retirement. In other words, the probability is conditioned upon having achieved an 22

age of 5 years. 23

Graduating or smoothing observed hazard rates is an application of inferential statistics 24

which draws inferences and predictions about a population based on samples of data taken from 25

the population of interest. Projection lives and projection curves are population parameters 26

“inferred” from a statistical analysis of the underlying forces of retirement described by 27

probability distributions. 28

The object of a statistical analysis of plant retirements is to find the form of an equation that 29

best describes the conditional probabilities of retirement, where the form of the equation is 30

70

driven by the underlying forces of retirement. Any number of equations can be considered as 1

candidates for selection. The so-called Iowa curves are a family of distributions most often used 2

in conducting depreciation studies. 3

Each Iowa curve has a unique hazard function derived from the ratio of its retirement 4

frequency distribution to its survivor distribution. Unfortunately, however, Iowa hazard functions 5

cannot be written as parametric equations. It is for this reason that polynomials of the form 6

2 3y a bx cx dx are used to estimate hazard functions. The variable y is the hazard rate and 7

x is the age interval of the rate.80 Observed proportions surviving are plotted and fitted to Iowa 8

curves (using the estimated projections lives) to visually observe the mortality characteristics 9

expressed as an Iowa curve. 10

The problem, therefore, is to estimate the coefficients (i.e., a, b, c and d) of the polynomial 11

from an estimate of hazard rates derived from a sampling of historical retirements recorded for a 12

plant category. Different estimators of the hazard rate can be used depending upon the desired 13

statistical properties of the estimator. The ratio of retirements to exposures is most often used for 14

depreciation studies. 15

Coefficients were estimated in the 2019 study using Orthogonal Polynomials. An 16

orthogonal polynomial is not a special form of a polynomial. It is a procedure developed by 17

Tchebysheff to estimate the coefficients of a polynomial (using regression) without rewriting the 18

normal equations for each successive power of the polynomial. The coefficients of a second 19

degree equation, for example, can be derived from a first degree equation without rewriting the 20

equations used in a normal least-squares regression. 21

Coefficients and polynomials were estimated for numerous trials or samples of retirements 22

recorded over various bands of activity years. An activity year is the calendar year in which 23

retirements were recorded. Retirements from vintages of like ages are combined to increase the 24

size of the samples from which hazard rates are estimated. The motivation for examining various 25

bands of activity years is to observe service life trends to the extent they may be detectable. 26

Each polynomial was transformed or converted to a survivor function (or survivor curve 27

when plotted) from which an estimate of the projection life was derived. The polynomial form of 28

80 The reason polynomials are limited to a third-degree term (i.e., a polynomial having an 3x term) is that some

low modal Iowa curves exhibit two inflection points in a plot of the hazard function.

71

the hazard functions were also plotted and visually inspected as an aid to better understanding 1

the forces of retirement acting upon a plant category. 2

Observed proportions surviving were then fitted to Iowa-type curves with projection lives 3

set equal to those derived from the polynomials. The purpose of fitting to Iowa curves is to 4

obtain service life descriptors more familiar to users of Iowa curves. It would be more obscure 5

and less informative to describe survivor curves by the coefficients of a polynomial. 6

Q. WERE FACTORS OTHER THAN SERVICE LIFE INDICATIONS DERIVED 7

FROM THE STATISTICAL STUDIES CONSIDERED IN ESTIMATING 8

SERVICE LIVES FOR SCE? 9

A. Yes. As discussed above, estimating service lives is a two-step procedure. The second step (life 10

estimation) is concerned with predicting the expected remaining life of property units still 11

exposed to forces of retirement and the service life of future plant additions. It is a process of 12

blending the results of a life analysis with information (mostly qualitative) and informed 13

judgment to obtain an appropriate service life and curve descriptive of future expectations. The 14

amount of weight given to a life analysis will depend upon the extent to which the age of past 15

retirements is considered descriptive of the future. Both life analysis and life estimation require 16

an understanding of the limitations of statistical studies and the need for informed judgment. 17

A consideration in estimating service lives is the nature and meaning of the life statistic 18

estimated based on the ageing of retirements by the accounting system. The statistic is essentially 19

a dollar-weighted average of the unit-years of service derived from the age of aggregated retired 20

property units calculated by the property accounting system. The estimated service-life statistic 21

is descriptive of the accounting retirement data, not directly from the physical asset age of the 22

underlying retirement units.. 23

Q. ARE FACTORS YOU CONSIDERED IN LIFE ESTIMATION DESCRIBED 24

IN THE 2019 STUDY? 25

A. Yes. Appendix A contains a narrative explanation of both quantifiable factors (life analyses) and 26

non-quantifiable factors (largely life estimation) considered by Foster Associates in 27

recommending adjusted service lives and curves for SCE. 28

72

Q. PLEASE SUMMARIZE THE FINDINGS OF YOUR SERVICE–LIFE STUDY. 1

A. Current and recommended service lives and retirement frequency distributions (i.e., dispersions) 2

are summarized in Table 1 below. 3

4

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 5

A. Yes, it does.6

Current RecommendedAccount Description P-Life Dispersion P-Life Dispersion

A B C D E

Transmission Plant 352.00 Structures and Improvements 55.00 L1 55.00 L1353.00 Station Equipment 45.00 R0.5 45.00 L0.5354.00 Towers and Fixtures 65.00 R5 65.00 R5355.00 Poles and Fixtures 65.00 SC 65.00 SC356.00 Overhead Conductors and Devices 61.00 R3 61.00 R3357.00 Underground Conduit 55.00 R3 55.00 R3358.00 Underground Conductors and Devices 45.00 S1 45.00 S1359.00 Roads and Trails 60.00 R5 60.00 R5

Distribution Plant 361.00 Structures and Improvements 50.00 L0.5 55.00 L0.5362.00 Station Equipment 65.00 L0.5 65.00 S-.5364.00 Poles, Towers and Fixtures 55.00 R1 55.00 R1365.00 Overhead Conductors and Devices 55.00 R0.5 55.00 R0.5366.00 Underground Conduit 59.00 R3 59.00 R3367.00 Underground Conductors and Devices 43.00 R1.5 47.00 L1368.00 Line Transformers 33.00 S1.5 33.00 S1.5369.00 Services 55.00 R1.5 55.00 R1.5370.00 Meters 20.00 R3 20.00 R3373.00 Street Lighting and Signal Systems 48.00 L1 50.00 L0.5

General Plant390.00 Structures and Improvements 45.00 R0.5 50.00 SC

Table 1. Service-Life Statistics

73

V. 1

DEPRECIATION STUDY FOR GENERATION PLANT 2

SCE has a mix of generating facilities. Some of these, such as Palo Verde Nuclear Generating 3

Station and Mountainview, are large generating plants with a separately identified accumulated 4

depreciation that are expected to retire at a single point in time. Others, such as Solar PV and Hydro, are 5

a group of separate generating facilities that share a common accumulated depreciation. At all of these 6

facilities, smaller components are expected to retire earlier during the service life of the plant (called 7

“interim retirements”). Like T&D assets, the depreciation expense for generation facilities includes both 8

the original cost to install and the future cost to retire. This chapter presents the results of SCE’s 9

depreciation study for generation assets. SCE’s depreciation proposals for generation plant is shown in 10

Table V-28, below. 11

Table V-28 Generation Plant Depreciation Study Results

A. Average Service Lives 12

The life span for a generating facility (or group of facilities) depends on the factors affecting the 13

final shutdown, including: operating licenses, fuel and resource availability, contractual obligations, the 14

relative efficiency of the generating units, and so forth. The “total” life span is determined largely as an 15

engineering judgment based on these factors. In contrast, the “average” life span of the facility 16

recognizes that not all of the originally installed assets of the facility (or group of facilities, i.e., hydro) 17

Generation Facility Authorized Proposed ∆ Authorized Proposed ∆

A B C D=C-B E F G=F-EPalo Verde 23 23 0 42 66 24Hydro Production 34 31 (3) 119 125 5Hydro Decommissioning 0 15 0 446 446Mountainview Units 3&4 20 20 (0) 9 27 19Pebbly Beach 11 26 15 0 2 2Peakers 23 22 (1) 11 22 11Solar Photovoltaic 11 11 (0) 62 81 19Fuel Cell 2 3 1 0 3 3Energy Storage 10 20 10 0 0

Remaining LifeAs of Jan 1, 2021 (Years) Removal Cost ($M)

74

will remain in service over the total life span. To address this, SCE adjusts the life span downward to 1

take into account the shorter-lived interim retirements. 2

Interim retirements consist of such items as pumps, motors, and other individual components that 3

retire depending on the factors specifically affecting them—wear and tear, reliability, obsolescence, and 4

so forth. For generating facilities that have similar life characteristics and share a common accumulated 5

depreciation (i.e., Peaker plants, Solar PV, etc.), the interim retirement may result from the retirement of 6

one or more of the individual generating stations that are part of the group. The impacts of the life span 7

and the interim retirements on the overall average service life of the plant asset are determined 8

separately. SCE considered the interim retirement adjustment first by estimating the future level of 9

annual interim retirements as a percent of the plant balance (i.e., an interim retirement rate or IR rate). 10

An average IR rate is estimated by analyzing the historical levels of interim retirements and evaluating 11

anticipated retirements. Just as with mass plant, the expected interim retirement rate increases with the 12

age of the plant. Consequently, the historical levels understate the anticipated future IR rates. The 13

estimated annual IR rate is applied to the current plant balance over the remaining life span of the 14

generating plant and affects the overall remaining life of the generating station. For example, if a 15

generating plant has a 10-year remaining life span and an IR rate of 1.4 percent per year, then about 16

14 percent of the current plant balance would retire as interim retirements (10 years times 1.4 percent 17

year) and the remaining 86 percent would retire as a final retirement. The interim retirements have a 18

shorter remaining life than the final retirements occurring at the end of the life span. The resulting 19

survivor curve is shown in Figure V-16.81 20

81 The IR adjustment is equal to the area of the of the Survivor Curve, or ½ of the interim retirements. One-half

of 14% x the 10-year service life is 0.7 years.

75

Figure V-16 Life Span Survivor Curve*

* Remaining Life Span = 10 years; IR Rate = 1.4%.

B. Generation Net Salvage 1

1. Analysis of Net Salvage for Generation Property 2

Generation properties experience two types of net salvage costs, interim retirement net 3

salvage and final decommissioning, that are included in the depreciation study. The first, interim 4

retirement net salvage, is experienced as smaller components are retired and replaced over the life span 5

of each specific generating facility. As these smaller components experience wear-and-tear, reliability 6

issues, or obsolescence they will require replacement to keep the plant operational. The removal costs 7

experienced during replacement is referred to as interim retirement net salvage and is recovered over the 8

remaining life span of the units. The second net salvage cost, final decommissioning, is the expected 9

cost to dismantle and remove the plant from operations. The final retirement net salvage is based on 10

engineering estimates of the cost to remove and dispose of the plant and equipment that is existing at the 11

time of the station’s final shutdown. 12

The future net salvage estimates for generating stations will differ significantly 13

depending on a variety of factors. Although the net salvage consists of both interim retirement net 14

salvage and final decommissioning costs, the scale of decommissioning costs will generally drive the 15

0%

20%

40%

60%

80%

100%

0 1 2 3 4 5 6 7 8 9 10Years

Avg. Life = Rem. Life ‐ IR Adjustment

9.3 yrs = 10 yrs ‐ 0.7 yrs

% Surviving

IR Adjustment

76

overall net salvage levels required. In the case of Palo Verde, only interim retirement net salvage is 1

included in the current filing.82 2

2. Future Decommissioning Estimates 3

In SCE’s 2018 GRC, the company estimated decommissioning costs at the cost level 4

expected to be incurred at the time of the retirement, which is consistent with STANDARD PRACTICE U-4. 5

The 2018 GRC Decision adopted the decommissioning estimates underlying SCE’s proposed net 6

salvage estimates but did not include future cost escalation beyond 2020, the end of the 2018 GRC 7

period. Stating decommissioning costs at a value less than their cost in nominal dollars fails to achieve a 8

standard straight-line allocation as outlined in SP U-4, and results in deferring a portion of the cost 9

recovery to future customers in contravention of SP U-4. The Commission has previously underscored 10

its intent that the SP-U4 method use future net salvage costs (i.e., nominal retirement year dollars). The 11

Commission stated: 12

Under this [SP-U4] method, the undepreciated asset amount (original cost less 13

accumulated depreciation plus the estimated net salvage) is depreciated over the 14

remaining life of the asset. The net salvage includes the cost of removal of the 15

asset at the end of its useful life as well as any salvage value the asset may have at 16

that time. The original cost of the asset and the net salvage are expressed in 17

nominal dollars. For example, if the end of an asset’s useful life is 2010, the net 18

salvage would be expressed in nominal 2010 dollars.83 19

Using the current value of the final decommissioning costs, and deferring recovery of 20

cost escalation to future rate cases, is a “deferred” allocation method and does not fit into the 21

Commission’s SP-U4 straight-line remaining life method.84 A deferred approach results in charging 22

customers a higher cost of service over the life of the asset. In affirming its SP-U4 approach to include 23

future cost escalation in the decommissioning estimate, the Commission indicated a number of 24

82 The Commission addresses the final decommissioning costs of Palo Verde in the Nuclear Decommissioning

Cost Triennial Proceedings.

83 D.09-03-025, pp. 175-176 (emphasis added).

84 In PG&E’s 2007 GRC decision, D. 07-06-044, the Commission rejected a TURN argument that SP U-4 did not intend to include inflation stating, “We find that TURN’s interpretation of SP U-4 is not supported by the tables in SP U-4 which illustrate what was intended.”

77

intergenerational equity concerns that arise from deferring inflation, including the impact on rate base 1

and future rates.85 2

In light of the above concerns, SCE is continuing to propose accruing for future 3

decommissioning using costs stated in the year of the final retirement, which avoids excessive deferral 4

to future customers and is consistent with SP U-4. 5

For example, for Mountainview Generating Station, SCE is proposing to allocate the $14 6

million86 of unrecovered future decommissioning costs straight-line ($0.7 million per year) over the 7

20-year remaining life consistent with STANDARD PRACTICE U-4. Limiting the future cost escalation to 8

2023 (the end of this rate case cycle) would reduce annual accruals from $0.7 million to $0.4 million in 9

this rate case, but would require deferring accrual increases in each future GRC to make up for the 10

unrecovered amount. The required increases using this approach are not linear. Instead, as the escalation 11

costs are deferred and the remaining life of the facility is shortened, net salvage accruals must increase 12

faster than inflation and future customers bear increasingly larger portions of the deferred cost over 13

increasingly shorter periods. To prevent this inequitable distribution of service value, the 14

decommissioning proposals in the following sections adhere to the SP U-4 approach of valuing the 15

estimated future net salvage costs at the time of retirement and amortizing them straight-line over the 16

remaining life. 17

C. Palo Verde Nuclear Generating Station (PVNGS) 18

1. Average Service Life 19

The Nuclear Regulatory Committee (NRC) licenses for PVNGS Units 1, 2, and 3 end 20

June 1, 2045, April 24, 2046, and November 25, 2047, respectively, resulting in an average 27.5-year 21

remaining life span for the station as of December 31, 2018. In addition, recent retirement activity 22

indicates a required adjustment to the average remaining life of 2.1 years to 25.3 years to account for the 23

shorter-lived interim retirements. 24

2. Interim Retirement Net Salvage and Decommissioning 25

As discussed above, in the case of PVNGS, only interim retirement net salvage is 26

addressed in this filing. As can be expected of the increased plant age, recent retirement experience 27

85 D.09-03-025, p. 177.

86 Consisting of $18.6 million of anticipated future decommissioning costs (inclusive of inflation) less $4.6 million of decommissioning recovery as of year-end 2020.

78

indicates an increase in the interim retirement net salvage rates. Based on the recent 10-year average 1

retirements and net salvage experience, SCE is proposing to include the interim retirement net salvage 2

rates as shown in Table V-29, below. 3

Table V-29 Palo Verde Nuclear Generating Station

Interim Retirement Rate and Net Salvage

D. Hydro Generation 4

SCE’s Hydroelectric (Hydro) generating assets include powerhouses and generating units with a 5

total generation capacity of 1,176 MW. These assets include the large 1,015 MW Big Creek system in 6

the western Sierras, and several smaller systems with a total capacity of 161 MW located in the eastern 7

Sierras, the south-western Sierras and the San Gabriel/San Bernardino Mountains (collectively referred 8

to as small hydro). These systems can be divided into two types: (1) reservoir storage, and (2) stream 9

flow or “run-of the-river.”87 Hydro facilities with reservoir storage can hold back water during the spring 10

and early summer to allow increased utilization of the water during the hottest months (and highest 11

electricity demand) in late summer and early fall. Storing water in reservoirs extends the window of 12

opportunity for generation beyond the spring snow-melt runoff period and allows greater control and 13

utilization of the water. 14


Nearly all of SCE’s hydro facilities (99 percent) are covered by FERC licenses. 16

The licenses have a variety of termination dates—from currently expired (i.e., either in the process of 17

87 A run-of-the-river project does not have control of a storage reservoir as part of the project. Although these

projects generally have dams that divert water from the river into the Hydro project water conveyance facility, the dam impoundment does not store significant amounts of water.

