transmission and distribution (t&d) volume 6, part 1 ... · exhibit no.: sce-03, vol. 06, part...

Application No.: Exhibit No.: SCE-03, Vol. 06, Part 1 Witnesses: M. Stark

K. Trainor

(U 338-E)

2015 General Rate Case

Transmission And Distribution (T&D) Volume 6, Part 1 – Distribution Maintenance

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SUMMARY

This chapter describes SCE’s inspection and maintenance activities associated with the

distribution grid, including planned and unplanned work. Most of the planned work is performed to

satisfy various requirements placed upon SCE by the California Public Utilities Commission (CPUC), as

well as various city and county agencies. SCE is requesting $2.535 billion in 2013-2017 capital

expenditures and $189 million in 2015 test year expenses in these categories.

Distribution Maintenance Programs O&M Expenses 2015 Forecast

(Constant 2012 $Million, FERC and CPUC Jurisdictional)

T&D Engineering and Grid Technology (Volume 2)

$54 8%

Customer Driven Prog & Distr. Con. (Volume 5)

$16 2%

Distribution Maintenance (Volume 6, Part 1)

$190 30%

Pole Loading (Volume 6, Part 2)

$38 6%

Grid Operations (Volume 7)

$112 18%

Transmission & Substation Maintenance (Volume 8)

$86 13%

Safety, Training, and Environmental

Programs (Volume 9)$68

11%

T&D Other Costs and OOR (Volume 10)

$76 12%

Distribution Maintenance Programs Capital Expenditures 2013 – 2017 Forecast

($ Millions, CPUC Jurisdictional Only)

T&D Engineering and Grid Technology

(Volume 2), $183 , 1%

System Planning Capital Projects

(Volume 3), $2,165 , 18%

Infrastructure Replacement

Programs (Volume 4), $2,032 , 17%

Customer Driven Prog & Distr. Con.(Volume

5), $3,158 , 26%

Distribution Maintenance

(Volume 6, Part 1), $2,519 , 21%

Pole Loading (Volume 6, Part 2), $1,078 , 9%

Grid Operations (Volume 7), $511 , 4%

Transmission & Substation

Maintenance (Volume 8), $438 , 4%

SCE-03: Transmission and Distribution Volume 06, Part 1 – Distribution Maintenance

Table Of Contents

Section Page Witness

-i-

I. INTRODUCTION .............................................................................................1 M. Stark

A. Distribution Inspection and Maintenance Program (DIMP) Overview ................................................................................................1

B. Forecast O&M Expenses and Capital Expenditures ..............................4

1. O&M Expenses ..........................................................................4

2. Capital Expenditures ..................................................................5

C. Comparison of 2012 GRC Request, Authorized, and Recorded ................................................................................................6

1. O&M Expenses ..........................................................................6

2. Capital Expenditures ..................................................................7

II. Work Descriptions, Recorded Costs And Test Year Forecasts .........................9

A. Distribution Equipment Inspection Expenses ........................................9

1. Annual Patrols, Portion of FERC Account 583.120 ..................9

a) Cost Forecast ..................................................................9

2. Overhead Detailed Inspection Program, Portion of FERC Account 583.120 ...........................................................10

a) Cost Forecast ................................................................11

3. Underground Detailed Inspections (UDI), Portion of FERC Account 583.120 ...........................................................12

a) Cost Forecast ................................................................13

B. Distribution Maintenance.....................................................................14

1. Cost Forecast – Maintenance Expense (O&M), Portions of FERC Accounts 593.120 and 594.120 ..................15

2. Cost Forecast – Distribution Maintenance Capital Expenditures ............................................................................16


Table Of Contents (Continued)


-ii-

C. Vegetation Management, Portion of FERC Account 593.120.................................................................................................19

1. Cost Forecast for Routine Vegetation Management ................20

2. Cost Forecast for Bark Beetle Remediation .............................21

3. Big Creek Corridor ..................................................................21

a) Cost Forecast ................................................................22

D. Miscellaneous Inspection and Maintenance ........................................23

1. Distribution Transformer Maintenance Expenses, Portion of FERC Account 593.120 ..........................................23

a) Cost Forecast ................................................................24

2. Graffiti Removal Expenses, Portion of 593.120 ......................24

a) Cost Forecast ................................................................24

3. Distribution Apparatus Inspection & Maintenance Expenses, Portion of 593.120 ..................................................25

a) Cost Forecast ................................................................25

4. Removal of Idle Facilities Capital Expenditures .....................26

a) Cost Forecast ................................................................26

E. Underground Structure Rehabilitation Program ..................................27

1. Cost Forecast - Underground Structure Field Investigation Expenses, Portion of FERC Account 583.120.....................................................................................30

2. Cost Forecast - Underground Structure Repair Expenses, Portion of FERC Account 593.120 .........................31

3. Cost Forecast - Underground Structure Replacements ...........................................................................33

F. Overhead Conductor Program .............................................................35




-iii-

1. Cost Forecast ............................................................................36

G. Pole Inspection and Replacement ........................................................37 K. Trainor

1. Distribution Pole Inspections, Portion of FERC Account 583.120 ......................................................................37

a) Cost Forecast ................................................................39

2. Deteriorated Pole Replacements Capital Expenditures ............................................................................40

a) Cost Forecast ................................................................41

3. Aged Pole Replacement Capital Expenditures ........................43

a) Cost Forecasts ..............................................................46

H. Joint Pole Activities .............................................................................47

1. Joint Pole Organization (JPO) Expenses, Portion of FERC Account 583.120 ...........................................................47

a) Cost Forecast ................................................................48

2. Joint Pole Expense Credits, Portion of FERC Account 583.120 ......................................................................48

a) Cost Forecast ................................................................49

3. Joint Pole Replacement Capital Credits ...................................50

a) Cost Forecast ................................................................50

I. Wood Pole Disposal .............................................................................51

a) Cost Forecast ................................................................52

J. Summary of FERC Accounts ...............................................................54

1. FERC Account 583.120 ...........................................................54

2. FERC Account 593.120 ...........................................................55

3. FERC Account 594.120 ...........................................................56




-iv-

Appendix A Witness Qualifications ................................................................................


List Of Figures

Figure Page

-v-

Figure I-1 Distribution Inspection and Maintenance Program O&M Costs Summary –

Authorized vs. Recorded (Constant 2012 $000) ....................................................................................6

Figure I-2 Distribution Inspection and Maintenance Program Capital Expenditures

Summary – Authorized vs. Recorded (Constant 2012 $millions) .........................................................7

Figure II-3 Distribution Maintenance Expenditures Various WBS Recorded and Adjusted

2008-2012/Forecast 2013-2015 ($000) Capital Expenditures .............................................................18

Figure II-4 Removal of Idle Facilities WBS Element CET-PD-CR-IF Recorded and

Adjusted 2008-2012/Forecast 2013-2015 ($000) Capital Expenditures .............................................27

Figure II-5 Underground Structure Replacements Recorded 2008-2012/Forecast 2013-

2015 ($000) Capital Expenditures .......................................................................................................35

Figure II-6 Deteriorated Pole Replacement, Distribution Portion of WBS Element CET-

PD-IR-DP Recorded 2008-2012/Forecast 2013-2015 ($000) Capital Expenditures ...........................42

Figure II-7 Deteriorated Pole Replacement, Transmission Portion of WBS Element CET-

PD-IR-TR Recorded and Adjusted 2008-2012/Forecast 2013-2015 ($000) Capital

Expenditures ........................................................................................................................................43

Figure II-8 Age of Distribution Wood Poles .............................................................................................45

Figure II-9 Programmatic Pole Replacements ...........................................................................................46

Figure II-10 Aged Pole Replacement Portion of WBS CET-PD-IR-DP Recorded and

Adjusted 2008-2012/Forecast 2013-2015 ($000) Capital Expenditures .............................................47

Figure II-11 Joint Pole Credits, Distribution and Transmission WBS Elements CET-PD-

CR-JD and CET-PD-CR-JT Recorded and Adjusted 2008-2012/Forecast 2013-2015

($000) Capital Expenditures ...............................................................................................................51

Figure II-12 Wood Pole Disposal WBS Element WBS CET-PD-OT-WP Recorded and

Adjusted 2008-2012/Forecast 2013-2015 ($000) Capital Expenditures ............................................53


List Of Tables

Table Page

-vi-

Table I-1 2013-2015 O&M Expense Forecast .............................................................................................4

Table I-2 2013-2017 Capital Expenditure Forecasts ...................................................................................5

Table II-3 Annual Patrols, Portion of FERC Account 583.120 Recorded and Adjusted

2008-2012/Forecast 2013-2015 (Constant 2012 $000) ........................................................................9

Table II-4 Overhead Detailed Inspection, Portion of 583.120 ...................................................................11

Table II-5 Underground Detail Inspections, Portion of FERC Account 583.120 Recorded

and Adjusted 2008-2012/Forecast 2013-2015 .....................................................................................13

Table II-6 Distribution Maintenance Expenses, Portion of 593.120 and 594.120 Recorded

and Adjusted 2008-2012 / Forecast 2013-2015 (Constant 2012 $000) ...............................................16

Table II-7 Vegetation Management, Portion of 593.120 (Constant 2012 $000) .......................................20

Table II-8 Bark Beetle Related Vegetation Management, Portion of 593.120 ..........................................21

Table II-9 Big Creek Expenses, Portion of 571.150 Recorded and Adjusted 2008-

2012/Forecast 2013-2015 (Constant 2012 $000) ................................................................................23

Table II-10 Distribution Transformer Maintenance Expenses, Portion of 593.120 ..................................23

Table II-11 Remove Graffiti from Distribution Equipment Portion of FERC Account

593.120 Recorded and Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012

$000) ....................................................................................................................................................24

Table II-12 Distribution Apparatus Inspection & Maintenance Expenses, Portion of

593.120.................................................................................................................................................25

Table II-13 Vault Inspection, Repair and Replacement Forecast Summary .............................................29

Table II-14 Manhole Inspection, Repair and Replacement Forecast Summary ........................................30

Table II-15 Field Evaluation Expenses, Portion of FERC Account 583.120 Recorded and

Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) .......................................................31

Table II-16 Underground Structure Repair Detailed Forecast (Constant 2012 $000) ...............................32

Table II-17 Underground Structure Repairs, Portion of FERC Account 593.120 Recorded

and Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) .................................................33

Table II-18 Underground Structure Replacement Forecast (Constant 2012 $000) ...................................34

Table II-19 Overhead Conductor Program Unit Forecast ..........................................................................36


List Of Tables (Continued)

Table Page

-vii-

Table II-20 Overhead Conductor Program, Portion of FERC Account 593.120 Recorded

and Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) .................................................37

Table II-21 Distribution Pole Inspections, Portion of FERC Account 583.120 Recorded

and Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) ................................................40

Table II-22 Pole Inspection Findings, Transmission and Distribution ......................................................41

Table II-23 Joint Pole Organization Expenses (Portion of FERC Account 583.120)

Recorded and Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) .................................48

Table II-24 Joint Pole Credit Expenses Portion of FERC Account 583.120 Recorded and

Adjusted 2008-2012/Forecast 2013-2015 (Constant 2012 $000) ........................................................49

Table II-25 Joint Pole Credits – Forecast by Activity Types .....................................................................50

Table II-26 Joint Pole Credit Unit Credit Analysis ...................................................................................51

Table II-27 Wood Pole Disposal Unit Cost Analysis ................................................................................52

Table II-28 Inspection of Distribution Overhead and Underground Lines and Equipment

Summary of FERC Account 583.120 Recorded and Adjusted 2008-2012/Forecast

2013-2015 ............................................................................................................................................54

Table II-29 Planned Maintenance of Distribution Overhead and Underground Lines

Summary of FERC Account 593.120; Recorded and Adjusted 2008-2012/Forecast

2013-2015(Constant 2012 $000) .........................................................................................................55

Table II-30 Distribution Overhead and Underground Breakdown Maintenance Summary

of FERC Account 594.120 Recorded and Adjusted 2008-2012/Forecast 2013-2015

(Constant 2012 $000) ...........................................................................................................................56

1

I. 1

INTRODUCTION 2

The electrical equipment and structures that make up SCE’s distribution grid undergo planned 3

and unplanned inspection and maintenance. Required maintenance is identified through three sources: 4

1. Scheduled inspections driven by specific regulatory requirements; 5

2. Field inspections by personnel while performing other work; and 6

3. Inspections after emergencies or in-service failures of equipment. 7

These inspections drive three categories of maintenance – repairs made by inspectors (known as 8

RBIs), repairs made by maintenance crews, and replacements made by construction crews. 9

In addition, SCE periodically initiates new programs to target specific issues or to respond to 10

particular regulatory requirements. This volume, along with Mr. Trainor’s testimony in Exhibit SCE-03, 11

Volume 06, Part 2, addresses several such programs, including the Pole Loading Program, the 12

underground structure replacement program, overhead conductor program, and vegetation management 13

programs. 14

A. Distribution Inspection and Maintenance Program (DIMP) Overview 15

In January 2008, SCE launched a new distribution inspection and maintenance program (DIMP) 16

that provides for the inspection and maintenance of SCE’s distribution facilities. SCE’s DIMP was 17

created to comply with Decision (D.) 04-04-065 in the Line Maintenance Order Instituting Investigation 18

(OII) and a memorandum of understanding (MOU) with the Safety and Enforcement Division (SED, 19

formerly known as the Commission’s Consumer Protection and Safety Division).1 In addition to 20

satisfying the requirements of the Line Maintenance OII Decision and the MOU, SCE’s goal in creating 21

DIMP was to meet the requirements of GOs 95, 128, and 165 in a way that: (1) is consistent with sound 22

maintenance practices; (2) enhances public and employee safety and maintains system reliability; and 23

(3) delivers overall greater safety value for each safety dollar spent. 24

1 On April 22, 2004, the Commission issued D.04-04-065 in I.01-08-029 (Maintenance OII). In the Decision, the

Commission, among other things, directed that SCE, in consultation with SED (formerly known as CPSD), refine its distribution maintenance program. On August 13, 2005, SED and SCE signed a MOU that memorialized the agreed-upon principles between SCE and CPSD relating to the development of SCE’s new distribution maintenance and inspection program. During this process SCE and SED also solicited input and participation from PG&E and SDG&E to develop a three-level maintenance and inspection “Common Platform” in the hopes of ultimately developing a model that could be applied to all electric utilities subject to General Orders 95, 128, and 165. Principles of this “Common Platform”, which was the foundation for SCE’s DIMP program, were adopted in R.08-11-005 and added to General Order 95, Rule 18A. DIMP was discussed in Vol. 2, Part 4, Chapter XIII of SCE’s 2009 GRC.