FERC Interim Net Salvage Net SalvageAccount Description Retirement % % of Ret. % of Plant

321 Structures and Improvements 0.30% -30.0% -2.5%322 Reactor Plant Equipment 0.60% -20.0% -3.3%323 Turbogenerator Units 1.30% -20.0% -7.2%324 Accessory Electric Equipment 0.15% -20.0% -0.8%325 Misc. Power Plant Equipment 0.50% -25.0% -3.4%

79

being relicensed or decommissioned) to year 2046. The total life span of SCE’s current remaining 1

license periods for those plants without expired licenses range between 5 and 30 years. For licenses 2

being renewed, FERC has recently issued licenses with periods averaging about 40 years. 3

Prior license renewal does not guarantee that a generating plant will last indefinitely. For 4

example, FERC may not grant the company licenses, generating units may become uneconomic, or 5

environmental concerns will weigh in favor of discontinuing operations. Moreover, the individual 6

components in a generating station will continue to wear out, become obsolete, damaged, or otherwise 7

need to be retired and replaced. 8

Consequently, SCE continues to propose that the hydro generation plant be depreciated 9

over the remaining life spans associated with each plant’s individual FERC license, and adjusted for 10

interim retirements expected during the period.88 For generating stations with already expired licenses, 11

or with licenses that are within 5.5 years of termination, SCE extends the life spans of the generating 12

stations by the estimated license life extension resulting from re-licensing.89 13

2. Interim Retirements and Net Salvage 14

Interim retirement rates and associated net salvage rates are calculated by analyzing the 15

recent retirement history for the level of net salvage incurred apart from final retirements. The ratio of 16

net salvage (gross salvage less cost of removal) divided by the retirement values is used to arrive at the 17

interim net salvage rates shown in Table V-30, below. 18

88 In the case of the 1 percent of hydro plant not covered by a FERC license, SCE applies the average life

determined for the plant that is covered by FERC license.

89 The average application license period is 40 years. The exception to this life span extension is the amortization period for the hydro relicensing costs. These relicensing costs are only amortized over the associated license period for which they were spent.

80

Table V-3090 Hydro Interim Retirement and Net Salvage

3. Hydro Decommissioning 1

In SCE-05, Volume 1, SCE describes why decommissioning small hydro plants has 2

become more likely in the coming years. To ensure adequate cost recovery, SCE proposes to include a 3

probability-adjusted annual accrual of $29.6 million for decommissioning in this rate case. 4

The Commission has authorized SCE to accrue funds over the useful lives of its nuclear, 5

fossil, and solar photovoltaic generation assets to provide equitable recovery for the cost to 6

decommission generation assets when they are retired from service. Until now, hydro assets have been 7

considered as potentially perpetual facilities with recovery of the ongoing asset investments and interim 8

retirements only; ultimate decommissioning has generally not been assumed. Now, as a result of aging 9

infrastructure, changes in the California energy market, and increasing costs to license and operate the 10

facilities, it is increasingly apparent that many of SCE’s small hydro powerhouses may indeed be retired 11

and removed from service. To address intergenerational equity, the decommissioning costs associated 12

with an asset should be recovered from the customers who benefit from the asset. Consequently, it is 13

appropriate to begin accruing for the decommissioning of hydro assets beginning in 2021. 14

It is challenging to predict which plants will be decommissioned due to the complexity of 15

issues such as licensing costs, environmental compliance-related costs, water rights, recreational use, 16

flood control, and other considerations involving affected stakeholders. The smaller hydro generation 17

facilities (i.e., below 30 MWs) face a greater likelihood of decommissioning than the larger scale hydro 18

facilities (e.g., Big Creek and Kern River 1 & 3). As described in SCE-05, Volume 1, SCE assembled a 19

probability-adjusted decommissioning cost estimate for each small hydro plant. The estimates include 20

90 Refer to WP SCE-07 Vol. 03, Book A pp. 170-172 (Hydro Generation).


331 Structures and Improvements 0.25% -140.0% -11.4%332 Reservoirs, Dams, and Waterways 0.35% -65.0% -7.9%333 Water wheels, Turbines and Generators 0.65% -40.0% -7.9%334 Accessory Electric Equipment 0.35% -120.0% -12.6%335 Miscellaneous Power Plant Equipment 0.40% -55.0% -6.7%336 Roads, Railroads and Bridges 0.20% -200.0% -14.1%

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the costs of physical decommissioning as well as related engineering and permitting costs. SCE has one 1

plant, San Gorgonio, that is currently being decommissioned. For the remainder of the small hydro fleet, 2

SCE assigned probabilities for decommissioning using five probability levels together with an 3

assumption about when decommissioning for particular plants might start. 4

The annual accrual was developed by dividing the probability-adjusted future 5

decommissioning cost (e.g., including inflation) by the years to decommissioning. That is, each facility’s 6

decommissioning cost was first multiplied by its probability of decommissioning to adjust the aggregate 7

$905 million estimate (for the group) to $326 million. Then, the estimate was escalated to the average 8

year decommissioning activities are expected to take place ($446 million), consistent with SP U-4. 9

Finally, this future estimate was divided by the estimated remaining time to decommission. Because of 10

the complexity of the decommissioning activities, SCE added 10 years to the retirement year to estimate 11

the length of time that decommissioning activities are expected to take place resulting in an average 12

remaining life in 2021 of 15 years. The resulting annual accrual is $30 million as summarized in the 13

table below. 14

82

Table V-31 Small Hydro Decommissioning Accruals


SCE will continue to use the broad group depreciation procedure for the removal cost 1

recovery so that the accumulated depreciation would be shared across the portfolio of hydro generation. 2

Decommissioning cost estimates will be refined as scope and requirements become more clear through 3

the FERC relicensing process. Customers will be held indifferent because under-recovery for one plant 4

can be made up by collections on other properties.91 Commencing cost recovery for small Hydro 5

decommissioning as part of this 2021 GRC rate cycle is reasonable and appropriate because assuming 6

indefinite longevity of these plants no longer realistic. Additional details regarding Hydro 7

decommissioning are provided in SCE-05, Volume 1– Generation. 8

91 As depreciation expense is recorded to the reserve, any under- and over-accruals are amortized over the

remaining life of the asset group. This ensures that customers do not over- or under-pay for the final costs of decommissioning.

Plant

Decom. Estimate (2018 $)

Decom. Prob.(1%, 10%, 50%,

90%, 99%)

Approx. Year Decom. Would

Begin

Probability-Adjusted

Decom. EstimateFuture Dollars

Life Extension

Remaining Life

Annual Accrual

A B C D E=B*C F1 G H=D-2021+G

I=F/H

Borel $117.1 99% 2025 $116.0 $154.0 10 14 $11.0Rush Creek (Agnew, Rush M.) $46.3 90% 2027 $41.7 $58.0 10 16 $3.6Rush Creek (Gem) $167.1 50% 2027 $83.6 $116.3 10 16 $7.3Lower Tule River $21.9 50% 2033 $11.0 $17.6 10 22 $0.8Kaweah 1-2 $88.8 10% 2021 $8.9 $10.7 10 10 $1.1Kaweah 3 $45.8 50% 2026 $22.9 $31.1 10 15 $2.1Lundy (Mill Creek) $17.7 10% 2029 $1.8 $2.6 10 18 $0.1Bishop Creek 2-6 $214.2 10% 2024 $21.4 $27.8 10 13 $2.1Poole (Lee Vining Creek) $82.4 10% 2027 $8.2 $11.5 10 16 $0.7Fontana $11.3 10% 2033 $1.1 $1.8 10 22 $0.1Lytle Creek $15.8 10% 2033 $1.6 $2.5 10 22 $0.1Mill Creek No. 1 $7.1 10% 2033 $0.7 $1.1 10 22 $0.1Mill Creek No. 3 $24.2 10% 2033 $2.4 $3.9 10 22 $0.2Ontario No. 1 $10.9 10% 2033 $1.1 $1.8 10 22 $0.1Ontario No. 2 $5.3 10% 2033 $0.5 $0.9 10 22 $0.0Santa Ana 1 & 3 $24.2 10% 2033 $2.4 $3.9 10 22 $0.2Sierra $5.1 10% 2033 $0.5 $0.8 10 22 $0.0Total $905.2 $325.7 $446.2 15 $29.61/ F=E*1.0239^(D-2018+5)

83

E. Pebbly Beach 1


SCE is proposing to retain the currently authorized 25-year average service life for 3

Pebbly Beach Generating Station based on the anticipated operating time between zero-time overhauls.92 4

Although the proposed 25-year service life of the plant is the same as in the prior GRC, SCE is including 5

a significant extension to the remaining life of the station (from 14 years to 29 years) based on the 6

proposed replacement of the diesel generators at the site.93 There have been few interim retirements in 7

the recent past from which to draw conclusions about the future. However, the replacement of the diesel 8

generators and other work at the facility will result in significant interim retirements warranting an 9

adjustment to the remaining life. SCE proposes to adjust the remaining life of the facility equipment 10

based on an SC-200 retirement curve as a conservative estimate94 of future interim retirements. The 11

shorter life of interim retirements adjusts the average remaining life by 1.1 years to 27.9 years. 12

2. Net Salvage 13

There is limited recent retirement history at Pebbly Beach available to estimate an interim 14

retirement net salvage rate. However, there is an expectation that capital expenditures will be required to 15

replace smaller components expected to retire before the end of the average service life. These expected 16

future interim retirements require an estimate of a net salvage rate. The average net salvage rate 17

experienced for interim retirements at Mountainview Generating Station between 2014 and 2018 18

was -33%. The additional transportation costs to and from the island will likely result in more negative 19

net salvage rate than what SCE has experienced at Mountainview. However, SCE proposes a 20

conservative -30% interim retirement net salvage rate at this time. 21

F. Mountainview 22


SCE proposes to retain Mountainview’s currently authorized 35-year average service 24

with a 22-year remaining life span as of year-end 2018 (Mountainview Units 3&4 originally went in 25

service in 2005). The shorter life of interim retirements adjusts the average remaining life by 0.4 years 26

to 21.6 years. 27

92 A “zero-time overhaul” restores operations of the unit to like-new operating conditions.

93 See SCE-05, Volume 1.

94 An SC-200 curve results in a 0.25% of the original plant retiring each year.

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Table V-32 Mountainview Generating Station Interim Retirement Rates

2. Net Salvage and Decommissioning 1

SCE is proposing to retain the currently authorized decommissioning estimate for 2

Mountainview Generating Station with updates to include the cost increase expected through the year of 3

retirement. The 2018 GRC Decision authorized SCE to recover the cost to decommission Mountainview 4

at 2020 levels of cost, or $8.6 million. The decommissioning cost increases to $18.6 million through the 5

retirement year,95 resulting in a $0.5 million increase in annual depreciation expense.96 6

While SCE did not request recovery of interim retirement net salvage in its prior rate 7

cases, recent retirement activity supports a modest increase. As such, SCE is proposing to include the 8

interim retirement net salvage rates as shown in Table V-32, above. 9

G. Peakers 10


SCE is proposing to retain the currently authorized 35-year average service life for 12

Peakers. Although there is limited retirement history, it is reasonable to expect that components of the 13

plant will experience additional wear and tear requiring replacement sometime over the 24.6 year 14

average remaining life of the units. There have been insufficient interim retirements available on which 15

to rely for an estimate of the IR rate for this plant, so SCE proposes a conservative IR rate of 0.25% 16

95 This increase reflects the results of two adjustments. The first, accounting for $2.8 million of the increase,

corrects a modeling issue not previously identified in SCE’s 2018 GRC decision. The balance of the impact is from SCE’s proposal to include inflation through the final year of retirement so that recovery is consistent with straight-line depreciation as authorized in the 2009, 2012, and 2015 General Rate Cases.

96 Refer to WP SCE-07, Vol. 03, Book A p. 175 (Mountainview).


341 Structures and Improvements 0.15% -150.0% -5.0%342 Fuel Holders, Producers, and Accessories 0.00% 0.0% 0.0%343 Prime Movers 0.20% -20.0% -0.9%344 Generators 0.05% -60.0% -0.7%345 Accessory Electric Equipment 0.10% -25.0% -0.6%346 Misc. Power Plant Equipment 0.00% 0.0% 0.0%

85

based on an SC-200 curve to estimate an IR rate for this plant. The shorter remaining life of the interim 1

retirements adjusts the average remaining life by 0.7 years, to 23.9 years, for these plants. 2


SCE is proposing to retain the currently authorized decommissioning estimate for 4

Peakers units97 with updates to include the cost increase expected through the year of retirement. The 5

2018 GRC Decision authorized SCE to recover the cost to decommission Peakers at 2020 levels of cost, 6

or $11.5 million. The decommissioning cost increases to $14.8 million through the retirement year, 7

resulting in a $0.1 million increase in annual depreciation expense.98 Available retirement history is too 8

limited to draw conclusions about the interim retirement net salvage rate; consequently SCE proposes to 9

use the average net salvage rate experienced at Mountainview between 2014 and 2018 of -30%. 10

H. Solar Photovoltaic 11

1. Average Service Life (Authorized 20 years, Proposed 20 years) 12

SCE is proposing to retain the currently authorized 20-year average service life for Solar 13

Photovoltaic (PV) equipment. The current 20-year life estimate is based largely on the lease terms for 14

the rooftops, which grant SCE rights to use the rooftop facilities for the same period as the lease. Given 15

the uncertainty of lease renewal and short expectations about the life of the equipment once it is 16

removed or relocated, a 20-year average service life proposal is reasonable for this account. The 17

remaining life and average remaining life are both 12.7 years. 18


SCE is proposing to retain the currently authorized decommissioning estimate for all but 20

one of its Solar PV units99 with updates to include the cost increase expected through the year of 21

retirement. The 2018 GRC Decision authorized SCE to recover the cost to decommission the Solar PV 22

facilities at 2020 levels of cost, or $62.0 million. The estimated decommissioning cost increases to $81.4 23

million through the retirement year, resulting in a $1.5 million increase in depreciation expense.100 24

97 SCE’s authorized decommissioning costs are based on a 2007 study performed by Arcadis estimating the cost

to retire each of SCE’s five Peaker units.

98 Refer to WP SCE-07 Vol. 03, Book A p. 186 (Peakers).

99 The decommissioning estimate for SPVP044-Perris is being updated to reflect an amount equal to SCE’s capital expenditures in this rate case. See Section V.H.3, below.

100 Refer to WP SCE-07 Vol. 03, Book A p. 188 (Solar Photovoltaic).

86

Because of limited retirement history, SCE is not proposing recovery of interim retirement net salvage at 1

this time. 2

Table V-33 Solar Decommissioning Costs by Panel Type


3. SPVP044 - Perris Solar Retirement 3

As discussed in SCE-05, Vol. 1, in May 2019, SCE received notice that the SPVP044 – 4

Perris site requires roof repairs, which necessitates removal and retirement of the investment after seven 5

years of service. SCE has invested $371 million at 25 Solar PV rooftop sites. The retirement of this 6

single asset, SPVP044 – Perris, is expected to result in a portion ($39.8 million) of this total investment 7

being retired prior to having reached the end of the average service life of the broad group of solar 8

assets. SP U-4 offers guidance on how unrecovered costs should be treated when assets retire earlier 9

than expected for the broader group. Specifically: 10

In group accounting all units having like mortality characteristics or all units of an 11

account are considered together. Accruals for the group are based on composite or 12

weighted average values of … service life expectancy. …. A deficiency due to 13

early retirement of a unit is made up through greater accruals on a unit which 14

outlives the average.101 15

This is in contrast to unit accounting, which requires a specific record and depreciation 16

reserve for each individual item of property. Because of the specificity required in unit accounting, SP 17

U-4 acknowledges that “the group basis is more feasible for most classes of utility property where large 18

numbers of units are involved.”102 With 25 different Solar PV sites, representing various installation 19

circumstances, equipment types, and rooftop versus ground-mounted installations, SCE’s Solar PV 20


102 Id.

Cost/MW to MW Authorized SCE ProposedSolar Type Ret. (2011$) Installed 2020$ Ret. Yr. $Rooftop - Floating $521 53.5 $37 $47Rooftop - Anchored $547 31.1 $22 $31Ground Mount $300 6.8 $3 $4Total $62 $81

87

assets meet the criteria described in U-4 regarding group accounting. The early retirement of the Perris 1

site leaves the vast majority (nearly 90%) of the solar assets in-service and does not violate group 2

depreciation principles established by the Commission. That is, there is a large portion of the solar 3

installation in service over which to allocate the unrecovered costs. As such, consistent with the average 4

life, broad group depreciation concepts in STANDARD PRACTICE U-4, the unrecovered cost of the retired 5

assets will be amortized over the remaining life of the surviving solar photovoltaic asset group. 6

I. Fuel Cells 7

SCE owns and operates two fuel cell demonstration facilities that were installed in connection 8

with a Commission-approved program in 2012 and 2013.103 The plants are located at California State 9

University, San Bernardino (CSUSB) and University of California Santa Barbara (UCSB). SCE 10

proposes to retain the currently authorized 10-year average service life. This proposal is consistent with 11

the facilities’ 10-year lease. 12

As explained in Exhibit SCE-05, Volume 1, SCE has not previously sought recovery of the 13

future costs of removal for the Fuel Cells because of a prior expectation that SCE would ultimately 14

transfer ownership to site hosts at the end of the facilities’ 10-year life. The current estimate of the cost 15

to remove these facilities is $3.0 million. SCE proposes to amortize this amount through the end of the 16

expected life of the facilities, or 2023, necessitating recovery of $1.0 million per year in 17

decommissioning expense. This is reasonable because, pursuant to the terms of the contract executed by 18

SCE and the counterparty campuses, SCE will be obligated to remove the assets if the site owners so 19

request at the end of the lease terms in 2022 and 2023. Any unspent removal costs (owing to a potential 20

transfer of the assets to the campuses, for example) would be returned to customers. 21

J. Energy Storage 22

Since the last rate case, three energy storage facilities have been deployed in SCE’s service 23

territory. Each facility contains new infrastructure for battery enclosures, battery modules, and 24

supporting equipment and traditional infrastructure such as power inverters, transformers, and switch-25

gear. The currently authorized life of this equipment is 10 years based on the risk of technological 26

obsolescence associated with deployment of new technologies. To partly mitigate this risk, SCE has 27

entered service agreements and performance agreements to ensure operations will meet standards for 20 28

years past the installation date. SCE proposes to extend the currently authorized life of the units from 10 29

103 D.12-04-011.

88

years to 20 years because the majority of the investment (83%) in this account is covered by 20-year 1

service and performance guarantees. Although it is reasonable to assume some costs to retire these assets 2

in the future (e.g., for labor and disposal fees), SCE is not proposing to include removal costs for energy 3

storage assets at this time because of manufacturer guarantees covering the costs of replacements in the 4

near term. 5

89

VI. 1

DEPRECIATION STUDY FOR GENERAL AND INTANGIBLE PLANT 2

Some categories of plant do not lend themselves to statistical analysis, but do not belong in the 3

life span category. These plant assets include most general plant (i.e., FERC Accounts 391-397), 4

intangible plant (e.g., software, radio frequencies, etc.), and easements. SCE determined average service 5

lives through conducting discussions with SCE engineers familiar with the assets, considering prior 6

company procedure, and relying on knowledge of (or research into) industry practice. 7

Table VI-34, below, shows the forecast depreciation service lives for general and intangible plant 8

accounts. The table compares SCE’s proposed depreciation rates to authorized service lives from 9

D.19-05-020 (the 2018 GRC Decision). SCE is proposing to retain the currently authorized average 10

service lives for all general and intangible accounts included in this section with the exception of 11

Account 391.4 (DDSMS - Power Management System). As described below, SCE is proposing a life 12

extension for this account from an average of 8.5 years to 10 years. 13

90

Table VI-34104 General and Intangible Plant Service Life Proposals

A. General Plant 1

Most general and intangible plant accounts contain many low-value, relatively short-lived 2

individual items. Following FERC guidelines, non-structural items in these accounts are amortized by 3

vintage group over the specified service life and retired at the end of the life span.105 For example, 4

personal computers are amortized over a 5-year period (i.e., a 20 percent annual depreciation rate) and 5

104 Refer to WP SCE-07 Vol. 03, Book A p. 193 (G&I Rate Determination Schedule).

105 FERC Accounting Release Number AR15 provided for the vintage year accounting method allowing companies to amortize vintage groups of assets over their designated service life and subsequently retire them. See https://www.ferc.gov/enforcement/acct-matts/docs/ar-15.asp.