2

Most notably, under DIMP, SCE prioritizes work based on the specific condition of each facility 1

or piece of equipment and its probability for impact on safety and reliability, taking into account several 2

factors. As a result, DIMP allows SCE to emphasize a condition’s risk to safety and reliability from a 3

wider perspective, and reduces the need to allocate resources to those conditions that pose a lower risk, 4

or no risk at all. Under this approach, SCE can deploy its limited resources more effectively and 5

efficiently to remediate conditions that have higher safety and reliability risks to achieve a higher value 6

for each dollar spent. This approach is consistent with the Commission’s direction in the Line 7

Maintenance OII Decision and in accordance with the MOU. 8

DIMP has three maintenance priority levels. During inspections, SCE inspectors identify and 9

rate conditions based on the specifics for that condition, taking into account several factors. These 10

factors include such things as the type of facility or equipment, loading, location, accessibility, climate, 11

and direct or potential impact on safety or reliability. Highest priority items requiring immediate action 12

are assigned Priority 1. Priority 2 items do not require immediate action, but do require action to be 13

corrected within a specified time period. Priority 1 and Priority 2 items may be fully repaired or 14

temporarily repaired and reclassified as a lower priority item. Priority 3 items are lower priority items 15

that involve little or no safety or reliability risk. SCE responds to Priority 3 items by taking action at or 16

before the next detailed inspection, which may include re-inspection, re-evaluation, reassessment, or 17

repair.2 18

Since the launch of DIMP in 2008, SCE has continued to refine and improve its inspection and 19

maintenance program. For example, beginning in 2009, SCE began completing all identified 20

maintenance items at the structure when a qualified worker is performing scheduled work on that 21

structure, irrespective of the additional items’ due dates or elevation on the structure. In essence, 22

depending upon crew qualifications, SCE will carry out all identified maintenance on the pole when 23

maintenance work is scheduled on the pole. This new approach is consistent with the requirements of 24

the Line Maintenance OII Decision and the MOU, and SCE believes it is the right approach to 25

maintenance. 26

Also, in 2009, SCE began notifying communication companies (such as Verizon or Time Warner 27

Cable) of Priority 2 conditions when such conditions are found during an SCE inspection. 28

Communication companies typically own or lease space on the pole in an area below the electrical level 29

3

that is known as the communication level, and their actions can result in safety or reliability concerns for 1

SCE assets. If these conditions are considered a safety or reliability concern, such as a communication 2

service drop attached to SCE’s service drop, SCE sends correspondence to the communication company 3

notifying them of the condition. Pursuant to the Commission’s Phase 1 decision in the Disaster 4

Management Rulemaking (R.08-11-005), a similar requirement has since created reciprocal obligations 5

for all electric and communication companies.3 In late 2009, SCE began receiving, and taking action on, 6

such notifications from telecommunication companies. 7

In 2009, SCE began using a new process for identifying, tracking, and evaluating underground 8

structures for repair or replacement. Since 2009, SCE has continued to refine and improve upon its 9

programs for the inspection, repair, and replacement of underground structures. In addition, SCE 10

recently expanded this program to include routine inspection and maintenance of underground structures 11

which were previously not included in G.O. 165 inspections because they do not contain electrical 12

equipment. SCE determined that these assets needed to be included as part of the regular DIMP 13

inspections to maintain their structural integrity and provide for accurate record keeping. 14

SCE has also undertaken several projects targeting specific emergent issues. 15

Underground structure inspection and remediation focusing on structural integrity of 16

underground assets, including assets that had previously not required inspection under G.O. 17

165: These structures are primarily vaults and manholes without equipment. This program 18

will be ongoing during the 2015-2017 period. This program is discussed in more detail in 19

section II.A.3. 20

Overhead conductor program to evaluate the entire overhead distribution system with a focus 21

on proactively identify potential splice, connector and wire failures under certain operational, 22

environmental, and mechanical conditions. SCE will be identifying, prioritizing, and 23

remediating identified conditions as part of a programmatic effort to reduce potential wire 24

down incidents on SCE’s distribution system. 25

Big Creek corridor project to more proactively manage vegetation in proximity to the high 26

voltage lines in the Big Creek area. SCE, through a collaborative effort with the United 27

Continued from the previous page 2 SCE’s DIMP was used as the model for G.O. 95, Rule 18A, which was enacted in D.12-01-032 as part of the Fire Safety

Rulemaking, R.08-11-005.

3 See D.09-08-029, new G.O. 95 Rule 18 Part B, effective August 20, 2009.

4

States Forrest Service, is undertaking new vegetation management activities along the right 1

of way for SCE’s 220 kV lines in the Big Creek area to comply with new vegetation 2

management standards. 3

Pole loading assessments and associated remediation to comply with G.O. 95 safety 4

standards and heightened internal standards: Proliferation of third-party attachments, new 5

standards, and newer technology indicate the need to assess all the poles on SCE’s system for 6

compliance with pole loading requirements and to perform the appropriate remediation, as 7

necessary. SCE has been evaluating the issue since 2011, and will begin a formal Pole 8

Loading Inspection Program in 2014, which is expected to continue through 2025. Further 9

details about this program can be found in Mr. Trainor’s testimony in Exhibit SCE-03 Vol. 10

06, Part 2. 11

B. Forecast O&M Expenses and Capital Expenditures 12

1. O&M Expenses 13

Table I-1 2015 O&M Expense Forecast

(100% CPUC Jurisdictional Constant 2012 $ 000) Account Activity 2015

583.120 Inspection Of Distribution Overhead And Underground Lines And Equipment 23,227$

593.120 Planned Maintenance Of Distribution Overhead And Underground Lines And Equipment; Vegetation Management; And Apparatus Inspection And Maintenance 138,846$

594.120 Distribution Overhead And Underground Breakdown Maintenance 27,454$

Total O&M Expenses $189,527

5

2. Capital Expenditures 1

Table I-2 2013-2017 Capital Expenditure Forecasts

(Total Company Nominal $000)

Activity 2013 2014 2015 2016 2017 TotalPreventive Maintenance 156,942 145,140 148,222 151,536 155,631 757,470 Breakdown Maintenance 102,700 105,256 107,491 109,895 112,864 538,207 Pole Replacement 216,095 292,535 141,946 144,930 148,760 944,266 Joint Pole Credits (20,020) (25,207) (15,397) (15,733) (16,155) (92,512) Wood Pole Disposal 2,503 3,152 1,925 1,968 2,021 11,570 Underground Structure Replac 53,643 70,687 72,188 73,802 69,059 339,379 Idle Facility Removal 6,290 6,447 6,584 6,731 6,913 32,965

Total Expenditures 518,154$ 598,010$ 462,959$ 473,128$ 479,093$ 2,531,344$

6

C. Comparison of 2012 GRC Request, Authorized, and Recorded 1

1. O&M Expenses 2

Figure I-1 Distribution Inspection and Maintenance Program O&M Expense Summary – Authorized vs. Recorded

(100% CPUC Jurisdictional Constant 2012 $000)

($0.9)

$2.1 $2.6 $8.5

-

25

50

75

100

125

150

175

200

2012 Authorized Inspections Pole Assessments Maintenance Breakdown 2012 Recorded

Inspections Maintenance Breakdown Diff from Auth

$158.5

$168.8

As shown in Figure I-1, in 2012 SCE spent approximately 106 percent of what was 3

authorized within the expense categories included in this exhibit. Distribution inspection, maintenance, 4

and breakdown expenses were all higher than authorized. 5

7

2. Capital Expenditures 1

Figure I-2 Distribution Inspection and Maintenance Program

Capital Expenditures Summary – Authorized vs. Recorded (CPUC-Jurisdictional Constant 2012 $millions)

$15

($21) ($13) ($4)

$4

-

50

100

150

200

250

300

350

400

450

2012 Authorized D Prev Mtce D Bkdwn Mtce Pole Repl UG Structure Repl Misc 2012 Recorded

D Prev Mtce D Bkdwn Mtce Pole Repl UG Structure Repl Misc Diff from Auth

$378

$358

As shown in Figure I-2, and despite the late 2012 GRC Decision, in 2012, SCE spent 2

almost 95 percent of what was authorized within the capital expenditure categories included in this 3

exhibit. Distribution preventive maintenance expenditures were higher than authorized, and distribution 4

breakdown maintenance lower. Between these two work categories, SCE recorded $6 million less than 5

authorized as fewer equipment failures or emergency replacements were required. SCE performed 6

fewer intrusive pole inspections in 2012 because of the delay in receiving the 2012 GRC decision, which 7

also translated to fewer pole replacements in 2012.4 SCE also spent less than authorized on 8

4 In 2013 the number of intrusive inspections being performed has been increased to allow SCE to get back on track with

its 10-year levelization plan.

8

Underground Structure replacements due to uncertainty around available funding, which delayed the 1

ramp-up of that program.2

9

II. 1

WORK DESCRIPTIONS, RECORDED COSTS AND TEST YEAR FORECASTS 2

A. Distribution Equipment Inspection Expenses 3

This section describes the distribution system inspection and maintenance programs that incur 4

O&M expenses, and the associated costs, except for those incurred in programs targeting specific asset 5

classes like poles and underground structures. 6

1. Annual Patrols, Portion of FERC Account 583.120 7

Annual patrols include activities related to inspecting the distribution electrical system in 8

accordance with G.O. 165 and DIMP. Inspectors conduct annual patrols of overhead facilities using a 9

geographical grid based approach. When conducting annual patrols the inspectors also assess visible 10

portions of distribution underground systems including pad-mounted transformers, BURD enclosures, 11

and vault lids. Identified maintenance items discovered during inspections are either repaired by the 12

inspector or prioritized for follow up corrective action in accordance with SCE’s DIMP program. 13

Annual patrols are conducted by SCE’s Electrical System Inspectors (ESI’s) and contract inspectors. 14

Table II-3 Annual Patrols, Portion of FERC Account 583.120

Recorded and Adjusted 2008-2012/Forecast 2013-2015 (100% CPUC Jurisdictional Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015Labor $950 $612 $439 $563 $653 $653 $653 $653Non-Labor $353 $565 $657 $479 $370 $370 $370 $370 Total $1,303 $1,177 $1,096 $1,042 $1,023 $1,023 $1,023 $1,023

Grids 20,161 20,140 20,237 20,245 20,413 20,413 20,413 20,413 Cost per Grid $65 $58 $54 $51 $50 $50 $50 $50

Ratio of Labor to Total 73% 52% 40% 54% 64% 64% 64% 64%

Basis of Forecast: LYRBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

a) Cost Forecast 15

Labor expenses included in this category are for inspectors performing the annual 16

patrols. Non-labor expenses include contract inspector costs, vehicles, and other allocated charges. 17

Table II-3 shows the recorded costs, number of grids patrolled, and the unit cost 18

(recorded cost divided by grid count) for the 2008-2012 period. SCE’s territory is comprised of more 19

10

than 20 thousand grids, or geographical areas, which contain overhead and underground facilities on 1

SCE’s distribution electrical system. The number of grids can increase over time as electrical facilities 2

are added to the distribution system. As seen in the table, the unit costs have stabilized since 2009 3

following the launch of SCE’s new DIMP. In accordance with D.89-12-057, SCE forecasts 2015 test 4

year unit costs to be equal to 2012 recorded unit costs, which is lower than the four-year average for 5

2009-2012 of $53 per grid. The forecast for the number of grids to be patrolled is based on the current 6

number of grids, which is the same as the number of grids inspected in 2012. Going forward annual 7

patrols are expected to remain the same as no changes are currently being contemplated for this 8

program. 9

The total expenses in this category were forecast based on last year recorded 10

expenses. The total was split between labor and non-labor based on the 2012 recorded ratio of labor to 11

non-labor. The forecasts for 2013-2015 are also shown in Table II-3. 12

2. Overhead Detailed Inspection Program, Portion of FERC Account 583.120 13

The Overhead Detailed Inspection (ODI) program involves activities related to inspecting 14

SCE’s overhead distribution electrical system in accordance with G.O. 165 and DIMP. The purpose of 15

the ODI inspection is to perform a close proximity evaluation of SCE’s overhead electrical facilities 16

such as poles, capacitors, switches, transformers, conductors, guy wires, and risers to: 17

identify hazardous conditions, or nonconformances with G.O. 95 that require 18

corrective action. Examples could include leaking transformers, broken or damaged 19

equipment, inadequate clearances, deteriorated cross arms, missing or damaged high 20

voltage signs, etc.; 21

determine what the corrective action should be and prioritize follow up corrective 22

actions based on safety and reliability in accordance with DIMP; 23

perform minor repairs at the public level while at the location. For example, 24

inspectors commonly perform repairs such as replacing damaged ground molding at 25

the public level, installing guy guards, removing unauthorized attachments (if 26

appropriate), installing pole tags, etc.; 27

document inspection findings, including pending and completed repairs. 28

GO 165 requires detailed inspection of overhead distribution equipment every five years. 29