FERC 2018-2020 2021-2023Account Description Authorized Proposed

General Plant391.1 Office Furniture 20 20391.2-3 Personal and Mainframe Computers 5 5391.4 DDSMS - Power Management System 8.5 10391.5-6 Office Equipment 5 5393 Stores Equipment 20 20394 Tools & Work Equipment 10 10395 Laboratory Equipment 15 15397 Telecommunication Equipment 17.9 17.9398 Miscellaneous Equipment 20 20

Intangibles302.020 Hydro Relicensing Various Various303.640 Radio Frequency 40 40302.050 Miscellaneous Intangibles 20 20303.105 Capitalized Software - 5-year 5 5303.707 Capitalized Software - 7-year 7 7303.210 Capitalized Software - 10-year 10 10303.315 Capitalized Software - 15-year 15 15

Easements350 Transmission Easements 60 60360 Distribution Easements 60 60389 General Easements 60 60

91

when a vintage group reaches five years of age, the vintage group of computers will be retired off the 1

books. Following this approach eliminates costly plant record-keeping and continuous physical tracking 2

of the equipment. Over time, imbalances in the accumulated depreciation can occur if, for example, 3

there are depreciation life or rate changes and if net salvage is recorded to the books but not reflected in 4

the depreciation rate. These accumulated depreciation surpluses (deficits) are amortized over the GRC 5

cycle (2021-2023). 6

1. Account 391.1 – Office Furniture 7

Account 391.1 contains all costs incurred to acquire office furniture. It includes such 8

items as modular furniture, desks, and cabinets used for general utility service that are not permanently 9

attached to buildings. SCE proposes retaining the currently authorized 20-year average service life for 10

this account. 11

2. Account 391.2 And 391.3 – Computer Equipment 12

The assets in Account 391.2 can include mostly personal computers and associated 13

components (e.g., monitors, printers, etc.) when purchased as a bundled unit, or when any of these items 14

are purchased individually and meet the capitalization threshold. Account 391.3 is where SCE records 15

all investment related to mainframe computer and file server equipment. SCE proposes retaining the 16

currently authorized 5-year average service life for this account. 17

3. Account 391.4 – Power Management System 18

This account represents a $89.2 million net investment in Supervisory Control and Data 19

Acquisition (SCADA) equipment for controlling and monitoring the SCE electrical system. Contained 20

within this account are the components making up the Power Management System, specifically 21

computer and data gathering equipment, man-machine interface, analog and digital telemetry devices, 22

and data center facility infrastructure. Although this account consists of components with varying levels 23

of technical sophistication and other factors affecting retirements, 95% of the SCADA investment have 24

current authorized service lives of 7 years (44%) and 10 years (51%), or a combined 8.5 years (on a 25

dollar weighted basis). SCE’s power management personnel have assessed this equipment and indicate 26

that the currently authorized lives are still reflective of current expectations. Given that about 95% of the 27

account’s investment is consolidated in these two similar life groups, SCE proposes to simplify the 28

service life applied to these assets and use the more conservative 10-year average service life for this 29

account. This depreciation service life results in a $2.4 million annual expense reduction (i.e., based on 30

year-end 2018 plant). 31

92

4. Account 391.5 and 391.6 – Office Equipment 1

These accounts represent an $18.7 million net investment in miscellaneous office 2

equipment such as video projection equipment, public address equipment, duplicating equipment, and so 3

forth. SCE proposes retaining the currently authorized 5-year average service life for this account. 4

5. Account 393 – Stores Equipment 5

Account 393 represents a $6.3 million net investment in equipment used for the 6

receiving, shipping, handling, and storing materials and supplies for warehouses. It includes electric 7

pallet jacks, lifting tables, stretch wrapping machine, transformer trays, lockers, warehouse heaters, 8

cable cutting machines, and so forth. SCE proposes retaining the currently authorized 20-year average 9

service life for this account. 10

6. Account 394 – Tools & Work Equipment 11

Account 394 represents a $37.4 million net investment in tools and equipment for 12

construction, repair, maintenance, general shop, and garage, but not specifically includable in other 13

accounts. SCE proposes retaining the currently authorized 10-year average service life for this account. 14

7. Account 395 – Laboratory Equipment 15

Account 395 represents a $67.8 million net investment in laboratory and field test 16

equipment. The account has a wide variety of equipment. It includes, for example, calibrators, furnaces, 17

gauge calibrators, insulation testers, gas leak detectors, phase meters, power system analyzers, sound 18

meters, metrology standards, and volt meters. The expected average service life of lab and test 19

equipment is impacted by two major retirement factors: technological obsolescence and normal “wear 20

and tear” from usage in both the field and lab environments. SCE proposes retaining the currently 21

authorized 15-year average service life for this account. 22

8. Account 397 – Telecommunication Equipment 23

Account 397 represents SCE’s investment in communication equipment for the 24

company’s system. Contained within this account are the electronic and computer-based equipment 25

(such as transmission equipment, dynamic network multiplexers, data network interconnection system, 26

and radio equipment), as well as communication infrastructure (such as the copper and fiber optic cable, 27

conduit, microwave equipment, and the electrical power generator system). SCE telecommunication 28

engineers have assessed this equipment as having service lives of 5, 7, 10, 15, 25, or 40 years depending 29

93

on the type of equipment.106 In general, state-of-the-art modern and sophisticated equipment has been 1

authorized shorter average service lives while infrastructure (poles, cable, conduit, etc.) has been 2

authorized longer service lives. SCE is proposing to retain the same service lives the Commission 3

authorized in the 2018 GRC. 4

9. Account 398 – Miscellaneous 5

Account 398 represents a $34.4 million net investment in miscellaneous utility equipment 6

that does not fit other plant accounts. Examples can include such diverse items as kitchen and infirmary 7

equipment. SCE proposes to retain the currently authorized service life of 20 years for this account. 8

B. Intangibles 9

SCE has investments in several intangible assets, including hydro relicensing, radio frequencies, 10

long-term franchise fees, capitalized software, and land easements and rights-of-way. As previously 11

discussed, the hydro relicensing costs are amortized over the remaining life of the FERC project license 12

period. SCE proposes to continue amortizing the radio frequency investments over the 40-year service 13

life, and land easements and rights-of-way over the 60-year service life determined in prior rate case 14

proceedings. The other categories are discussed below. 15

1. Miscellaneous Intangibles 16

The year-end 2018 net investment for miscellaneous intangibles is approximately 17

$339,000, which is largely made up of long-term franchise costs. SCE proposes to retain the currently 18

authorized life of 20 years for these costs. 19

2. Capitalized Software 20

Software requires ongoing investment to upgrade and optimize its usefulness. The 21

estimated life of capitalized software reflects the time between its initial deployment and/or upgrade, to 22

the time it is required to be replaced or overhauled because of technology, vendor, or business 23

obsolescence. SCE proposes to continue the four existing average service life categories of five, seven, 24

ten, and 15 years authorized in prior proceedings. Given rapid technological change, the trend has been 25

towards shorter service lives. As of year-end 2018, 82% of SCE’s capitalized software has a five-year 26

amortization and about 17% has a seven-year amortization. The remaining software has ten-year or 27

fifteen-year amortization periods. 28

106 Refer to WP SCE-07 Vol. 03, Book A pp. 197-199 (Telecomm. Engineering Survey).

94

Amortization periods of five- and seven-year lives are not uncommon in the utility 1

industry for capitalized software. Based on benchmarking with other utilities and reviews of industry 2

practice, SCE has found that five years is the most frequently applied amortization for typical capitalized 3

software for utilities. Longer service lives of seven years or more are generally used for the initial 4

implementation of complex backbone systems such as an Enterprise Resource Planning (ERP) system or 5

billing systems. While initial ERP system implementations might be amortized over longer periods, 6

subsequent upgrades are generally amortized over a shorter period equivalent to the amortization period 7

for typical capitalized software. 8

When considering capitalized software lives, there are similarities and dissimilarities with 9

tangible plant assets. Most utility plant assets have identifiable component parts that can be discretely 10

retired and replaced when they are no longer useful. For example, a substation as a whole will provide 11

service for a longer period than the individual units of property required to keep it operating. Similarly, 12

enterprise-wide software has ongoing additions, replacements, and/or deletions of programming code 13

through various enhancement revisions, upgrades, and platform revamps over its lifecycle. These can 14

result from ongoing technological advances, security enhancements, incremental and extensive changes 15

to industry, regulatory and operational requirements, obsolescence, system upgrades, and so forth. 16

The effect of technical advances has become increasingly impactful on software lives. 17

For example, SAP has released multiple version upgrades to its software since SCE’s initial installation 18

in 2008. In addition, there have been implementations and upgrades to numerous SAP add-on software 19

such as PowerPlan and Ariba that have required ongoing revisions to SAP interface programming. An 20

example of emerging technological impacts is cloud computing. The approach of installing on-premises 21

software is being replaced as software providers are moving away from supporting on-site solutions. 22

Moreover, the Financial Accounting Standards Board recently issued accounting guidance regarding 23

cloud computing arrangements that will result in shorter-lived capitalized software costs.107 Beginning 24

in 2020, the associated capitalized costs amounts will need to be expensed over the period of the hosting 25

agreements, which generally is expected to be in the range of three to five years. These kinds of 26

technological disruptors will continue to affect and generally reduce software lives. 27

107 FASB Accounting Standards Update (ASU) 2018-15, Customer’s Accounting for Implementation Costs

Incurred in a Cloud Computing Arrangement That Is a Service Contract. Under this ASU, beginning in 2020, the associated capitalized costs amounts will need to be amortized over the period of the hosting agreements, which generally are expected to be in the range of three to five years.

95

When portions of the software programming code are revised/replaced, it is not practical 1

to identify discrete retirement amounts. Consequently, there is no statistical manner to reasonably 2

evaluate capitalized software service lives. Instead, there is a need to apply judgement in establishing an 3

average amortization period to reasonably reflect the software’s service value. Although the 4

amortization period of a particular software is set at seven years, there is a recognition that that 5

represents an average service life of the programming code, with some portions being replaced/revised 6

earlier than seven years and other portions having value beyond seven years. Taken together, the service 7

life should be reasonable on average, given the expected on-going change to the software. Based on the 8

current technological trends and consistency with industry software amortization lives, SCE proposes to 9

continue applying the currently authorized set of capitalized software lives. 10

3. Easements 11

SCE proposes to retain the authorized amortization period of 60 years for its easements 12

and rights-of-way. 13

Appendix A

2019 Service-life Study

2019 Service–life Study

Appendix A

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CONTENTS

EXECUTIVE SUMMARY SECTION I INTRODUCTION .................................................................................................................. 1

SCOPE OF STUDY .............................................................................................................. 1

STUDY PROCEDURE SECTION II INTRODUCTION .................................................................................................................. 2

SCOPE .............................................................................................................................. 2

DATA COLLECTION ............................................................................................................ 2

LIFE ANALYSIS AND ESTIMATION ........................................................................................ 3

RECOMMENDATIONS AND ANALYSIS SECTION III RECOMMENDATIONS .......................................................................................................... 7

ANALYSIS .......................................................................................................................... 7

TRANSMISSION PLANT

ACCOUNT 352.00 – STRUCTURES AND IMPROVEMENTS .................................................. 8

ACCOUNT 353.00 – STATION EQUIPMENT ..................................................................... 10

ACCOUNT 354.00 – TOWERS AND FIXTURES................................................................. 12

ACCOUNT 355.00 – POLES AND FIXTURES .................................................................... 14

ACCOUNT 356.00 – OVERHEAD CONDUCTORS AND DEVICES ........................................ 16

ACCOUNT 357.00 – UNDERGROUND CONDUIT .............................................................. 18

ACCOUNT 358.00 – UNDERGROUND CONDUCTORS AND DEVICES ................................. 20

ACCOUNT 359.00 – ROADS AND TRAILS ....................................................................... 22

DISTRIBUTION PLANT

ACCOUNT 361.00 – STRUCTURES AND IMPROVEMENTS ................................................ 23

ACCOUNT 362.00 – STATION EQUIPMENT ..................................................................... 25

ACCOUNT 364.00 – POLES AND FIXTURES .................................................................... 27

ACCOUNT 365.00 – OVERHEAD CONDUCTORS AND DEVICES ........................................ 29

ACCOUNT 366.00 – UNDERGROUND CONDUIT .............................................................. 31

ACCOUNT 367.00 – UNDERGROUND CONDUCTORS AND DEVICES ................................. 33

ACCOUNT 368.00 – LINE TRANSFORMERS .................................................................... 35

ACCOUNT 369.00 – SERVICES ..................................................................................... 37

ACCOUNT 370.00 – METERS ....................................................................................... 39

ACCOUNT 373.00 – STREET LIGHTING AND SIGNAL SYSTEMS ....................................... 41

GENERAL PLANT

ACCOUNT 390.00 – STRUCTURES AND IMPROVEMENTS ................................................ 43

August 2019

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EXECUTIVE SUMMARY

INTRODUCTION This report presents a study and recommended service–life statistics for transmis-sion, distribution and general depreciable plant owned and operated by Southern California Edison Company (SCE). Foster Associates was engaged by SCE in January 2019. The study was completed in August 2019.

Foster Associates is a public utility economics consulting firm offering economic research and consulting services on issues and problems arising from governmen-tal regulation of business. Areas of specialization supported by the firm’s Fort Myers office include property life forecasting, technological forecasting, depre-ciation estimation, and valuation of industrial property.

Foster Associates has undertaken numerous depreciation engagements for both public and privately owned business entities including detailed statistical life stud-ies, analyses of required net salvage rates, and the selection of depreciation sys-tems that will most nearly achieve the goals of depreciation accounting under the constraints of either government regulation or competitive market pricing. Foster Associates is widely recognized for industry leadership in the development of de-preciation systems, life analysis techniques and computer software for conducting depreciation and valuation studies.

Service lives currently used by SCE were approved by the California Public Utili-ties Commission (CPUC) in A16–09–001. (D.19–05–020, dated May 16, 2019). With two exception, the approved service lives were derived from a service–life study conducted by Foster Associates on December 31, 2015 plant balances. Findings and recommendations developed in the current study are summarized in Section III of this report.

SCOPE OF STUDY The principal activities undertaken in the course of the current study included:

Collection of plant data;

Reconciliation of data to the official records of the Company; and

Statistical life studies and estimation of projection lives and projec-tion curves.

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STUDY PROCEDURE

INTRODUCTION The purpose of a comprehensive depreciation study for a regulated utility is to an-alyze the mortality characteristics, net salvage rates and the adequacy of deprecia-tion accruals derived from currently approved depreciation rates. The findings from such an investigation are used in the formulation of revised depreciation rates subject to regulatory approvals.

In the case of the current study, Foster Associates was engaged by SCE to only study and recommended service–life statistics that would then be incorporated in depreciation rates developed by the Company.

SCOPE The steps involved in conducting the service–life study can be grouped into three major tasks:

Data Collection;

Life Analysis; and

Life Estimation.

The scope of the 2019 service–life study included a consideration of each of these tasks as described below.