ODI inspections are conducted by SCE’s Electrical System Inspectors and contract inspectors. The 30

expenses incurred by this program are recorded in FERC Account 583.120. 31

11

Table II-4 Overhead Detailed Inspection, Portion of 583.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $2,000 $2,425 $2,591 $2,746 $2,904 $4,372 $4,422 $4,295Non-Labor $1,652 $1,617 $1,272 $1,333 $2,335 $3,517 $3,558 $3,455 Total $3,652 $4,042 $3,863 $4,079 $5,239 $7,889 $7,980 $7,750

Inspections 230,589 293,328 275,911 278,588 284,870 275,512 278,715 270,682 Cost per Inspection ($) $16 $14 $14 $15 $18 $29 $29 $29


Basis of Forecast: Forecast Inspections * LYR cost per inspection + Increment for difficult to access structuresBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

a) Cost Forecast 1

Labor expenses included in Table II-4 are the costs incurred by SCE inspectors 2

performing the inspections. Non-labor expenses include contract inspector labor costs, materials, 3

vehicles, and other allocated charges. Table II-4 shows the historical recorded costs for 2008-2012 4

along with the number of inspections, and the corresponding cost per inspection (recorded cost divided 5

by inspection count). Unit costs have been relatively stable from 2008 to 2011. In 2012, the cost per 6

inspection increased due to changes in work methods and accounting practices. Prior to 2012, the ODI 7

supervisors’ labor and vehicle costs were recorded in an account that was allocated to various activities. 8

Starting in 2012, these costs are being charged directly to the overhead detail inspection account. 9

In addition, inspectors began performing inspections in remote areas by 10

helicopter. This activity began in 2011, and 2012 reflects the first full year of this activity. These 11

changes increased unit costs from an average of $15 per inspection from 2008-2011 to $18 per 12

inspection in 2012. Since these practices will continue in the future, SCE utilized the 2012 recorded 13

cost per inspection as the basis to forecast test year expenses. Additionally, the test year cost forecast 14

will increase above 2012 recorded due to a program enhancement focused on gaining access to 15

obstructed or difficult to access structures. The majority of these poles are in customers’ backyards, 16

often behind locked gates or with access to the pole obstructed. Beginning in 2013, SCE is requiring 17

inspectors to gain access to every pole in order to complete the detailed inspection rather than 18

12

completing inspections from a distance using binoculars or similar equipment. Difficult to access poles 1

often involve making contact with the property owners and require inspectors to make multiple trips in 2

order to complete the inspection. In extreme cases SCE could be required to pursue legal action in order 3

to gain access to the pole. 4

In 2012, inspectors could perform ODI on approximately 50 poles per day. For 5

the difficult to access poles, SCE expects inspectors to complete 20 poles per day, while maintaining 6

their productivity for accessible poles at 50 per day. The inclusion of difficult to access poles will 7

increase the average unit cost to $29 per pole.5 8

The total forecasts for this activity in 2013-2015 are forecast by multiplying the 9

forecast unit cost per inspection by the forecast number of inspections. The labor and non-labor costs 10

were forecast based on the 2012 labor to non-labor ratio. The 2015 forecast expense shown is based on 11

the average of forecast expense for 2015-17. The summary of the forecasts are also included in Table 12

II-4. 13

3. Underground Detailed Inspections (UDI), Portion of FERC Account 583.120 14

This program involves activities for inspecting SCE’s underground distribution electrical 15

system in accordance with G.O. 165 and DIMP. The purpose of UDI is to provide close proximity 16

examination of underground and pad mounted distribution equipment as mandated by G.O. 165. 17

Inspectors assess subsurface and pad mounted equipment including enclosures, switches, transformers, 18

visible cables, and associated components to identify safety hazards and nonconformances with G.O. 19

128. Similar to the ODI program, the UDI inspectors document safety and reliability hazards and 20

prioritize corrective actions in accordance with SCE’s DIMP. When possible, they perform routine 21

maintenance or make repairs during the course of the inspection. UDI activities are generally performed 22

by a crew consisting of a lineman and a groundman, both of which have received specialized training to 23

work in underground vaults and in proximity to energized high voltage equipment. 24

5 See Workpaper entitled “Overhead Detail Inspection – Difficult to Access Pole Forecast.”

13

Table II-5 Underground Detail Inspections, Portion of FERC Account 583.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $1,591 $1,438 $2,320 $3,210 $4,430 $4,257 $4,042 $4,389Non-Labor $736 $662 $1,051 $2,270 $1,046 $1,005 $954 $1,036 Total $2,327 $2,100 $3,371 $5,480 $5,476 $5,262 $4,996 $5,425

Inspections 154,313 133,214 142,265 184,387 174,424 167,613 159,133 172,819 Cost per Inspection $15 $16 $24 $30 $31 $31 $31 $31


Basis of Forecast: Forecast Inspections * LYR Cost per InspectionBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

a) Cost Forecast 1

Labor expenses in this work category are driven by the inspectors performing the 2

underground detail inspections. Non-labor expenses include materials, vehicle costs, and other allocated 3

charges. Table II-5 shows the recorded expenses and inspection counts from 2008-2012, along with the 4

corresponding cost per inspection (recorded cost divided by inspection count). 2008 and 2009 unit costs 5

are similar, but the cost-per-inspection increased in 2010 due to a mid-year change in the field tool used 6

to record UDI activities that altered how inspectors account for their time between inspections and 7

repairs. The cost per inspection increase in 2011 is due to a full year of the aforementioned accounting 8

change and the inclusion of more underground structures in the UDI program as discussed below. The 9

cost-per-inspection remained stable in 2012. 10

SCE began including structures without equipment in the UDI program in 2010, 11

going from inspecting a few structures to over 8,000 structures in 2011, and approximately 20,000 12

structures in 2012. All of these structures will continue to be included in the routine inspections 13

performed under the UDI program going forward. For subsurface structures without equipment, such as 14

vaults and manholes, the cost per inspection is higher than the cost for other structures due to the time 15

required to perform the inspection. Vaults and manholes require a minimum of two employees to 16

conduct the inspection, are often filled with water that must be pumped out, require the inspectors to test 17

and continually monitor air conditions within the enclosure before entering the structure, and require 18

traffic control. The inspection of underground structures without equipment is being performed in 19

14

addition to the inspections conducted in accordance with G.O. 165. Since these underground structure 1

inspections will continue in the future as part of the ongoing UDI program, SCE utilized the 2012 2

recorded cost per inspection as the forecast unit cost for 2013-2015. 3

The inspection count forecast for 2013-2015 is derived from the number of 4

inspections that will be due each year, as required by G.O. 165 and SCE’s DIMP.6 The total forecasts 5

for this activity in 2013-2015 are calculated by multiplying the forecast unit cost per inspection by the 6

number of inspections required to be performed. The labor and non-labor costs were forecast based on 7

the recorded 2012 labor to non-labor ratio. The 2015 forecast expense shown is based on the average of 8

forecast expense for 2015-17. The summary of the forecasts are also included in Table II-5. 9