DATA COLLECTION The minimum database required to conduct a statistical life study consists of a history of vintage year additions and unaged activity–year retirements, transfers and adjustments. These data must be appropriately adjusted for transfers, sales and other plant activity that would otherwise bias the measured service life of normal retirements. The age distribution of surviving plant for unaged data can be estimated by distributing plant in service at the beginning of the study year to pri-or vintages in proportion to the theoretical amount surviving from a projection or survivor curve identified in the life study. The statistical methods of life analysis used to examine unaged plant data are known as semi–actuarial techniques.

A far more extensive database is required to apply statistical methods of life anal-ysis known as actuarial techniques. Plant data used in an actuarial life study most often include age distributions of surviving plant at the beginning of a study year and the vintage year, activity year, and dollar amounts associated with normal re-tirements, reimbursed retirements, sales, abnormal retirements, transfers, correc-tions, and extraordinary adjustments over a series of prior activity years. An actu-arial database may include age distributions of surviving plant at the beginning of the earliest activity year, rather than at the beginning of the study year. Plant addi-tions, however, must be included in a database containing an opening age distri-bution to derive aged survivors at the beginning of the study year. All activity year transactions with vintage year identification are coded and stored in a data-base. These data are processed by a computer program and transaction summary

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reports are created in a format reconcilable to official plant records. The availabil-ity of such detailed information is dependent upon an accounting system that sup-ports aged property records. The Continuing Property Record (CPR) system used by SCE provides aged transactions for all plant accounts.

Service life statistics estimated in the 2019 study were derived from plant ac-counting transactions recorded over the period 2002 through 2018. Detailed ac-counting transactions were extracted from the CPR system and assigned transac-tion codes which describe the nature of the accounting activity. Transaction codes for plant additions, for example, were used to distinguish normal additions from acquisitions, purchases, reimbursements and adjustments. Similar transaction codes were used to distinguish normal retirements from sales, reimbursements, abnormal retirements and adjustments. Transaction codes were also assigned to transfers, capital leases, gross salvage, cost of removal and other accounting activ-ity that should be considered in a depreciation study.

The accuracy and completeness of the assembled database was verified by SCE personnel for activity years 2002 through 2018. Age distributions of surviving plant at December 31, 2018 were reconciled to the CPR.

LIFE ANALYSIS AND ESTIMATION Life analysis and life estimation are terms used to describe a two–step procedure for estimating the mortality characteristics of a plant category. The first step (i.e., life analysis) is largely mechanical and primarily concerned with history. Statisti-cal techniques are used in this step to obtain a mathematical description of the forces of retirement acting upon a plant category and an estimate of the projection life of the account. The mathematical expressions used to describe these life char-acteristics are known as survival functions or survivor curves.

It is important to note what is being estimated in a service life study. It is not unit-years of service; it is dollar–years of service. Retirements are not recorded for plant accounting purposes in units such as feet, pounds, segments or any similar physical measurement. Plant records are maintained in dollars and service lives are measured in dollar–years of service. Estimating service lives based on engi-neering studies of how long, on average, units of property might remain in service is not equivalent to estimating dollar–years of service.

Life statistics estimated in the 2019 service–life study are dollar–weighted aver-ages of the unit–years of service derived from the age of aggregated retired prop-erty units. Retirement vintages are assigned by SCE’s property accounting system using approved retirement frequency distributions. The reported dollar amounts of units retired from service are obtained by multiplying units retired by the average per–unit cost of associated vintage additions. This approach eliminates issues re-lated to tracking the original vintages of thousands of property units and provides that the estimated “projection lives” in the 2019 study are based on retirements

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and plant investment reflected in SCE’s plant ledger.

The size of a retirement unit also matters. A company that defines a span of con-ductor between supports to be a retirement unit will measure longer service lives than a company that defines one foot of conductor as a retirement unit. Replace-ment of conductor less than a retirement unit is charged to operating expense and no retirement is recorded for the replaced unit. Larger units result in less frequent recorded retirements, which translate to longer average dollar–years of service.

An added dimension of complexity in introduced when retirements occur at vary-ing ages and attributable to mixed forces of retirement. This creates a non-homogeneous account composed of two subpopulations acted upon by differing forces of retirement. The estimated projection life for such an account measured in dollar–years of service will converge toward the mean of the subpopulation most resistant to the forces of retirement.

The second step (i.e., life estimation) is concerned with predicting the expected remaining life of property units still exposed to forces of retirement. It is a process of blending the results of a life analysis with informed judgment (including expec-tations about the future) to obtain an appropriate projection life and curve descrip-tive of the parent population from which a plant account is viewed as a random sample. The amount of weight given to a life analysis will depend upon the extent to which past retirement experience is considered descriptive of the future.

The analytical methods used in a life analysis are broadly classified as actuarial and semi–actuarial techniques. Actuarial techniques can be applied to plant ac-counting records that reveal the age of a plant asset at the time of its retirement from service. Stated differently, each property unit must be identifiable by date of installation and age at retirement. Semi–actuarial techniques can be used to derive service life and dispersion estimates when age identification of retirements is not maintained or readily available. Age identification of retirements over the period 2002–2018 was available for all plant accounts included in the 2019 study.

An actuarial life analysis program designed and developed by Foster Associates was used in this study. The first step in an actuarial analysis involves a systematic treatment of the available data for the purpose of constructing an observed life ta-ble. A complete life table contains the life history of a group of property units in-stalled during the same accounting period and various probability relationships derived from the data. A life table is arranged by age–intervals (usually defined as one year) and shows the number of units (or dollars) entering and leaving each age–interval and probability relationships associated with this activity. A life table minimally shows the age of each survivor and the age of each retirement from a group of units installed in a given accounting year.

A life table can be constructed in any one of at least five methods. The annual–rate or retirement–rate method was used in this study. The mechanics of the annu-

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al–rate method require the calculation of a series of ratios obtained by dividing the number of units (or dollars) surviving at the beginning of an age interval into the number of units (or dollars) retired during the same interval. This so–called “retirement ratio” (or set of ratios) is an estimator of the hazard rate or conditional probability of retirement during an age interval. The cumulative proportion sur-viving is obtained by multiplying the retirement ratio for each age interval by the proportion of the original group surviving at the beginning of that age interval and subtracting this product from the proportion surviving at the beginning of the same interval. The annual–rate method is applied to multiple groups or vintages by combining the retirements and/or survivors of like ages for each vintage in-cluded in the analysis.

The second step in an actuarial analysis involves graduating or smoothing the ob-served life table and fitting the smoothed series to a family of survival functions. The functions used in this study are the Iowa–type curves which are mathemati-cally described by the Pearson frequency curve family. Observed life tables were smoothed by a weighted least–squares procedure in which first, second and third degree orthogonal polynomials were fitted to the observed retirement ratios. The resulting function was expressed as a survivorship function and numerically inte-grated to obtain an estimate of the projection life for each plant account. The smoothed survivorship function was then fitted by a weighted least–squares pro-cedure to the Iowa–curve family to obtain a mathematical description or classifi-cation of the dispersion characteristics of the data.

The set of computer programs used in this analysis provides multiple rolling–band, shrinking–band and progressive–band analyses of an account. Observation bands are defined in terms of a "retirement era" that restricts the analysis to the re-tirement activity of all vintages represented by survivors at the beginning of a se-lected era. In a rolling–band analysis, a year of retirement experience is added to each successive retirement band and the earliest year from the preceding band is dropped. A shrinking–band analysis begins with the total retirement experience available and the earliest year from the preceding band is dropped for each suc-cessive band. A progressive–band analysis adds a year of retirement activity to a previous band without dropping earlier years from the analysis. Rolling, shrinking and progressive band analyses are used to detect the emergence of trends in the behavior of the dispersion and projection life.

Options available in the Foster Associates actuarial life analysis program include: the width and location of both placement and observation bands; the interval of years included in a selected band analysis; the estimator of the hazard rate (actuar-ial, conditional proportion retired, or maximum likelihood); the elements to in-clude on the diagonal of a weight matrix (exposures, inverse of age, inverse of variance, or unweighted); and the age at which an observed life table is truncated. The program also provides tabular and graphics output as an aid in the analysis.

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While actuarial and semi–actuarial statistical methods are well suited to an analy-sis of plant categories containing a large number of homogeneous units (e.g., poles and conductors), the concept of retirement dispersion is recognized differ-ently for plant categories composed of major items of plant that will most likely be retired as a single unit. Plant retirements from an integrated system prior to the retirement of the entire facility are viewed as interim retirements that will be re-placed in order to maintain the integrity of the system. Additionally, plant facili-ties may be added to the existing system (i.e., interim additions) in order to ex-pand or enhance its productive capacity without extending the service life of the existing system. A proper depreciation rate can be developed for an integrated system using a life–span method. All depreciable plant accounts classified in transmission, distribution and general were studied as full mortality categories in the 2018 study.

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RECOMMENDATIONS AND ANALYSIS

RECOMMENDATIONS Table 1 below provides a summary of current and recommended projection lives and projection curves estimated for SCE in the 2019 study.

ANALYSIS A description of each plant account examined in the study and factors considered in the estimation of recommended service–life parameters is contained in the fol-lowing pages of this report.

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Current RecommendedAccount Description P-Life Dispersion P-Life Dispersion

A B C D E

Transmission Plant 352.00 Structures and Improvements 55.00 L1 55.00 L1353.00 Station Equipment 45.00 R0.5 45.00 L0.5354.00 Towers and Fixtures 65.00 R5 65.00 R5355.00 Poles and Fixtures 65.00 SC 65.00 SC356.00 Overhead Conductors and Devices 61.00 R3 61.00 R3357.00 Underground Conduit 55.00 R3 55.00 R3358.00 Underground Conductors and Devices 45.00 S1 45.00 S1359.00 Roads and Trails 60.00 R5 60.00 R5

Distribution Plant 361.00 Structures and Improvements 50.00 L0.5 55.00 L0.5362.00 Station Equipment 65.00 L0.5 65.00 S-.5364.00 Poles, Towers and Fixtures 55.00 R1 55.00 R1365.00 Overhead Conductors and Devices 55.00 R0.5 55.00 R0.5366.00 Underground Conduit 59.00 R3 59.00 R3367.00 Underground Conductors and Devices 43.00 R1.5 47.00 L1368.00 Line Transformers 33.00 S1.5 33.00 S1.5369.00 Services 55.00 R1.5 55.00 R1.5370.00 Meters 20.00 R3 20.00 R3373.00 Street Lighting and Signal Systems 48.00 L1 50.00 L0.5

General Plant390.00 Structures and Improvements 45.00 R0.5 50.00 SC

Table 1. Service-Life Statistics

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TRANSMISSION PLANT ACCOUNT: 352.00 – STRUCTURES AND IMPROVEMENTS

DESCRIPTION This account includes the cost in structures and improvements used in connection with transmission operations. Account statistics and current and proposed parame-ters are shown in Table 1 below.

LIFE ANALYSIS Major forces of retirement for this account include system upgrades, severe storms and earthquakes, traffic and fire accidents, rodent damage, automation, re-visions in policy, code, and criteria, and wear and tear related to aging.

Statistical service life indications for the full account are derived from unlikely recurring retirement activity. Retirements of $22.4M reported in 2009 (58.5 per-cent of total adjusted retirements over the 17 year study period) were primarily related to the retirement of equipment at the Sylmar substation. Average service life indications from the statistical service life analysis range from the low 30s to the mid 50s for bands with lower censoring and conformance indexes. The ma-jority of second and third degree polynomial indications are considered less reli-able than first degree polynomial indications. Graduated hazard rates in these in-stances are unrealistically declining and many were zeroed to remove negative hazard rates implied by the fitted polynomials. The composition of major catego-ries (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a full-band statistical analysis of each subpopulation are shown in Table 2 below.

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Current Proposed

PLife-Curve 55-L1 55-L1Derived Additions $1,022,020,288Plant Retirements $38,269,215Percent Retired 3.7%Plant Balance $983,751,073

Table 1. Account Parameters and Statistics

Investment Full Band Censoring

Category Amount ($) % PLife-Curve (%)

Foundations & Structures 246,035,960 25 76-L0.5 36.6 MEER Building 201,960,633 21 120-S-0.5 72.0 Water Supply Systems 132,162,839 13 105-S0.5 60.0 Monitoring Devices 99,790,965 10 196-S6 98.9 Power & Lighting Systems 58,939,389 6 83-R0.5 40.8 Common & Other 31,635,462 3 38-L0.5 7.8 HVAC 18,245,454 2 39-L0 23.6Non-unitized 194,980,370 20

Total 983,751,072 100 105

Table 2. Major Structural Components

A-10

The variability of subpopulation service lives is an indication of a nonhomogene-ous plant account with mixed forces of retirement acting on the subpopulations. Heterogeneity coupled with high degrees of censoring reduces the level of confi-dence that can be placed in service–life indications obtained from either a sub-population or total account analysis.

LIFE ESTIMATION Based mainly on first degree statistical service life indications and discounting origin modal dispersions in which chance is a more pervasive force of retire-ment, a retention of the currently approved 55 L1 projection life curve is rec-ommended for this account. This recommendation reflects a lack of evidence for adjusting the service life estimates given the single retirement underlying a signif-icant percentage of the retirement history. Foster Associates was informed that Company engineers and operations personnel do not anticipate policy or proce-dural changes or technological advances that would introduce significantly differ-ent forces of retirement from those observed in the past.

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TRANSMISSION PLANT ACCOUNT: 353.00 – STATION EQUIPMENT

DESCRIPTION

This account includes the cost in transforming, conversion, and switching equip-ment used for the purpose of changing the characteristics of electricity in connec-tion with its transmission or for controlling transmission circuits. Account statis-tics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS Retirement activity in transmission station equipment is largely associated with age related failures, obsolescence and growing or shifting loads that necessitate rebuilding to larger capacities. Although obsolescence can occur at any age, it is more likely to affect older equipment. Company engineers report that thermal, mechanical, and electrical integrity issues intensify with age, typically beginning around age 30 years when insulation degradation, increased in service failures, and increased maintenance arises. Retirements occur when increased costs and decreased utilization rates dictate is it no longer economic to repair such equip-ment. Decreased spare parts availability as equipment ages also plays a major role in age related retirements.

For more than ten years, the Company has utilized a Condition Based Mainte-nance (CBM) strategy to manage all transformers and circuit breakers by routine-ly conducting off line diagnostics, visual inspections, and functional checks. These analysis components are combined with other key data such as age, design, moisture levels, loading, and fault exposure to develop a health index ranking that is maintained throughout the life of these assets and used in the determination of when to repair or retire.

Service life indications from the statistical analysis of the full account range from the low 30s to the low 50s for bands with lower censoring and conformance in-dexes. The majority of second and third degree polynomial indications are con-sidered less reliable than first degree polynomial indications. Graduated hazard rates in these instances are unrealistically declining and were zeroed to remove negative hazard rates implied by the fitted polynomials.

The composition of major categories (or subpopulations) of plant classified in this

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Current Proposed

PLife-Curve 40-L0.5 45-L0.5Derived Additions $6,707,505,587Plant Retirements $635,368,420Percent Retired 9.5%Plant Balance $6,072,137,167


A-12

account at December 31, 2018 and the service life indications obtained from a full-band statistical analysis of each category are shown in Table 2 below.

The subpopulation analysis of the full historical experience exhibits a range of ac-counting service lives between 34 and 74 years with a direct dollar weighted av-erage of 50 years and a preponderance of lower left modal dispersions. Ser-vice life indications derived from a statistical analysis of the combined subpopu-lations are well within a zone of reasonableness when compared to the subpopula-tion indications. The analysis of these subpopulations does not indicate forces of retirement that would significantly bias the observed indications for a combined, nonhomogeneous plant category.

LIFE ESTIMATION Based on indications from both the full account and subpopulation statistical ser-vice life analyses, a 45 L0.5 projection life curve is recommended for this ac-count. This recommendation is derived from account total service lives indicated for trials with lower censoring, conformance indexes, and hazard functions un-compromised by declining or negative hazard rates. Foster Associates was in-formed that Company engineers do not anticipate that future forces of retirement will be significantly different from those observed in the past for this plant cate-gory.

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Full Band Censoring


Transformers 1,091,583,314 18 50-L0.5 14.6 Common & Other 782,463,939 13 40-L0 17.8 Circuit Breakers 771,331,833 13 34-L1 1.6 Switches and Switch Gear 593,841,483 10 39-L0 10.2 Monitoring Devices 590,905,070 10 54-SC 22.3 Bus Support Structures 522,356,267 9 78-L0 32.5 Capacitors 381,827,523 6 59-S-.5 28.9 Power Control Cable 362,014,697 6 56-SC 34.9 Foundations 171,341,678 3 74-L0.5 37.6 Non-unitized 804,471,363 13

Total 6,072,137,167 100 50


Investment

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TRANSMISSION PLANT ACCOUNT: 354.00 – TOWERS AND FIXTURES

DESCRIPTION This account includes the cost installed of towers and appurtenant fixtures used for supporting overhead transmission conductors. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS Forces of retirement acting upon transmission towers and fixtures include line up-grades, corrosion, relocation (for lower voltage structures), and failures due to wind storms, ice, or floods. Most of these forces tend to increase with age. Alt-hough storm damage can generally be expected to impact retirements at any age, in combination with deterioration, the probability of failure is cumulative. SCE conducts annual inspections on all transmission towers and performs subsequent maintenance identified from those inspections.

The statistical service life indications for the full account are derived from mini-mal and irregular retirement activity. Retirements recorded in this account amount to only $7.4M from an average plant balance exceeding $1.4B over the study pe-riod and about three percent of derived additions. Statistical service life indica-tions derived from this minimal experience are highly censored, unrealistically long (exceeding 150 years in many instances), and contrary to Company service life expectations.

The investment in the single major category of plant classified in this account at December 31, 2018 and the service life indication obtained for it from a full band statistical analysis are shown in Table 2 below.

The account could not be reasonably sub divided further apart from non unitized

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Current Proposed

PLife-Curve 65-R5 65-R5Derived Additions $2,363,142,679Plant Retirements $7,363,678Percent Retired 0.3%Plant Balance $2,355,779,001


Full Band Censoring


Towers 1,935,696,473 82 139-S1.5 75.1 Non-unitized 420,082,528 18

Total 2,355,779,001 100 139


Investment

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items constituting 18 percent of the plant investment.

LIFE ESTIMATION The minimal retirement activity and resulting unreliable service life indications from both the full account and subpopulation statistical analyses do not provide a strong foundation for service life estimation. Foster Associates, therefore, de-ferred to SCE in recommending retention of the currently approved 65 R5 pro-jection life curve. Factors evaluated by SCE beyond the service life analyses in-clude operational, accounting and ratemaking considerations.

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TRANSMISSION PLANT ACCOUNT: 355.00 – POLES AND FIXTURES

DESCRIPTION

This account includes the installed cost of transmission line poles, wood, steel, concrete, or other material, together with appurtenant fixtures used for supporting overhead transmission conductors. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

The majority of wood poles in the Company's system are full–length and "through–boring" treated to protect against decay and insect attack. Wood poles may also be treated with a steel stub or a fiberglass wrap to provide additional support. In addition to pole treatment, the Company conducts a 10–year inspec-tion cycle to address safety and reliability. Tree trimming and vegetation man-agement are also a significant component of reliability measures undertaken by the Company.

Major forces of retirement acting upon transmission wood poles include external, internal, top rot, and split top deterioration. Additional forces include vehicles, wind, storm, fire, and bird (mainly woodpecker) damage. Response to these forc-es partly depends on the specific locale of the pole given the Company's wide ge-ographical area encompassing mainly desert but also agricultural, rural, and urban communities.

Indications from the statistical service life analysis for this account range from the low 50s to the mid 60s for bands with lower censoring and conformance indexes. The majority of third degree polynomial indications are considered less reliable than first degree or second degree polynomial indications. Graduated hazard rates in these instances are unrealistically declining and were zeroed to remove negative hazard rates implied by the fitted polynomials. The shorter average ser-vice lives observed in the recent past are attributable to a significant increase in retirement activity in recent years. Retirements in the most recent five years, for example, constituted more than 56% percent of all adjusted retirements in the 17 year study period.


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account at December 31, 2018 and the service life indications obtained from a full–band statistical analysis of each category are shown in Table 2 below.

The subpopulation analysis indicates service lives ranging between 46 and 78 years with an average of 65 years. It is the opinion of Foster Associates that ser-vice–life indications derived from a statistical analysis of the combined subpopu-lations are well within a zone of reasonableness when compared to the subpopula-tion indications. The analysis of subpopulations does not indicate forces of re-tirement that would significantly bias the observed indications for a combined, non–homogeneous plant category.

LIFE ESTIMATION As noted above, more than 60 percent of the total retirements recorded over the 17 year study period occurred during the most recent five years. About 45 per-cent occurred over the most recent three years. SCE reported that most of the in-crease in retirement activity is associated with a retirement program started in 2014 to address pole overload due to increased conductor sizes. Foster Associates was also informed that a number of retirements during that period was due to a faulty software algorithm that has since been corrected. Although the full account and subpopulation statistical service life analysis suggests a shorter projection life, Foster Associates deferred to the Company in recommending retention of the currently approved 65 SC projection service–life parameters pending further evi-dence of a trend in future studies.

.

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Light Duty Steel & Concrete 651,887,350 43 78-L0.5 57.2 Wood, Fiberglass, & Composite 604,178,223 40 52-SC 58.0 Retaining Walls & Other 4,436,990 0 46-S4 35.0 Non-unitized 239,126,419 16

Total 1,499,628,982 100 65


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TRANSMISSION PLANT ACCOUNT: 356.00 – OVERHEAD CONDUCTORS AND DEVICES

DESCRIPTION

This account includes the installed cost of overhead conductors and devices used for transmission purposes. The investment comprises mostly bare copper between 0.419 and 0.522 inches and ACSR cable between 0.563 and 1.762 inches. Ac-count statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

Forces of retirement acting upon transmission conductors include deterioration re-sulting from atmospheric corrosion, fatigue failure due to conductor vibration, storm damage, failure of splices or dead ends, relocation (e.g., highway widen-ing, dam site construction, etc.), circuit upgrades, system reconfiguration and elimination of idle facilities (e.g., closure of generation facilities or loss of large customers). Rule 20, the State's mandate for implementation of conversion to un-derground facilities, also contributes to the forces of retirement in this account. The conditional probability of retirement of retirement resulting from these forces tends to increase with age. The Company's response to minimize the impact of these forces over the life of the equipment includes regular maintenance and an-nual inspection of all transmission overhead conductor, splices and connectors and subsequent maintenance identified from such inspections.

The statistical service life analysis for this account indicates average service lives exceeding 85 years. The analysis, however, is based on $18M of retirement activi-ty from derived additions exceeding $1.6B. Retirement activity of 1.9 percent of derived additions is not considered sufficient to provide a reliable basis for service life estimation.

The composition of major categories (or subpopulations) of plant classified in this account at December 31, 2015 is shown in Table 2. More than 40 percent of the classified investment is conductor larger than 1500 MCM. Service life indications obtained from a full–band statistical analysis of the major categories are shown in Table 2 below.

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The subpopulation analysis of the full historical experience evidences a range of average service lives between 39 and 132 years with a dollar–weighted average of 113 years. With the exception of Switches which constitute only three percent of the investment, these indications are compromised by high censoring and minimal retirement activity comparable to observations in the full account.

LIFE ESTIMATION With consideration given to the minimal retirement experience in this account and the resulting extremes in service life indications, Foster Associates deferred to the Company in recommending retention of the currently approved 61–R3 projection service–life parameters.

.

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Full Band Censoring


Overhead Conductor 1,158,740,091 70 114-R3 93.4 Ground Wire & Other 150,580,564 9 132-R0.5 98.0 Switches 43,135,048 3 34-R1 0.1 Non-Unitized 300,622,575 18

Total 1,653,078,278 100 113


Investment

A-19

TRANSMISSION PLANT ACCOUNT: 357.00 – UNDERGROUND CONDUIT

DESCRIPTION This account includes the installed cost of underground conduit and tunnels used for housing transmission cables or wires. Underground conduit and substructures comprise mainly concrete components and PVC pipe which are inspected thor-oughly prior to installation to ensure integrity and safety. Underground conduit, manholes and vaults are necessary when overhead electrical lines are converted to underground. Reasons for underground conversion include third party requests, overhead congestion, road crossings, local aesthetics, environmental concerns and zoning requirements. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS Rebuild and digging are the major forces of retirement expected to affect this ac-count. Conduit failures are generally the result of mechanical damage caused by excavating or drilling crews inadvertently digging into or drilling through the duct. Other forces of retirement include deterioration due to wear, soil loading, corrosive or hot soils, extreme and weather changes, relocations, and idle facili-ties.

The statistical service life analysis for the full account is based on highly cen-sored trials (87 percent) with life indications ranging between 88 and 146 years. Only $400,136 or 0.1% of derived additions has been retired from the account; a level not considered sufficient to provide a reliable basis for service life estima-tion. Another limitation to the statistical service life analysis is the relatively young investment which was only six years relative to the much longer average service life expected from the components of this account.

The composition of major categories (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a full band statistical analysis of each category are shown in Table 2 below.

PAGE 18

A-20

Subpopulation service life indications are similarly derived from highly censored trials providing little insight into future live expectancies. The large composition of non unitized investment is attributable to plant additions within the last three years.

LIFE ESTIMATION Neither the full account nor the subpopulation analysis provides sufficient evi-dence to support adjusting the currently approved 55–R3 projection life and curve. Current parameters are, therefore, recommended to be retained for this ac-count.

PAGE 19

Full Band Censoring


Conduit 45,023,926 16 167-R2 87.0 Manholes, Vaults & Other 30,053,012 11 78-S1.5 41.3 Trenches 3,200,350 1 N/ANon-unitized 194,787,718 71 N/A

Total 273,065,006 100 131


Investment

A-21

TRANSMISSION PLANT ACCOUNT: 358.00 – UNDERGROUND CONDUCTORS AND DEVICES

DESCRIPTION

This account includes the installed cost of underground conductors and devices used for transmission purposes. Account statistics and current and proposed pa-rameters are shown in Table 1 below.

LIFE ANALYSIS

Deterioration, failure, relocations, upgrades and accidental dig ins are the major forces of retirement acting upon underground conductor and related devices. The Company conducts regular maintenance and inspection of all transmission under-ground systems including cable and performs subsequent maintenance when deemed necessary.

The statistical life analysis conducted for this account indicates average service lives between the mid 30s and mid 40s for trials with lower censoring, conform-ance indexes, and non negative retirement ratios. The majority of first and third degree polynomial indications are considered less reliable than sec-ond degree indications because graduated hazard rates in these instances are un-realistically declining and were zeroed to remove negative hazard rates implied by the fitted polynomials.


PAGE 20



Conductor 239,799,288 60 45-S1.5 43.7 Lightn. Arrest. & Potheads 63,990,992 16 26-S2 3.0 Cathodic Protect. & Other 16,115,938 4 145-R1 85.7 Non-unitized 78,437,411 20

Total 398,343,629 100 46


A-22

An analysis of the subpopulations indicates a range of service lives between 26 and 145 years with lower modal dispersions and an average of 46 years. Ser-vice life indications derived from a statistical analysis of the combined subpopu-lations are well within a zone of reasonableness when compared to the subpopula-tion indications, with the exception of cathodic protection and other devices con-stituting four percent of the plant investment. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed indica-tions for a combined, nonhomogeneous plant category.

LIFE ESTIMATION Based on these observations and considerations, a recommendation to retain the currently prescribed 45 S1 projection life curve is considered reasonable for this account. Foster Associates was informed that Company engineers do not antici-pate future forces of retirement to be significantly different from those observed in the past for this plant category.

PAGE 21

A-23

TRANSMISSION PLANT ACCOUNT: 359.00 – ROADS AND TRAILS

DESCRIPTION

This account includes the cost of roads, trails, and bridges used primarily as transmission facilities. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

The statistical service life analysis for this account is based on minimal retirement activity of $155,302, or 0.1 percent of derived additions from an average plant balance exceeding $109M over the study period. Retirements were reported in on-ly 4 years during that period. The service life analysis is expectedly highly cen-sored at more than 76.8 percent with resulting life indications ranging no shorter than 80 years.

Except for non unitized, the investment in the single major category of plant classified in this account at December 31, 2018 and the service life indication ob-tained for it from a full band statistical analysis are shown in Table 2 below. The account could not be reasonably sub divided further apart from the non unitized items constituting 19 percent of the plant investment.

LIFE ESTIMATION Statistical service life indications for this account are considered insufficient to warrant an adjustment to the currently approved 60–R5 projection life–curve.

PAGE 22

Current Proposed

PLife-Curve 60-R5 60-R5Derived Additions $195,652,360Plant Retirements $155,302Percent Retired 0.1%Plant Balance $195,497,058




Roads and Trails 157,481,455 81 110-S3 95.5 Non-unitized 38,015,602 19

Total 195,497,057 100 110

A-24

DISTRIBUTION PLANT ACCOUNT: 361.00 – STRUCTURES AND IMPROVEMENTS

DESCRIPTION

This account includes the cost in place of structures and improvements used in connection with distribution operations. The account comprises mainly control houses and related structures at distributions substations. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

Major forces of retirement for this account include system upgrades, severe storms and earthquakes, traffic and fire accidents, rodent damage, automation, re-visions in policy, code, and criteria, and wear and tear related to aging.

Statistical service life indications for this account range from the low–40s to low–60s for bands with lower censoring and conformance indexes. The majority of second and third–degree polynomial indications are considered less reliable than first–degree polynomial indications. Graduated hazard rates in these instances are unrealistically declining and were be zeroed to remove negative hazard rates im-plied by the fitted polynomials.

The composition of major categories (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a full–band statistical analysis of each category are shown in Table 2 below.

PAGE 23

Current Proposed

PLife-Curve 50-L0.5 55-L0.5Derived Additions $766,340,124Plant Retirements $69,837,862Percent Retired 9.1%Plant Balance $696,502,262




Common & Other 161,772,713 23 62-O2 32.6 Foundations & Other Strct. 156,634,609 22 36-S2 74.5 MEER Building 149,417,330 21 42-L1 71.6 Water Supply Systems 65,494,336 9 51-S1 83.7 Power & Lighting Systems 58,804,270 8 36-S2 77.6 HVAC 40,299,493 6 36-S1 68.1 Monitoring Devices 24,355,501 3 49-S1.5 90.8Non-unitized 39,724,009 6

Total 696,502,261 100 46

A-25

An analysis of the subpopulations indicates average service lives ranging between 36 and 62 years, various dispersions, and a dollar–weighted mean of 46 years.

LIFE ESTIMATION Based on these observations and dismissing origin–modal dispersions in which chance is a more pervasive force of retirement, a 55–L0.5 projection life–curve is recommended for this account.

Service–life indications derived from a statistical analysis of the combined sub-populations are well within a zone of reasonableness when compared to the sub-population indications. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed indications for a combined, nonhomogeneous plant category. Company operations personnel do not expect policy or procedural changes or technological advances that would introduce sig-nificantly different forces of retirement from those observed in the past.

PAGE 24

A-26

DISTRIBUTION PLANT ACCOUNT: 362.00 – STATION EQUIPMENT

DESCRIPTION

This account includes the installed cost of station equipment, including trans-former banks, used for the purpose of changing the characteristics of electricity in connection with its distribution. Account statistics and current and proposed pa-rameters are shown in Table 1 below.

LIFE ANALYSIS

The statistical service life analysis for this account indicates average service lives within a narrow range between the mid–50s and mid–60s for bands with lower censoring and conformance indexes.


An analysis of the subpopulations indicates average service lives between 37 and 72 years with lower modal dispersions and a dollar–weighted mean of 57 years.

Service–life indications derived from a statistical analysis of the combined sub-populations are well within a zone of reasonableness when compared to the sub-population indications. The analysis of subpopulations does not indicate forces of

PAGE 25

Current Proposed

PLife-Curve 65-L0.5 65-S-.5Derived Additions $2,922,005,259Plant Retirements $194,185,857Percent Retired 6.6%Plant Balance $2,727,819,402


Full Band Censoring


Common and Other 620,379,003 23 67-L0.5 27.2 Transformers 440,054,678 16 57-L1 79.7 Circuit Breakers 366,490,744 13 53-L1 78.1 Monitoring Devices 345,290,666 13 46-R1.5 77.7 Bus Support Structures 212,803,599 8 72-L0.5 85.3 Power Control Cable 169,521,056 6 37-L1 56.5 Switches 123,013,239 5 51-L0.5 75.8 Non-unitized 450,266,417

Total 2,727,819,402 100 57


Investment

A-27

retirement that would significantly bias the observed indications for a combined, nonhomogeneous plant category.

LIFE ESTIMATION Based on these observations and considerations, retaining a 65–L0.5 projection life–curve is recommended for this account. This recommendation is within the range of both full account and subpopulation service life indications. Foster Asso-ciates was informed that Company engineers do not anticipate that future forces of retirement will be significantly different from those observed in the past for this plant category.

Although not equivalent to dollar–years of service, SCE engineers estimate a mean time to wear–out of about 60 years for B–Bank (115 or 66 kV) transform-ers. At the end of 2018, the Company had 163 A Bank and 2,267 B Bank trans-formers classified in service. Company engineers also estimate that the mean time to wear out is about 48 years for circuit breakers. The average age of transform-ers measured in unit years is about 26 years whereas the average age measured in dollar years is about 10 years. Similarly, the average age of circuit breakers measured in unit years is about 32 years whereas the average age measured in dollar years is about 10 years.

PAGE 26

A-28

DISTRIBUTION PLANT ACCOUNT: 364.00 – POLES, TOWERS AND FIXTURES

DESCRIPTION This account includes the installed cost of poles, towers, and related fixtures used for supporting overhead distribution conductors and service wires. Account sta-tistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS The majority of wood poles in the Company's system are full–length and "through–boring" treated to protect against decay and insect attack. Wood poles may also be treated with a steel stub or a fiberglass wrap to provide additional support. In addition to pole treatment, the Company conducts a 10–year inspec-tion cycle to address safety and reliability. Tree trimming and vegetation man-agement are also a significant component of reliability measures undertaken by the Company.

As with transmission wood poles, major forces of retirement acting upon distribu-tion wood poles include external, internal, top rot, split top deterioration and pole loading. Additional forces include vehicles, wind, storm, fire, and bird (mainly woodpecker) damage. Response to these forces partly depends on the specific lo-cale of the pole given the Company's wide geographical area encompassing main-ly desert but also agricultural, rural, and urban communities.

The statistical service life analysis for this account indicates consistent indications with accounting service lives around the mid–50s for bands with lower censoring and conformance indexes.

Except for non unitized plant, the investment in the single major category of plant classified in this account at December 31, 2018 and the service life indica-tion obtained for it from a full band statistical analysis are shown in Table 2 be-low.