B. Distribution Maintenance 10

Distribution maintenance includes the cost of labor, materials, and other expenses incurred when 11

repairing or replacing items identified through inspection programs, as part of the normal course of 12

business, and emergency or breakdown activities. It does not include costs related to failures that occur 13

during a storm or from a claim, such as a vehicle damaging SCE poles. Inspection programs driving 14

these activities include overhead detail inspections, underground detail inspections, and annual patrols 15

described above. In addition, when field crews observe problems while performing other work or 16

responding to trouble calls, they perform additional maintenance activities that record to these accounts. 17

Maintenance activities can include the repair, replacement, or relocation of facilities; replacement of 18

signs and cross-arms; repair or relocation of conduit; repair or replacement of conductor or cable, 19

equipment, or pole fixtures; re-fusing line cutouts; repairing grounds, and replacing transformers. 20

In accordance with DIMP, inspectors identify and prioritize deteriorated components or 21

conditions found during inspections for follow up repair or replacement. Every item is evaluated based 22

on the specifics for that condition, taking into account several factors, such as the type of facility or 23

equipment, loading, location, accessibility, climate, and direct or potential impact on safety or reliability. 24

These maintenance activities are performed by electrical crew foremen, linemen, groundmen, and 25

contractor crews who work for SCE’s Distribution Construction and Maintenance organization. Costs 26

associated with maintenance activities are either recorded as expense (O&M), or capital, in accordance 27

with established accounting rules. In simplistic terms, repairs or minor replacements are generally 28

6 Please see Workpaper entitled “Underground Detail Inspections.”

15

recorded to expense, and the replacement of equipment or facilities are recorded to capital. Maintenance 1

activities for repairs (O&M) and replacements (capital) are forecast separately in the sections below. 2

1. Cost Forecast – Maintenance Expense (O&M), Portions of FERC Accounts 593.120 3

and 594.120 4

Labor costs are driven by the work performed by SCE field personnel in this work 5

activity. Non-labor costs are driven by the contract crew charges, materials, vehicles costs, and other 6

allocated costs. Preventive maintenance expenses for distribution assets driven by inspections or field 7

observations are recorded in 593.120; breakdown maintenance expenses are recorded in 594.120. Both 8

preventive and breakdown maintenance are driven by the age and condition of the distribution electrical 9

system, can be similar in nature, and are completed by the same personnel. Hence, they are being 10

forecast together. The historical expenses incurred in this activity are shown in Table II-6. 11

The total costs recorded in this category have increased from 2008 to 2009 due to 12

increasing maintenance work resulting from the second year of DIMP, and an increase in emergency or 13

breakdown maintenance activity associated with SCE’s aging electrical system. Under DIMP, items can 14

be prioritized to be repaired within 24 months. Some of the items prioritized for repair in 2008 were not 15

due until 2009, so 2009 was the first full year of maintenance under the new DIMP. From 2009 to 2010 16

costs decreased due to a reduction in emergency and breakdown activity. Since 2010, the costs in this 17

activity have continued to increase each year as both planned and emergency maintenance work has 18

increased with the expanding and aging infrastructure. Going forward, SCE expects to continue to 19

perform the same types of activities in this area, with continuing upward pressure driven by the 20

expanding and aging infrastructure. Given this upward trend, in accordance with D. 89-12-057, SCE 21

forecasts expenses in these activities to be equal to 2012 recorded expenses in constant 2012 dollars. 22

Since work levels, contractor utilization, and other charges are also expected to follow 23

the same trends as in 2012, SCE has estimated the labor and non-labor expenses in 2013 to 2015 using 24

the 2012 labor to non-labor ratio. The forecasts are also summarized in Table II-6. 25

16

Table II-6 Distribution Maintenance Expenses, Portion of 593.120 and 594.120

Recorded and Adjusted 2008-2012 / Forecast 2013-2015 (100% CPUC Jurisdictional Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015594.120

Labor $8,260 $10,129 $8,135 $11,334 $13,949 $13,949 $13,949 $13,949Non-Labor $6,744 $10,851 $7,941 $11,892 $13,505 $13,505 $13,505 $13,505

593.120Labor $14,554 $20,570 $19,277 $20,498 $21,376 $21,376 $21,376 $21,376Non-Labor $20,257 $28,831 $30,390 $32,023 $29,503 $29,503 $29,503 $29,503

Total $49,815 $70,381 $65,743 $75,747 $78,333 $78,333 $78,333 $78,333

Labor $22,814 $30,699 $27,412 $31,832 $35,325 $35,325 $35,325 $35,325Non-Labor $27,001 $39,682 $38,331 $43,915 $43,008 $43,008 $43,008 $43,008



Recorded Forecast

2. Cost Forecast – Distribution Maintenance Capital Expenditures 1

As discussed earlier, the costs recorded in this account are driven by the work performed 2

by SCE field personnel and contract crews, materials, equipment, vehicles costs, and other allocated 3

costs. Like maintenance repairs, both preventive and breakdown maintenance are driven by the age and 4

condition of the distribution electrical system, can be similar in nature, and are completed by the same 5

personnel. Therefore, SCE forecasts these two capital expenditure categories together. The historical 6

expenditures incurred in this activity are shown in Table II-6. 7

The total costs recorded in this category decreased from 2008 to 2009, primarily due to a 8

decline in breakdown replacement along with a decrease in emergency replacements. From 2009 to 9

2012 expenditures have been steadily increasing due to the ongoing DIMP and the continually 10

expanding and aging infrastructure. Going forward, SCE expects to continue to perform the same types 11

of activities in this area, with continuing upward pressure driven by the expanding and aging 12

infrastructure. Due to this upward trend, and in accordance with D. 89-12-057, SCE forecasts 13

17

expenditures in this activity to be equal to 2012 recorded expenditures in constant 2012 dollars. See 1

Figure II-3. 2

Additionally, in 2013 SCE is performing additional maintenance activities that have been 3

identified within the local Regions and Districts. These projects involve maintenance activities driven 4

by safety, operations, or reliability issues that have been identified by these local jurisdictions. Projects 5

are selected based on known local conditions, and although these projects by themselves would not 6

typically rise to the system level today, they could ultimately become larger issues in the future if not 7

corrected. Examples can include projects to re-conductor and rebuild lines to critical assets such as 8

police, fire, and forest communications systems, create critical system ties, rebuild systems that have 9

performed poorly, and rebuild systems that caused multiple outages in small pockets of the system. 10

18

Figure II-3 Distribution Maintenance Capital Expenditures

Various WBS7 Recorded 2008-2012/Forecast 2013-2017

(100% CPUC-Jurisdictional $000)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 204,460 191,169 213,225 235,616 239,107 259,642 250,396 255,713 261,431 268,495

Constant 2012 $ 234,311 214,215 229,240 243,247 239,107 254,107 239,107 239,107 239,107 239,107

$-

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

Nominal $ Constant 2012 $

Forecast

In D. 12-11-051, SCE’s 2012 GRC Final Decision, the Commission asked SCE to 1

include with any request for additional funding of Asset Based Preventative Maintenance, a description 2

of how many replacements were performed annually after 2010, the number of new replacements 3

identified, and the number, priority, and estimated cost of backlog replacement projects, if any. 4

In the 2012 GRC, SCE presented the counts of overhead transformers, underground 5

transformers, overhead conductors, and underground conductors replaced under this activity as a proxy 6

for all work performed in this category. For example, when SCE replaces a mile of cable, it could 7

include other equipment types such as switches, capacitors, regulators, pull boxes, conduit, fuses, and 8

sump pumps, but for the purpose of that analysis SCE only counted the mile of cable. In the previous 9

GRC, these counts were used to forecast the volume of work and associated costs for the entire activity. 10

7 WBS elements CET-PD-BM-BD, CET-PD-IR-EP, CET-PD-IR-NP, CET-PD-IR-PM, and CET-PD-BM-EP.

19

In practice, instead of asset counts, SCE utilizes notifications to track preventative 1

maintenance work identified through inspections and field observations. Notifications generated by 2

inspection programs are assigned a priority in accordance with SCE’s DIMP program. The actual assets 3

replaced under any notification could encompass more than these four equipment types. Therefore, SCE 4

is unable to provide a complete listing of the information as requested. 5

The activity termed “Asset Based Preventive Maintenance” in the 2012 GRC, is the same 6

activity referred to as “Preventive Maintenance” in this GRC. SCE has not created its forecast using an 7

asset based replacement methodology in this GRC. Instead, SCE is using its last year recorded costs to 8

forecast its future costs. 9

SCE does not currently have a backlog of preventive maintenance replacement projects. 10

C. Vegetation Management, Portion of FERC Account 593.120 11

Vegetation management includes all of the expenses associated with tree trimming, tree removal, 12

and weed abatement in proximity to distribution high voltage lines. It also includes costs incurred in 13

planting different species of trees as replacements and in handling preventive soil treatment. The 14

majority of costs in this area are from a fixed price contract with SCE’s tree trimming contractor, which 15

requires them to maintain compliance for the approximately 1.4 million trees throughout SCE’s territory 16

that exist in proximity to energized conductors. Annual tree trimming costs increased at the end of 2009 17

as a result of the Commission’s change in the vegetation clearance requirements in High Fire areas, 18

which became effective August 20, 2009.8 The 2012 GRC authorized recovery of these increased costs. 19

GO 95 and Public Resources Code Sections 4292 and 4293 require SCE to manage vegetation 20

near its wires. SCE engages a contractor to trim and remove trees and weeds, as well as other activities, 21

to facilitate compliance with these requirements. All of the trees in inventory are inspected annually to 22

comply with the applicable requirements. During these inspections, any trees or vegetation that require 23

trimming to maintain the required distances from high voltage lines are scheduled for trimming or 24

removal. In addition, hazard trees, such as overhangs in high fire areas, dead, diseased or dying trees are 25

also identified for trimming or removal. In some cases it is necessary to trim trees more frequently to 26

meet the Commission’s requirements. For example, fast-growing species, or trees in areas designated as 27

high risk for wild fires may need more frequent trimming to meet the Commission standards. 28

8 See D.09-08-029 “Decision in Phase 1 – Measures to Reduce Fire Hazards in California Before the 2009 Fall Fire

Season.”

20

In addition to routine vegetation management, in this GRC, SCE is requesting funding for bark 1

beetle related vegetation management. As discussed in Exhibit SCE-10, Vol. 1, Part 2, in 2003 the 2

Commission authorized SCE to recover costs for Bark Beetle remediation work through Catastrophic 3

Event Memorandum Account (CEMA) filings. Since that time, SCE has been recording its O&M 4

expenses associated with the inspection and removal of dead, dying or diseased trees that may fall or 5

contact SCE’s electrical facilities as a result of the bark beetle emergency. 6

Since expenses related to bark beetle remediation have become more predictable, SCE has 7

determined that recovery through CEMA will no longer be necessary and is requesting on-going costs to 8

be included in base rates. If recovery of the bark beetle costs in this GRC application is adopted, SCE 9

will discontinue recording any bark beetle related costs into the Bark Beetle CEMA as of January 1, 10

2015. 11

1. Cost Forecast for Routine Vegetation Management 12

Labor expenses in this category are driven by the work performed by SCE arborists and 13

employees that manage the vegetation management program. Non-labor costs include contractor costs 14

and other allocated charges associated with the vegetation management program. As previously 15

discussed, costs increased in 2009 due to the Commission’s change in the vegetation clearance 16

requirements in High Fire areas. Costs peaked in 2010, and have since stabilized. SCE expects to 17

continue to perform the same level of activities in this area going forward. As a result, the forecast for 18

these expenses is based upon 2012 expenses, the last recorded year. See Table II-7. 19

Table II-7 Vegetation Management, Portion of 593.120

Recorded and Adjusted 2008-2012 / Forecast 2013-2015 (100% CPUC-Jurisdictional Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015Labor $2,180 $3,260 $5,519 $4,975 $4,285 $4,285 $4,285 $4,285Non-Labor $45,265 $47,212 $56,993 $55,310 $53,450 $53,450 $53,450 $53,450 Total $47,445 $50,472 $62,512 $60,285 $57,735 $57,735 $57,735 $57,735



Recorded Forecast

21

2. Cost Forecast for Bark Beetle Remediation 1

Bark beetle activities have declined since the inception of this program as the number of 2

affected trees have been controlled and stabilized. SCE expects to continue to perform the same level of 3

activities in this area going forward. In accordance with D. 89-12-057, SCE is basing its forecast on 4

2012 expenses, the last recorded year. See Table II-8. 5

Table II-8 Bark Beetle Related Vegetation Management, Portion of 593.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $305 $276 $260 $206 $181 $181 $181 $181Non-Labor $8,878 $5,227 $4,115 $2,701 $2,089 $2,089 $2,089 $2,089 Total $9,183 $5,503 $4,375 $2,907 $2,270 $2,270 $2,270 $2,270



Recorded Forecast

3. Big Creek Corridor 6

On December 21, 2011, NERC submitted a petition for FERC approval of Reliability 7

Standard FAC-003-2 (Transmission Vegetation Management), along with new corresponding Violation 8

Risk Factors and Violation Severity Levels for tree encroachments. The new transmission vegetation 9

management standard, effective July 1, 2013, includes more prescriptive standards for vegetation 10

management programs and more stringent penalty provisions. In conjunction with this new standard 11

and in an effort to more proactively manage vegetation in the Big Creek area, SCE is undertaking new 12

vegetation management activities in the Big Creek (BC) Corridor to comply with these new standards. 13

The BC Corridor encompasses more than 100 miles of high voltage lines in the BC 14

hydroelectric system, a system that dates back to the early 1900s. The BC system is located in the Sierra 15

Nevada Mountains, often within land located in the National Forest and under jurisdiction of the United 16