PAGE 27

Current Proposed



A-29

An analysis of the single subpopulation of poles indicates a 50–R1 projection life–curve at 45.9 percent censoring. This indication is comparable to indications obtained for the full band statistical service life analysis. The account could not be reasonably sub divided apart from the non unitized items constituting six per-cent of the plant investment.

LIFE ESTIMATION About 54 percent of the total retirements recorded over the 17 year study period occurred during the most recent five years. About 40 percent occurred over the most recent three years. SCE reported that most of the increase in retirement ac-tivity to a retirement program started in 2014 to address pole overload due to in-creased conductor sizes. Foster Associates was also informed that a number of re-tirements during that period was due to a faulty software algorithm that has since been rectified. Although the full account and subpopulation statistical service life analysis suggests a shorter projection life, Foster Associates deferred to the Com-pany in recommending retention of the currently approved 55 R1 projection ser-vice–life parameters pending further evidence of a trend in future studies.

PAGE 28

Full Band Censoring


Poles 2,951,743,122 94 50-R1 35.9 Non-unitized 195,954,207 6

Total 3,147,697,329 100 50


Investment

A-30

DISTRIBUTION PLANT ACCOUNT: 365.00 – OVERHEAD CONDUCTORS AND DEVICES

DESCRIPTION This account includes the cost installed of overhead conductors and devices used for distribution purposes. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS Rebuild programs and relocation to address changes in capacity and rights of way, deterioration resulting from atmospheric corrosion, fatigue failure due to conduc-tor vibration, storm damage, and splice failure are the major forces of retirement acting upon this plant category. Lightning strikes also nick the conductor, reduc-ing its capacity and eventually causing burndown. Although repair at the damaged point is possible with splicing and reconnecting, it is costly. It is common, there-fore, to remove and replace a longer section of the damaged conductor, which is usually the span between supports. Proactive replacement with covered conductor in high fire risk areas is also undertaken by the Company. Overhead to under-ground facilities conversion, such as that governed by CPUC Rule 20, continues to be a force of retirement acting upon plant classified in this account.

The Company introduced an ongoing Overhead Conductor Program (OCP) in 2015 to proactively address the use of unfused #6 copper and #4 aluminum wire in distribution primary circuits which was introducing short circuits du-ty/conductor damage. More than 12.5 percent of the total retirements recorded over the period 2015–2018 were attributable to this program.

The statistical service life analysis for this account is based on moderately cen-sored trials. A number of first and second degree polynomials indications derived from graduated hazard rates that are unrealistically declining or zeroed were dis-counted as were origin modal dispersions in which chance is a more pervasive force of retirement. More consistent indications for bands with lower censoring and conformance indexes indicated accounting service lives between 42 and 52 years and lower modal dispersions.

The composition of major categories (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a

PAGE 29

Current Proposed

PLife-Curve 55-R0.5 55-R0.5Derived Additions $2,047,272,510Plant Retirements $204,416,186Percent Retired 10.0%Plant Balance $1,842,856,324


A-31

full band statistical analysis of each category are shown in Table 2 below.

An analysis of the subpopulations indicates service lives between 20 and 64 years with lower modal dispersions and a dollar–weighted average of 53 years. Service–life indications derived from a statistical analysis of the combined subpopulations are considered to be within a zone of reasonableness when compared to the sub-population indications. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed indications for a combined, non–homogeneous plant category.

LIFE ESTIMATION Based on these observations and considerations, Foster Associates recommends retaining the currently approved 55–R0.5 projection life–curve for this account.

Foster Associates was informed that Company engineers do not anticipate that fu-ture forces of retirement will be significantly different from those observed in the past for this plant category.

PAGE 30

Full Band Censoring


Conductor 1,174,809,822 64 64-R1.5 60.9 Switches 433,837,475 24 34-S-.5 6.9 Devices & Other 129,392,452 7 20-O3 (2.5) Non-unitized 104,816,574 6

Total 1,842,856,323 100 53


Investment

A-32

DISTRIBUTION PLANT ACCOUNT: 366.00 – UNDERGROUND CONDUIT

DESCRIPTION This account includes the installed cost of underground conduit and tunnels used for housing distribution cables or wires. Underground conduit and substructures comprise mainly concrete components and PVC pipe which are inspected thor-oughly prior to installation to enhance cable and duct service lives and ensure in-tegrity and safety. Underground conduit, manholes, and vaults are necessary when overhead electrical lines are converted to underground. Reasons for underground conversion include third party request, overhead congestion, road crossings, local aesthetics, environmental concerns, and zoning requirements. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

Conduit failures are generally the result of mechanical damage caused by excavat-ing or drilling crews inadvertently digging into or drilling through the duct. Other forces of retirement include deterioration due to wear, soil loading, corrosive or hot soils, extreme and weather changes, relocations, and idle facilities.


PAGE 31

Current Proposed



Full Band Censoring


Conduit 1,054,716,815 44 124-R3 95.1 Pull & Slab Boxes 546,115,998 23 44-R3 9.8 Vaults 506,536,527 21 87-R3 86.0 Risers & Other 177,361,105 7 47-L1.5 26.4 Trenches 19,571,547 1 163-R3 100.0 Non-unitized 86,368,623 4 49-L1 45.0

Total 2,390,670,615 100 90


Investment

A-33

The statistical service life analysis for this account is based on highly censored trials with indicated service lives exceeding 100 years. Additionally, only minimal retirement activity of $60M (or 2.4 percent) from derived additions exceeding $2.4B has been reported. This retirement activity is considered insufficient to provide a reliable basis for service life estimation.

LIFE ESTIMATION With consideration given to the minimal retirements recorded in this account and unreliable service–life indications, Foster Associates deferred to the Company in recommending retention of the currently approved 59–R3 projection service–life parameters.

PAGE 32

A-34

DISTRIBUTION PLANT ACCOUNT: 367.00 – UNDERGROUND CONDUCTORS AND DEVICES

DESCRIPTION This account includes the installed cost of underground conductors and devices used for distribution purposes. Reasons for underground conversion include third party request, Rule 20A conversion and other zoning requirements, over-head congestion, local aesthetics, and environmental concerns. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS The majority of SCE’s underground cable population is XLPE, which generally fails due to deterioration and eventual breakdown of insulation. Other forces of retirement include relocations, upgrades, and accidental dig ins. Deterioration has a cumulative effect and generally will not cause early retirements. Failures can occur at any time, but will generally increase with age and level of deteriora-tion. Relocations and upgrades generally will not occur at an early age. Accidental dig ins will generally occur independent of age. The Company continues to miti-gate these forces of retirement through a number of programs such the "Cable Life Extension" program introduced in 2012 to focus on radial cables installed in non–rigid conduit (CIC). CIC constitutes approximately a fourth of the Compa-ny's total primary cable inventory. The program provided life extension benefits by identifying and addressing cable segments at greatest risk of imminent failure. Cables at risk can be treated with "Cable Injection" which involves physical injec-tion of a silicone-based fluid into the cable strands that is designed to modify ca-ble chemistry and improve dielectric strength.

The Company continues to monitor for replacement lead covered cable such as LCC or PILC cable, which cannot be moved once installed and presents signifi-cant repair challenges. Also of concern to the Company is certain XLPE cables installed in non rigid polypropylene tubes. While cable installed in rigid PVC duct can be removed relatively easily, CIC installations resists pulling and in-creases costs or retiring and replacement.

The statistical service life analysis for this account indicates average service lives in a narrow range between 45 and 40 years with lower modal dispersions for trials with lower censoring, conformance indexes, and hazard functions not compro-

PAGE 33

Current Proposed

PLife-Curve 43-R1.5 47-L1Derived Additions $7,007,974,672Plant Retirements $521,365,275Percent Retired 7.4%Plant Balance $6,486,609,397


A-35

mised by negative or declining rates.

The composition of major categories (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a full band statistical analysis of each category are shown in Table 2 below. Equipment classified in the "Devices and Other" category includes primarily cir-cuit breakers and switches.

An analysis of the subpopulations indicates a 30 L1 and a 47 S1 service life curves and a dollar weighted mean of 44 years. Service life indications derived from a statistical analysis of the combined subpopulations are considered to be within a zone of reasonableness when compared to the subpopulation indications. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed indications for a combined, non-homogeneous plant category.

LIFE ESTIMATION Based on these observations and considerations, a 47 L1 projection life curve is recommended for this account. A longer service life than currently approved would appear to be more descriptive of the ageing of retirements recorded in SCE’s plant ledger. Foster Associates was informed that Company engineers do not anticipate that future forces of retirement will be significantly different from those observed in the past for this plant category.

Although not equivalent to dollar–years of service, SCE engineers estimate a mean time to failure (MTTF) of 41 years for cross–linked polyethylene (XLPE) and 46 years for tree retardant cross–linked polyethylene (TR–XLPE) conductor. Company engineers also estimate that the mean time to wear–out of underground mainline and radial oil switches is about 35 years and the mean time to wear–out of an underground capacitor bank is about 30 years and 25 years for automatic re-closers. Approximately 8,400 subsurface oil–filled switches, 2,448 capacitor banks and 50 automatic reclosers were installed in the underground system at year–end 2018.

PAGE 34

Full Band Censoring


Conductor 5,296,589,698 82 47-S1 26.7 Devices and Other 1,052,219,844 16 30-L1 9.2 Non-unitized 137,799,855 2

Total 6,486,609,397 100 44


Investment

A-36

DISTRIBUTION PLANT ACCOUNT: 368.00 – LINE TRANSFORMERS

DESCRIPTION This account includes the investment in overhead and underground distribution line transformers used in transforming electric energy to secondary voltages. Equipment continues to be classified in this account regardless of whether actual-ly in service or held in reserve for future use. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS Distribution transformers are replaced when they fail in service or when deteriora-tion is observed during inspection or other field work. Deterioration includes leaks, corrosion and damage caused by vehicles or acts of nature. Transformers are also retired when discovered or suspected to contain regulated level of Poly-chlorinated Biphenyls (PCBs). With few exceptions such as when PCB concentra-tion of a transformer is already known, all distribution transformers owned by the Company and manufactured prior to July 1979 are assumed to contain PCBs. The Company has a PCB contaminated Transformer replacement program that has been highly effective at identifying PCB transformers and retiring them. The Company estimates that it has approximately 3,200 older distribution transformers which may contain regulated levels of PCBs. The Company manages to identify and retire an average of 250 transformers per year through the PCB program,

The statistical service life analysis for this account is stable and indicates average service lives in the mid 20s to mid 40s and lower modal dispersions for bands with lower censoring and conformance indexes. Although the majority of indica-tions are derived from graduated hazard rates that are unrealistically declining, graphical analysis confirms that the influence is limited and does not confound es-timation of the underlying forces of retirement.

It should be noted, however, that “cradle to grave” accounting is used for line transformers and associated equipment (e.g., capacitors and network protectors). Service lives indicated from a statistical analysis provide estimates of the age at which transformers are permanently retired from service.


PAGE 35

Current Proposed

PLife-Curve 33-S1.5 33-S1.5Derived Additions $4,947,828,910Plant Retirements $729,874,076Percent Retired 14.8%Plant Balance $4,217,954,834


A-37

account at December 31, 2018 and the service life indications obtained from a full band statistical analysis of each category are shown in Table 2 below.

An analysis of the subpopulations indicates average service lives between 24 and 38 years with lower to mid−modal dispersions and a dollar−weighted mean of 34 years. Service−life indications derived from a statistical analysis of the combined subpopulations are considered to be within a zone of reasonableness when com-pared to the subpopulation indications. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed indications for a combined, nonhomogeneous plant category.

LIFE ESTIMATION Service–life indications from both the full account and subpopulation polynomial analyses bound the currently approved 33–S1.5 projection life–curve. Adjusting the currently approved parameters would imply a degree of precision beyond that which can be measured or estimated from retirements recorded in SCE’s plant ledger.

Based on these considerations, retention of a 33–S1.5 projection–life is recom-mended for this account.

PAGE 36



Undeground Transformers 1,616,571,350 38 33-S2 - Overhead Transformers 1,167,188,612 28 38-S2 - Lightn. Arres. & Fuseholders 932,115,625 22 37-S3 1.1 Capacitors & Other 381,235,014 9 24-O2Non-unitized 120,844,233 3

Total 4,217,954,834 100 34


A-38

DISTRIBUTION PLANT ACCOUNT: 369.00 – SERVICES

DESCRIPTION This account includes the installed cost of overhead and underground services used for distribution purposes. Account statistics and current and proposed pa-rameters are shown in Table 1 below.

LIFE ANALYSIS Overhead (OH) services are typically installed in older urban areas and remote ru-ral areas where it is cost prohibitive to install conductor underground. Services are installed underground (UG) in newer urban areas and in new rural areas under de-velopment. Forces of retirement acting upon UG services are comparable to those acting upon UG primary conductors such as operating temperature, insulation type, vintage of cables, installation method, manufacturing quality and corrosive environment where installed. Other forces include change outs for remodeling and service panel upgrades to meet increased load demands.

The statistical service life analysis for this account is based on highly censored (52-88 percent) samples producing unreliable service–life indications for a major-ity of trials. The analysis reveals a few inconclusive indications with service lives between the high–40s and mid–60s.


PAGE 37



UG Conductor 939,824,796 63 77-S2 82.2 OH Conductor 447,648,175 30 61-R2 69.1 Conduit & Other 82,101,774 5 175-R3 96.9 Non-Unitized 24,775,679 2

Total 1,494,350,424 100 78


Current Proposed

PLife-Curve 55-R1.5 55-R1.5Derived Additions $1,534,080,857Plant Retirements $39,730,434Percent Retired 2.6%Plant Balance $1,494,350,423


A-39

An analysis of the subpopulations indicates full band average service lives be-tween 61 and 175 years with lower and mid modal dispersions and a dol-lar weighted mean of 78 years. Subpopulation service life indications are similar-ly based on highly censored trials and the resulting indications are considered less than conclusive.

LIFE ESTIMATION In the 2018 GRC (Application 16–09–001) the CPUC rejected SCE’s proposed 45– year service life and adopted a 55–year service life as reasonable and more consistent with historical data. Neither the full account nor the subpopulation analysis provides sufficient evidence to warrant adjusting the currently approved 55–R1.5 projection life and curve. It is the opinion of Foster Associates that sys-tem vintaging and pricing of retirements may be contributing to high degrees of censoring and anomalies observed in conducting a statistical analysis. Foster As-sociates concurs with SCE that current parameters should be retained for this ac-count.

PAGE 38

A-40

DISTRIBUTION PLANT ACCOUNT: 370.00 – METERS

DESCRIPTION

This account includes the cost of smart meters, devices and related appurtenances for use in measuring the electricity delivered to its users, whether actually in ser-vice or held in reserve. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS

SCE has a population of slightly over 5 million installed meters. With the excep-tion of a small number (less than 20 thousand) of electromechanical meters, AMI meters have been deployed system wide. A large–scale migration to AMI meters began in 2009 following a pilot program in 2007–2008. About 12 percent of the investment in this account is associated with electromechanical meters serving opt–out customers. The relatively recent deployment of AMI meters produces an insufficient sample of retirements to draw inferences from a statistical analysis. Censoring is about 98 percent.

Investment in the single major category of meters classified in this account at De-cember 31, 2018 and the service life indication obtained for it from a full band statistical analysis are shown in Table 2 below. The account could not be reasona-bly sub divided further apart from the minimal amount in non unitized plant.

An analysis of the single subpopulation of meters indicates a 63 R4 projection life curve at 98.8 percent censoring. This indication is comparable to indications obtained for the full band statistical service life analysis.

PAGE 39

Full Band Censoring


Meters 915,992,163 100 63-R4 98.8 Non-unitized 717,325 0

Total 916,709,488 100 63


Investment

Current Proposed

PLife-Curve 20-R3 20-R3Derived Additions $925,098,458Plant Retirements $8,388,971Percent Retired 0.9%Plant Balance $916,709,487


A-41

LIFE ESTIMATION AMI meters are electronic devices encased in plastic, typically installed in harsh environments, exposed to extreme weather conditions, and targets for vandalism. While the metrology element used in smart meters is generally considered mature and reliable technology, the life–span of the communication element is far from certain. Metering communication technology and protocols overlaid on electronic meters are rapidly evolving and will likely accelerate the rate of smart meter re-placements relative to older–style, electromechanical metering equipment.

Absent supporting life analysis indications, the service life estimation for this ac-count is based on a consideration of design life (20 years) and the opinions of Company engineers and operations personnel familiar with smart meters and ever evolving communications technology. Foster Associates therefore deferred to SCE in recommending retention of the currently approved 20–R3 projection life–curve for this account.

PAGE 40

A-42

DISTRIBUTION PLANT ACCOUNT: 373.00 – STREET LIGHTING AND SIGNAL SYSTEMS

DESCRIPTION This account includes the installed cost of equipment used wholly for public overhead street and highway lighting. Account statistics and current and proposed parameters are shown in Table 1 below.

LIFE ANALYSIS The major forces of retirement for street light poles include vehicle accidents, de-terioration, idled facilities, street upgrades and relocations. During the last 15 years, the SCE undertook an accelerated steel pole replacement program to ad-dress structural integrity deterioration and related public safety concerns. Pole de-terioration found during this program was attributable to atmospheric and water corrosion, and pole, nut and anchor bolt rust. The majority of retired poles were replaced with concrete poles.

The Company conducts annual compliance patrolling and visual inspection of systems and facilities to identify safety issues early. The potential service life of concrete poles is enhanced by adding chlorine ion intrusion inhibitors and using high quality attachments with galvanized coatings.

The statistical service life analysis for this account is reasonably stable for trials with lower censoring, conformance indexes, and non–negative fitted hazard func-tions. Indications from such trials support average service lives between the low 40s and mid–50s.


An analysis of the subpopulations indicates full–band average service lives be-tween 26 and 199 years with lower modal dispersions and a dollar–weighted mean of 60 years. Service–life indications derived from a statistical analysis of the combined subpopulations are considered to be within a zone of reasonableness when compared to the subpopulation indications. The analysis of subpopulations does not indicate forces of retirement that would significantly bias the observed

PAGE 41

Current Proposed

PLife-Curve 48-L1 50-L0.5Derived Additions $993,333,824Plant Retirements $129,130,318Percent Retired 13.0%Plant Balance $864,203,506


A-43

indications for a combined, nonhomogeneous plant category.

LIFE ESTIMATION Based on these considerations and a recognition of how accounting retirements are vintaged, a 50–L1 projection life–curve, derived from the full account broad-est placement and observation bands, is considered reasonable and is recommend-ed for this account.

PAGE 42

Full Band Censoring


Poles 378,149,747 46 60‐L1.5 63.6 Cable & Conduit 281,074,503 31 72‐R2 67.7 Fixtures 168,139,206 21 26‐S0 1.5 Transformers & Other 20,106,553 3 45‐O3 35.0 Trenches 710,517 3 199‐SQ 100.0 Non-unitized 16,022,980 2

Total 864,203,506 100 60

Investment

A-44

GENERAL PLANT DEPRECIABLE ACCOUNT: 390.00 – STRUCTURES AND IMPROVEMENTS

DESCRIPTION

This account includes the cost in place of structures and improvements used for Company purposes, the cost of which is not properly includible in other structures and improvements accounts. Account statistics and current and proposed parame-ters are shown in Table 1 below.

LIFE ANALYSIS

The statistical service life analysis for this account indicates average service lives between 35 and 50 years for trials with lower censoring and conformance indexes. A number of trials are considered less reliable if hazard rates are unrealistically declining or zeroed to avoid the suggestion of negative hazard rates. The compo-sition of major categories (or subpopulations) of plant classified in this account at December 31, 2018 and the service life indications obtained from a full band sta-tistical analysis of each category are shown in Table 2 below.

An analysis of the subpopulations indicates full band average service lives be-tween 28 and 127 years with lower modal dispersions and a dollar weighted mean of 64 years.

PAGE 43

Full Band Censoring


Buildings 294,432,144 27 77-R0.5 75.5 Common & Other 227,917,867 21 62-L0.5 59.9 Power & Lighting Systems 191,421,606 18 80-O3 75.4 HVAC 114,069,632 11 30-R1 60.7 Monitoring Devices 102,374,310 9 28-L1 45.0 Foundations & Other Struct. 82,503,250 8 52-L1 76.4 Water Supply Systems 29,836,272 3 127-SC 82.9 Non-unitized 37,289,051 3

Total 1,079,844,132 100 64


Investment

Current Proposed

PLife-Curve 45-R0.5 50-SCDerived Additions $1,202,126,326Plant Retirements $122,282,194Percent Retired 10.2%Plant Balance $1,079,844,132


A-45

LIFE ESTIMATION Based on the indications obtained from the broader bands of the statistical life analysis, a 50 SC projection life curve is recommended for this account. Foster Associates was informed that Company engineers do not anticipate that future forces of retirement will be significantly different from those observed in the past for this plant category.

PAGE 44

A-46

Appendix B

Witness Qualifications for Dr. Ronald E. White

of 14

Foster Associates Consultants, LLC 17595 S. Tamiami Trail, Suite 260 Fort Myers, FL 33908

Phone (239) 267-1600 Fax (239) 267-5030 E-mail [email protected]

Ronald E. White, Ph.D.

Education 1961 - 1964 Valparaiso University Major: Electrical Engineering

1965 Iowa State University B.S., Engineering Operations

1968 Iowa State University M.S., Engineering Valuation Thesis: The Multivariate Normal Distribution and the Simulated Plant Record Method of Life Analysis

1977 Iowa State University Ph.D., Engineering Valuation Minor: Economics Dissertation: A Comparative Analysis of Various Estimates of the Hazard Rate Associated With the Service Life of Industrial Property

Employment 2015 - Present Foster Associates Consultants, LLC President

2007 - 2015 Foster Associates, Inc. Chairman

1996 - 2007 Foster Associates, Inc. Executive Vice President

1988 - 1996 Foster Associates, Inc. Senior Vice President

1979 - 1988 Foster Associates, Inc. Vice President

1978 - 1979 Northern States Power Company Assistant Treasurer

1974 - 1978 Northern States Power Company Manager, Corporate Economics

1972 - 1974 Northern States Power Company Corporate Economist

1970 - 1972 Iowa State University Graduate Student and Instructor

1968 - 1970 Northern States Power Company Valuation Engineer

1965 - 1968 Iowa State University Graduate Student and Teaching Assistant

Publications A New Set of Generalized Survivor Tables, Journal of the Society of Depreciation Professionals, October, 1992.

The Theory and Practice of Depreciation Accounting Under Public Utility Regulation, Journal of the Society of Depreciation Professionals, December, 1989.

Appendix B

B-1

of 14

Standards for Depreciation Accounting Under Regulated Competition, paper presented at The Institute for Study of Regulation, Rate Symposium, February, 1985.

The Economics of Price-Level Depreciation, paper presented at the Iowa State University Regulatory Conference, May, 1981.

Depreciation and the Discount Rate for Capital Investment Decisions, paper presented at the National Communications Forum - National Electronics Conference, October 1979.

A Computerized Method for Generating a Life Table From the 'h-System' of Survival Functions, paper presented at the American Gas Association - Edison Electric Institute Depreciation Accounting Committee Meeting, December, 1975.

The Problem With AFDC is …, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, May, 1973.

The Simulated Plant-Record Method of Life Analysis, paper presented at the Missouri Public Service Commission Regulatory Information Systems Conference, May, 1971.

Simulated Plant-Record Survivor Analysis Program (User's Manual), special report published by Engineering Research Institute, Iowa State University, February, 1971.

A Test Procedure for the Simulated Plant-Record Method of Life Analysis, Journal of the American Statistical Association, September, 1970.

Modeling the Behavior of Property Records, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, May, 1970.

A Technique for Simulating the Retirement Experience of Limited-Life Industrial Property, paper presented at the National Conference of Electric and Gas Utility Accountants, May, 1969.

How Dependable are Simulated Plant-Record Estimates?, paper presented at the Iowa State University Conference on Public Utility Valuation and the Rate Making Process, April, 1968.

Testifying Witness

Alabama Public Service Commission, Docket No. 18488, General Telephone Company of the Southeast; testimony concerning engineering economy study techniques.

Alabama Public Service Commission, Docket No. 20208, General Telephone Company of the South; testimony concerning the equal-life group procedure and remaining-life technique.

Alberta Energy and Utilities Board, Application No. 1250392, Aquila Networks Canada; rebuttal testimony supporting proposed depreciation rates.

Alberta Energy and Utilities Board, Case No. RE95081, Edmonton Power Inc.; rebuttal evidence concerning appropriate depreciation rates.

Alberta Energy and Utilities Board, 1999/2000 General Tariff Application, Edmonton Power Inc.; direct and rebuttal evidence concerning appropriate depreciation rates.

Arizona Corporation Commission, Docket No. T-01051B-97-0689, U S West Communications, Inc.; testimony concerning appropriate depreciation rates.

Arizona Corporation Commission, Docket No. G-1032A-02-0598, Citizens Communications Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–0135A–03–0437, Arizona Public Service Company; rebuttal testimony supporting net salvage rates.

Arizona Corporation Commission, Docket No. E–01345A–05–0816, Arizona Public Service Company; testimony supporting proposed depreciation rates.

B-2

of 14




Arizona Corporation Commission, Docket No. E–01933A–12–0126, Tucson Electric Power Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–01933A–15–0322, Tucson Electric Power Company; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. G–04204A–06–0463, UNS Gas, Inc.; testimony supporting proposed depreciation rates.

Arizona Corporation Commission, Docket No. E–04204A–06–0783, UNS Electric, Inc.; testimony supporting proposed depreciation rates.



Arizona State Board of Equalization, Docket No. 6302-07-2, Arizona Public Service Company; testimony concerning valuation and assessment of contributions in aid of construction.

California Public Utilities Commission, Case Nos. A.92-06-040, 92-06-042, GTE California Incorporated; rebuttal testimony supporting depreciation study techniques.

California Public Utilities Commission. Docket No. GRC A.05–12–002, Pacific Gas and Electric Company; testimony regarding estimation of net salvage rates.

California Public Utilities Commission. Docket No. GRC A.06–12–009/A.06–12–010, San Diego Gas & Electric Company and Southern California Gas Company; testimony regarding estimation of net salvage rates.

California Public Utilities Commission. Application No. A.16–09–001 Southern California Edison; testimony regarding estimation of service lives and net salvage rates.

Public Utilities Commission of the State of Colorado, Application No. 36883-Reopened. U S WEST Communications; testimony concerning equal-life group procedure.

State of Connecticut Department of Public Utility Control, Docket No. 10–12–02, Yankee Gas Services Company; testimony supporting recommended depreciation rates.

State of Connecticut Department of Public Utility Control, Docket No. 09–12–05, The Connecticut Light and Power Company; testimony supporting recommended depreciation rates.

State of Connecticut Department of Public Utility Control, Docket No. 06–12PH01, Yankee Gas Services Company; testimony supporting recommended depreciation rates.

State of Connecticut Department of Public Utility Control, Docket No. 05–03–17, The Southern Connecticut Gas Company; testimony supporting recommended depreciation rates.

B-3

of 14

Delaware Public Service Commission, Docket No. 81-8, Diamond State Telephone Company; testimony concerning the amortization of inside wiring.

Delaware Public Service Commission, Docket No. 82-32, Diamond State Telephone Company; testimony concerning the equal-life group procedure and remaining-life technique.

Public Service Commission of the District of Columbia, Formal Case No. 842, District of Columbia Natural Gas; testimony concerning depreciation rates.

Public Service Commission of the District of Columbia, Formal Case No. 1016, Washington Gas Light Company - District of Columbia; testimony supporting proposed depreciation rates.





Federal Communications Commission, Prescription of Revised Depreciation Rates for AT&T Communications; statement concerning depreciation, regulation and competition.

Federal Communications Commission, Petition for Modification of FCC Depreciation Prescription Practices for AT&T; statement concerning alignment of depreciation expense used for financial reporting and regulatory purposes.

Federal Communications Commission, Docket No. 99-117, Bell Atlantic; affidavit concerning revenue requirement and capital recovery implications of omitted plant retirements.

Federal Energy Regulatory Commission, Docket No. RP14-118-000, WBI Energy Transmission, Inc.; testimony supporting proposed depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER10-2110-000, ITC Midwest; testimony supporting proposed depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER10-185-000, Michigan Electric Transmission Company; testimony supporting proposed depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER09-1530-000, ITC Transmission; testimony supporting proposed depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER95-267-000, New England Power Company; testimony supporting proposed depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER11-3638-000, Arizona Public Service Company; testimony supporting proposed depreciation rates

Federal Energy Regulatory Commission, Docket No. RP89-248, Mississippi River Transmission Corporation; rebuttal testimony concerning appropriateness of net salvage component in depreciation rates.

Federal Energy Regulatory Commission, Docket No. ER91-565, New England Power Company; testimony supporting proposed depreciation rates.

B-4

of 14

Federal Energy Regulatory Commission, Docket No. ER78-291, Northern States Power Company; testimony concerning rate of return and general financial requirements.

Federal Energy Regulatory Commission, Docket Nos. RP80-97 and RP81-54, Tennessee Gas Pipeline Company; testimony concerning offshore plant depreciation rates.

Federal Power Commission, Docket No. E-8252, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance.

Federal Power Commission, Docket No. E-9148, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance.

Federal Power Commission, Docket No. ER76-818, Northern States Power Company; testimony concerning rate of return and general financial requirements.

Federal Power Commission, Docket No. RP74-80, Northern Natural Gas Company; testimony concerning depreciation expense.

Public Utilities Commission of the State of Hawaii, Docket No. 00-0309, The Gas Company; testimony supporting proposed depreciation rates.

Public Utilities Commission of the State of Hawaii, Docket No. 94-0298, GTE Hawaiian Telephone Company Incorporated; testimony concerning the need for shortened service lives and disclosure of asset impairment losses.

Idaho Public Utilities Commission, Case No. U-1002-59, General Telephone Company of the Northwest, Inc.; testimony concerning the remaining-life technique and the equal-life group procedure.

Illinois Commerce Commission, Case No. 04–0476, Illinois Power Company; testimony supporting proposed depreciation rates.

Illinois Commerce Commission, Docket No. 94-0481, Citizens Utilities Company of Illinois; rebuttal testimony concerning applications of the Simulated Plant-Record method of life analysis.

Iowa State Commerce Commission, Docket No. RPU 82-47, North Central Public Service Company; testimony on depreciation rates.

Iowa State Commerce Commission, Docket No. RPU 84-34, General Telephone Company of the Midwest; testimony concerning the remaining-life technique and the equal-life group procedure.

Iowa State Utilities Board, Docket No. DPU-86-2, Northwestern Bell Telephone Company; testimony concerning capital recovery in competition.

Iowa State Utilities Board, Docket No. RPU-84-7, Northwestern Bell Telephone Company; testimony concerning the deduction of a reserve deficiency from the rate base.

Iowa State Utilities Board, Docket No. DPU-88-6, U S WEST Communications; testimony concerning depreciation subject to refund.

Iowa State Utilities Board, Docket No. RPU-90-9, Central Telephone Company of Iowa; testimony concerning depreciation rates.

Iowa State Utilities Board, Docket No. RPU-93-9, U S WEST Communications; testimony concerning principles of depreciation accounting and abandonment of FASB 71.

B-5

of 14

Iowa State Utilities Board, Docket No. DPU-96-1, U S WEST Communications; testimony concerning principles of depreciation accounting and abandonment of FASB 71.

Iowa State Utilities Board, Docket No. RPU-05-2, Aquila Networks; testimony supporting recommended depreciation rates.

Kansas Corporation Commission, Docket No. 16-KGSG-491-RTS, Kansas Gas Service, a Division of ONE Gas, Inc.; testimony supporting proposed depreciation rates.

Kansas Corporation Commission, Docket No. 12-KGSG-835-RTS, Kansas Gas Service, a Division of ONEOK, Inc.; testimony supporting proposed depreciation rates.

Kansas Corporation Commission, Docket No. 12-WSEE-112-RTS, Westar Energy, Inc.; testimony supporting proposed depreciation rates.



Kansas Corporation Commission, Docket No. 10–KCPE–415–RTS; Kansas City Power and Light; cross–answering testimony addressing the recording and treatment of third–party reimbursements in estimating net salvage rates.

Kansas Corporation Commission, Docket No. 04–AQLE–1065–RTS, Aquila Networks – WPE (Kansas); testimony supporting proposed depreciation rates.

Kansas Corporation Commission, Docket No. 03–KGSG–602–RTS, Kansas Gas Service, a Division of ONEOK, Inc.; rebuttal testimony supporting net salvage rates.

Kansas Corporation Commission, Docket No. 06–KGSG–1209–RTS, Kansas Gas Service, a Division of ONEOK, Inc.; testimony supporting proposed depreciation rates.

Kentucky Public Service Commission, Case No. 97-224, Jackson Purchase Electric Cooperative Corporation; rebuttal testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9096, Baltimore Gas and Electric Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 8485, Baltimore Gas and Electric Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9424, Delmarva Power and Light Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9385, Potomac Electric Power Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9481, Washington Gas Light Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 9103, Washington Gas Light Company; rebuttal testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 8960, Washington Gas Light Company; testimony supporting proposed depreciation rates.

Maryland Public Service Commission, Case No. 7689, Washington Gas Light Company; testimony concerning life analysis and net salvage.

Commonwealth of Massachusetts Department of Public Utilities, D.P.U. 15–155, Massachusetts Electric Company/Nantucket Electric Company; testimony supporting proposed depreciation rates.

B-6

of 14

Commonwealth of Massachusetts Department of Public Utilities, D.P.U. 10–70, Western Massachusetts Electric Company; testimony supporting proposed depreciation rates.

Commonwealth of Massachusetts Department of Telecommunications and Energy, D.T.E. 06–55, Western Massachusetts Electric Company; testimony supporting proposed depreciation rates.

Massachusetts Department of Public Utilities, Case No. DPU 91-52, Massachusetts Electric Company; testimony supporting proposed depreciation rates which include a net salvage component.

Michigan Public Service Commission, Case No. U–18150, DTE Electric Company; testimony supporting proposed depreciation rates.

Michigan Public Service Commission, Case No. U–16991, The Detroit Edison Company; testimony supporting proposed depreciation rates.

Michigan Public Service Commission, Case No. U–16117, The Detroit Edison Company; testimony supporting proposed depreciation rates.

Michigan Public Service Commission, Case No. U–15699, Michigan Consolidated Gas Company; testimony supporting proposed depreciation rates.

Michigan Public Service Commission, Case No. U–13899, Michigan Consolidated Gas Company; testimony concerning service life estimates.

Michigan Public Service Commission, Case No. U-13393, Aquila Networks – MGU; testimony supporting proposed depreciation rates.

Michigan Public Service Commission, Case No. U-12395, Michigan Gas Utilities; testimony supporting proposed depreciation rates including amortization accounting and redistribution of recorded reserves.

Michigan Public Service Commission, Case No. U-6587, General Telephone Company of Michigan; testimony concerning use of a theoretical depreciation reserve with the remaining-life technique.

Michigan Public Service Commission, Case No. U-7134, General Telephone Company of Michigan; testimony concerning the equal-life group depreciation procedure.

Minnesota Public Service Commission, Docket No. E-611, Northern States Power Company; testimony concerning rate of return and general financial requirements.

Minnesota Public Service Commission, Docket No. E-1086, Northern States Power Company; testimony concerning depreciation rates.

Minnesota Public Service Commission, Docket No. G-1015, Northern States Power Company; testimony concerning rate of return and general financial requirements.

Public Service Commission of the State of Missouri, Case No. ER-2009-0090, KCP&L Greater Missouri Operations, rebuttal testimony concerning depreciation rates.

Public Service Commission of the State of Missouri, Case No. ER-2001-672, Missouri Public Service, a division of Utilicorp United Inc.; surrebuttal testimony regarding computation of income tax expense.

Public Service Commission of the State of Missouri, Case No. TO-82-3, Southwestern Bell Telephone Company; rebuttal testimony concerning the remaining-life technique and the equal-life group procedure.

Public Service Commission of the State of Missouri, Case No. GO-97-79, Laclede Gas Company; rebuttal testimony concerning adequacy of database for conducting depreciation studies.

B-7

of 14

Public Service Commission of the State of Missouri, Case No. GR-99-315, Laclede Gas Company; rebuttal testimony concerning treatment of net salvage in development of depreciation rates.

Public Service Commission of the State of Missouri, Case No. HR–2004–0024, Aquila Inc. d/b/a/ Aquila Networks–L & P; testimony supporting depreciation rates.

Public Service Commission of the State of Missouri, Case No. ER–2004–0034, Aquila Inc. d/b/a/ Aquila Networks–L & P and Aquila Networks–MPS; testimony supporting depreciation rates.

Public Service Commission of the State of Missouri, Case No. GR–2004–0072, Aquila Inc. d/b/a/ Aquila Networks–L & P and Aquila Networks–MPS; testimony supporting depreciation rates.

Public Service Commission of the State of Montana, Docket No. 88.2.5, Mountain State Telephone and Telegraph Company; rebuttal testimony concerning the equal-life group procedure and amortization of reserve imbalances.

Montana Public Service Commission, Docket No. D95.9.128, The Montana Power Company; testimony supporting proposed depreciation rates.

Montana Public Service Commission, Docket No. D2018.2.12, NorthWestern Energy –Montana; testimony supporting proposed depreciation rates

Nebraska Public Service Commission, Docket No. NG–0041, Aquila Networks (PNG Nebraska); testimony supporting proposed depreciation rates.

Public Service Commission of Nevada, Docket No. 92-7002, Central Telephone Company-Nevada; testimony supporting proposed depreciation rates.

Public Service Commission of Nevada, Docket No. 91-5054, Central Telephone Company-Nevada; testimony supporting proposed depreciation rates.

New Hampshire Public Utilities Commission, Docket No. DR95-169, Granite State Electric Company; testimony supporting proposed net salvage rates.

New Jersey Board of Public Utilities, Docket No. GR07110889, New Jersey Natural Gas Company; testimony supporting proposed depreciation rates.

New Jersey Board of Public Utilities, Docket No. GR 87060552, New Jersey Natural Gas Company; testimony supporting depreciation rates.

New Jersey Board of Regulatory Commissioners, Docket No. GR93040114J, New Jersey Natural Gas Company; testimony supporting depreciation rates.

New Jersey Board of Regulatory Commissioners, Docket No. GR15111304, New Jersey Natural Gas Company; testimony supporting depreciation rates.

New York Public Service Commission, Case No. 12–G–0202. Niagara Mohawk Power Corporation d/b/a National Grid; testimony supporting recommended depreciation rates.

New York Public Service Commission, Case No. 10–E–0050. Niagara Mohawk Power Corporation d/b/a National Grid; testimony supporting recommended depreciation rates.

North Carolina Utilities Commission, Docket No. E-7, SUB 487, Duke Power Company; rebuttal testimony concerning proposed depreciation rates.

North Carolina Utilities Commission, Docket No. P-19, SUB 207, General Telephone Company of the South; rebuttal testimony concerning the equal-life group depreciation procedure.

B-8

of 14

North Dakota Public Service Commission, Case No. 8860, Northern States Power Company; testimony concerning general financial requirements.

North Dakota Public Service Commission, Case No. 9634, Northern States Power Company; testimony concerning rate of return and general financial requirements.



Oklahoma Corporation Commission, Cause No. PUD 201500213, Oklahoma Natural Gas Company; testimony supporting revised depreciation rates.

Oklahoma Corporation Commission, Cause No. PUD 200900110, Oklahoma Natural Gas Company; testimony supporting revised depreciation rates.

Ontario Energy Board, E.B.R.O. 385, Tecumseh Gas Storage Limited; testimony concerning depreciation rates.

Ontario Energy Board, E.B.R.O. 388, Union Gas Limited; testimony concerning depreciation rates.

Ontario Energy Board, E.B.R.O. 456, Union Gas Limited; testimony concerning depreciation rates.

Ontario Energy Board, E.B.R.O. 476-03, Union Gas Limited; testimony concerning depreciation rates.

Public Utilities Commission of Ohio, Case No. 81-383-TP-AIR, General Telephone Company of Ohio; testimony in support of the remaining-life technique.

Public Utilities Commission of Ohio, Case No. 82-886-TP-AIR, General Telephone Company of Ohio; testimony concerning the remaining-life technique and the equal-life group procedure.

Public Utilities Commission of Ohio, Case No. 84-1026-TP-AIR, General Telephone Company of Ohio; testimony in support of the equal-life group procedure and the remaining-life technique.

Public Utilities Commission of Ohio, Case No. 81-1433, The Ohio Bell Telephone Company; testimony concerning the remaining-life technique and the equal-life group procedure.

Public Utilities Commission of Ohio, Case No. 83-300-TP-AIR, The Ohio Bell Telephone Company; testimony concerning straight-line age-life depreciation.

Public Utilities Commission of Ohio, Case No. 84-1435-TP-AIR, The Ohio Bell Telephone Company; testimony in support of test period depreciation expense.

Public Utilities Commission of Oregon, Docket No. UM 204, GTE of the Northwest; testimony concerning the theory and practice of depreciation accounting under public utility regulation.

Public Utilities Commission of Oregon, Docket No. UM 840, GTE Northwest Incorporated; rebuttal testimony concerning principles of capital recovery.

Pennsylvania Public Utility Commission, Docket No. R-80061235, The Bell Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base.

Pennsylvania Public Utility Commission, Docket No. R-811512, General Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base.

B-9

of 14

Pennsylvania Public Utility Commission, Docket No. R-811819, The Bell Telephone Company of Pennsylvania; testimony concerning the proper depreciation reserve to be used with an original cost rate base.

Pennsylvania Public Utility Commission, Docket No. R-822109, General Telephone Company of Pennsylvania; testimony in support of the remaining-life technique.

Pennsylvania Public Utility Commission, Docket No. R-850229, General Telephone Company of Pennsylvania; testimony in support of the remaining-life technique and the proper depreciation reserve to be used with an original cost rate base.

Pennsylvania Public Utility Commission, Docket No. C-860923, The Bell Telephone Company of Pennsylvania; testimony concerning capital recovery under competition.

Rhode Island Public Utilities Commission, Docket No. 2290, The Narragansett Electric Company; testimony supporting proposed net salvage rates and depreciation rates.

South Carolina Public Service Commission, Docket No. 91-216-E, Duke Power Company; testimony supporting proposed depreciation rates.

South Dakota Public Utilities Commission, Docket No. EL14–106, NorthWestern Energy; testimony supporting revised depreciation rates.

Public Utilities Commission of the State of South Dakota, Case No. F-3062, Northern States Power Company; testimony concerning general financial requirements and measurements of financial performance.

Public Utilities Commission of the State of South Dakota, Case No. F-3188, Northern States Power Company; testimony concerning rate of return and general financial requirements.

Securities and Exchange Commission, File No. 3-5749, Northern States Power Company; testimony concerning the financial and ratemaking implications of an affiliation with Lake Superior District Power Company.

Tennessee Public Service Commission, Docket No. 89-11041, United Inter-Mountain Telephone Company; testimony concerning depreciation principles and capital recovery under competition.

The Railroad Commission of Texas, GUD Docket No. 9988, Texas Gas Service, testimony supporting recommended depreciation rates.





State of Vermont Public Service Board, Docket No. 6596, Citizens Communications Company – Vermont Electric Division; testimony supporting recommended depreciation rates.

State of Vermont Public Service Board, Docket No. 6946 and 6988, Central Vermont Public Service Corporation; testimony supporting net salvage rates.

B-10

of 14

Commonwealth of Virginia State Corporation Commission, Case No. PUE-2002-00364, Washington Gas Light Company; testimony supporting proposed depreciation rates.

Public Service Commission of Wisconsin, Docket No. 2180-DT-3, General Telephone Company of Wisconsin; testimony concerning the equal-life group depreciation procedure.

Other Consulting Activities

Arbitrator in a Technical Dispute relating to classification of Capital Budget expenditures.

Moran Towing Corporation. In Re: Barge TEXAS-97 CIV. 2272 (ADS) and Tug HEIDE MORAN – 97 CIV. 1947 (ADS), United States District Court, Southern District of New York.

John Reigle, et al. v. Baltimore Gas & Electric Co., et al., Case No. C-2001-73230-CN, Circuit Court for Anne Arundel County, Maryland.

SR International Business Insurance Co. vs. WTC Properties et. al., 01,CV–9291 (JSM) and other related cases.

BellSouth Telecommunications, Inc. v. Citizens Utilities Company d/b/a/ Louisiana Gas Service Company, CA No. 95-2207, United States District Court, Eastern District of Louisiana.

Affidavit on behalf of Continental Cablevision, Inc. and its operating cable television systems regarding basic broadcast tier and equipment and installation cost-of-service rate justification.

Office of Chief Counsel, Internal Revenue Service. In Re: Kansas City Southern Railway Co., et. al. Docket Nos. 971-72, 974-72, and 4788-73.

Office of Chief Counsel, Internal Revenue Service. In Re: Northern Pacific Railway Co., Docket No. 4489-69.

United States Department of Justice. In Re: Burlington Northern Inc. v. United States, Ct. Cl. No. 30-72.

Minnesota District Court. In Re: Northern States Power Company v. Ronald G. Blank, et. al. File No. 394126; testimony concerning depreciation and engineering economics.

Faculty Depreciation Programs for public utility commissions, companies, and consultants, sponsored by Depreciation Programs, Inc., in cooperation with Western Michigan University. (1980 - 1999)

United States Telephone Association (USTA), Depreciation Training Seminar, November 1999.

Depreciation Advocacy Workshop, a three-day team-training workshop on preparation, presentation, and defense of contested depreciation issues, sponsored by Gilbert Associates, Inc., October, 1979.

Corporate Economics Course, Employee Education Program, Northern States Power Company. (1968 - 1979)

Perspectives of Top Financial Executives, Course No. 5-300, University of Minnesota, September, 1978.

Depreciation Programs for public utility commissions, companies, and consultants, jointly sponsored by Western Michigan University and Michigan Technological University, 1973.

B-11

of 14

Professional Associations

Advisory Committee to the Institute for Study of Regulation, sponsored by the American University and The University of Missouri-Columbia.

American Economic Association.

American Gas Association - Edison Electric Institute Depreciation Accounting Committee.

Board of Directors, Iowa State Regulatory Conference.

Edison Electric Institute, Energy Analysis Division, Economic Advisory Committee, 1976-1980.

Financial Management Association.

The Institute of Electrical and Electronics Engineers, Inc., Power Engineering Society, Engineering and Planning Economics Working Group.

Midwest Finance Association.

Society of Depreciation Professionals (Founding Member and Chairman, Policy Committee).

Moderator Depreciation Open Forum, Iowa State University Regulatory Conference, May 1991.

The Quantification of Risk and Uncertainty in Engineering Economic Studies, Iowa State University Regulatory Conference, May 1989.

Plant Replacement Decisions with Added Revenue from New Service Offerings, Iowa State University Regulatory Conference, May 1988.

Economic Depreciation, Iowa State University Regulatory Conference, May 1987.

Opposing Views on the Use of Customer Discount Rates in Revenue Requirement Comparisons, Iowa State University Regulatory Conference, May 1986.

Cost of Capital Consequences of Depreciation Policy, Iowa State University Regulatory Conference, May 1985.

Concepts of Economic Depreciation, Iowa State University Regulatory Conference, May 1984.

Ratemaking Treatment of Large Capacity Additions, Iowa State University Regulatory Conference, May 1983.

The Economics of Excess Capacity, Iowa State University Regulatory Conference, May 1982.

New Developments in Engineering Economics, Iowa State University Regulatory Conference, May 1980.

Training in Engineering Economy, Iowa State University Regulatory Conference, May 1979.

The Real Time Problem of Capital Recovery, Missouri Public Service Commission, Regulatory Information Systems Conference, September 1974.

Speaker Depreciation Training Seminar, Kansas Gas Service, October 2018.

Depreciation Workshop, Oklahoma Corporation Commission, Public Utility Division, March 2015.

Depreciation Workshop, ONE Gas, Inc. January 2015.

Depreciation Training Seminar, Florida Public Service Commission, March 2013.

B-12

of 14

Depreciation and Obsolescence (Isness and Oughtness), Ninety–Fifth Annual Arizona Tax Conference, August 2012.

Group Depreciation Practices of Regulated Utilities (IAS 16 Property, Plant and Equipment), Hydro One Networks, Inc., November 2008.

Economics, Finance and Engineering Valuation. Florida Gulf Coast University, April 2007.

Depreciation Studies for Regulated Utilities, Hydro One Networks, Inc., April 2006.

Depreciation Studies for Cooperatives and Small Utilities. TELERGEE CFO and Controllers Conference, November, 2004.

Finding the “D” in RCNLD (Valuation Applications of Depreciation), Society of Depreciation Professionals Annual Meeting, September 2001.

Capital Asset and Depreciation Accounting, City of Edmonton Value Engineering Workshop, April 2001.

A Valuation View of Economic Depreciation, Society of Depreciation Professionals Annual Meeting, October 1999.

Capital Recovery in a Changing Regulatory Environment, Pennsylvania Electric Association Financial-Accounting Conference, May 1999.

Depreciation Theory and Practice, Southern Natural Gas Company Accounting and Regulatory Seminar, March 1999.

Depreciation Theory Applied to Special Franchise Property, New York Office of Real Property Services, March 1999.

Capital Recovery in a Changing Regulatory Environment, PowerPlan Consultants Annual Client Forum, November 1998.

Economic Depreciation, AGA Accounting Services Committee and EEI Property Accounting and Valuation Committee, May 1998.

Discontinuation of Application of FASB Statement No. 71, Southern Natural Gas Company Accounting Seminar, April 1998.

Forecasting in Depreciation, Society of Depreciation Professionals Annual Meeting, September 1997.

Economic Depreciation In Response to Competitive Market Pricing, 1997 TELUS Depreciation Conference, June 1997.

Valuation of Special Franchise Property, City of New York, Department of Finance Valuation Seminar, March 1997.

Depreciation Implications of FAS Exposure Draft 158-B, 1996 TLG Decommissioning Conference, October 1996.

Why Economic Depreciation?, American Gas Association Depreciation Accounting Committee Meeting, August 1995.

The Theory of Economic Depreciation, Society of Depreciation Professionals Annual Meeting, November 1994.

Vintage Depreciation Issues, G & T Accounting and Finance Association Conference, June 1994.

Pricing and Depreciation Strategies for Segmented Markets (Regulated and Competitive), Iowa State Regulatory Conference, May 1990.

Principles and Practices of Depreciation Accounting, Canadian Electrical Association and Nova Scotia Power Electric Utility Regulatory Seminar, December 1989.

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Principles and Practices of Depreciation Accounting, Duke Power Accounting Seminar, September 1989.

The Theory and Practice of Depreciation Accounting Under Public Utility Regulation, GTE Capital Recovery Managers Conference, February 1989.

Valuation Methods for Regulated Utilities, GTE Capital Recovery Managers Conference, January 1988.

Depreciation Principles and Practices for REA Borrowers, NRECA 1985 National Accounting and Finance Conference, September 1985.

Depreciation Principles and Practices for REA Borrowers, Kentucky Association of Electric Cooperatives, Inc., Summer Accountants Association Meeting, June 1985.

Considerations in Conducting a Depreciation Study, NRECA 1984 National Accounting and Finance Conference, October 1984.

Software for Conducting Depreciation Studies on a Personal Computer, United States Independent Telephone Association, September 1984.

Depreciation—An Assessment of Current Practices, NRECA 1983 National Accounting and Finance Conference, September 1983

Depreciation—An Assessment of Current Practices, REA National Field Conference, September 1983.

An Overview of Depreciation Systems, Iowa State Commerce Commission, October 1982.

Depreciation Practices for Gas Utilities, Regulatory Committee of the Canadian Gas Association, September 1981.

Practice, Theory, and Needed Research on Capital Investment Decisions in the Energy Supply Industry, workshop, sponsored by Michigan State University and the Electric Power Research Institute, November 1977.

Depreciation Concepts Under Regulation, Public Utilities Conference, sponsored by The University of Texas at Dallas, July 1976.

Electric Utility Economics, Mid-Continent Area Power Pool, May 1974.

Honors and Awards

The Society of Sigma Xi.

Professional Achievement Citation in Engineering, Iowa State University, 1993.

May 2019

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sce-07 v.03 testimony...application no.: a.19-08- exhibit no.: sce-07, vol. 3 witnesses: d. gunn r....

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