States Forrest Service (USFS). The right of way for SCE’s 220 kV lines in the mountainous region of 17

the BC corridor traverse areas of steep and rugged terrain, bordered by large trees. For years SCE has 18

been trimming trees along the Big Creek Corridor, but a lack of collaboration with the USFS limited 19

22

SCE’s ability to manage the right of way (ROW) and vegetation along the BC Corridor. During this 1

time, removals have been difficult, and often performed only under emergency conditions. In 2010, an 2

incident occurred where a tree fell into the BC line from outside the right of way (ROW). Since that 3

time, SCE has been working with the USFS to perform more work in the BC area. Today, the USFS is 4

working with SCE in a collaborative manner and they are supportive of SCE’s efforts to more 5

proactively manage vegetation in the BC area. As a result, SCE is launching an initial effort this 6

September to more proactively manage the BC corridor and vegetation in proximity to the lines. Going 7

forward, SCE plans to incorporate the information and best practices learned during this initial effort to 8

help better manage and remediate what is identified as the high risk areas along the BC ROW. These 9

activities are necessary to comply with the requirement to “manage vegetation to prevent 10

encroachments,” including fall-ins, as required by NERC FAC-003-2. 11

a) Cost Forecast 12

The cost forecast for this program involves the removal of small trees and large 13

shrubbery underneath the high voltage lines, the removal of large trees adjacent to the lines, and 14

associated work. The process for removing a tree within the transmission ROW in Big Creek consists of 15

four steps: felling (cutting the tree down), buck/slash (cutting off all of the limbs), chip/haul (chipping of 16

limbs), and log disposal. SCE will also perform brushing, mowing, grading, and herbicide activities on 17

the ROW. In addition to these activities, cost estimates also take into account environmental activities 18

due to the sensitive habitat and potential for archeological sites in the BC area. Activities will be 19

prioritized to remediate the highest risk areas first. The cost estimates are based on contract costs from 20

SCE’s bark beetle program, which involved similar activities.9 See Table II-9. 21

9 See Workpaper entitled “Big Creek Corridor NERC FAC-003-2.”

23

Table II-9 Big Creek Expenses, Portion of 571.150

Recorded and Adjusted 2008-2012/Forecast 2013-2015 (Total Company Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015Labor $0 $0 $0 $0 $0 $0 $0 $0Non-Labor $0 $0 $0 $0 $0 $1,530 $2,158 $2,158 Total $0 $0 $0 $0 $0 $1,530 $2,158 $2,158

Ratio of Labor to Total 0% 0% 0%

Basis of Forecast: Contract rates * forecast activitiesBasis of Labor/Non-Labor Split: Forecast

Recorded Forecast

D. Miscellaneous Inspection and Maintenance 1

1. Distribution Transformer Maintenance Expenses, Portion of FERC Account 2

593.120 3

When distribution transformers fail in service, a small portion of them can be refurbished 4

and returned to service. This account records the cost of labor, materials used and expenses incurred in 5

the repair of distribution transformers performed by specialized crews in SCE’s Shop Services and 6

Instrumentation Division (SSID). 7

Table II-10 Distribution Transformer Maintenance Expenses, Portion of 593.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $1,580 $848 $1,155 $1,080 $1,048 $1,143 $1,143 $1,143Non-Labor $772 $437 $557 $956 $468 $638 $638 $638 Total $2,352 $1,285 $1,712 $2,036 $1,516 $1,781 $1,781 $1,781


Basis of Forecast: 5YABasis of Labor/Non-Labor Split: 5YA

Recorded Forecast

24

a) Cost Forecast 1

The expenses recorded in this account are a function of the number of 2

transformers that can be refurbished in a given year. Since these costs have fluctuated from 2008 to 3

2012, SCE utilized used a five-year average as the basis for its test year forecast. The labor and non-4

labor split is based on the five-year average ratio of labor to non-labor. See Table II-10 above. 5

2. Graffiti Removal Expenses, Portion of 593.120 6

Graffiti removal involves the painting of equipment and structures in conjunction with 7

SCE’s graffiti abatement program. Graffiti abatement is an ongoing issue among the cities and counties 8

served by SCE. Several communities have enacted, or are considering, graffiti abatement ordinances for 9

utility equipment and structures, often with stringent requirements and penalties. Since 2007 SCE has 10

been aggressively confronting this growing issue with help from its Local Governmental Affairs 11

organization, and by contracting for service territory wide graffiti abatement services. 12

a) Cost Forecast 13

SCE’s graffiti abatement contractor provides graffiti abatement services 14

throughout SCE’s 50,000 square-mile service territory under a fixed price agreement, which will be 15

renegotiated before the end of 2013. New rates will become effective in 2014. Ongoing expenses are 16

expected to track labor and non-labor escalation rates. Therefore the test year forecast is based on the 17

constant dollar recorded costs shown in 2012 (Table II-11). 18

Table II-11 Remove Graffiti from Distribution Equipment

Portion of FERC Account 593.120 Recorded and Adjusted 2008-2012/Forecast 2013-2015

(100% CPUC-Jurisdictional Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015Labor $5 $9 $21 $35 $70 $70 $70 $70Non-Labor $599 $544 $552 $591 $571 $571 $571 $571 Total $604 $553 $573 $626 $641 $641 $641 $641



Recorded Forecast

25

3. Distribution Apparatus Inspection & Maintenance Expenses, Portion of 593.120 1

Distribution Apparatus includes the cost associated with the inspection and testing of all 2

overhead and underground distribution apparatus, such as fixed and automatic capacitors, network 3

protectors, fault interrupters, and automatic re-closing switches used for line protection and 4

sectionalizing, as well as the resulting maintenance performed by the apparatus crews. 5

Two- and three-person apparatus crews with specialized training perform these 6

inspections using technical diagnostic equipment. Apparatus equipment is predominantly found on the 7

overhead distribution system, and is inspected on a five-year cycle consistent with GO 165. Work 8

performed by apparatus crews varies from year to year according to this inspection cycle, and type of 9

work performed, which can cause costs to vary between repair expenses and capital expenditures. The 10

frequency and cost of repairs, and the portion of repairs that are maintenance expenses versus capital 11

expenditures, vary from year-to-year. 12

Table II-12 Distribution Apparatus Inspection & Maintenance Expenses, Portion of 593.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $2,711 $3,320 $3,200 $2,970 $3,241 $3,087 $3,087 $3,087Non-Labor $1,351 $2,051 $1,830 $1,306 $760 $1,460 $1,460 $1,460 Total $4,062 $5,371 $5,030 $4,276 $4,001 $4,547 $4,547 $4,547


Basis of Forecast: 5YABasis of Labor/Non-Labor Split: 5YA

Recorded Forecast

a) Cost Forecast 13

As described above, the cost for distribution apparatus inspection and 14

maintenance expenses fluctuate from year-to-year due to the number of inspections performed, 15

complexity and type of maintenance activity performed, and number of repairs versus replacements. As 16

a result of equipment inspections, crews will identify repairs that are either capital or expense, 17

depending upon the extent of the work. The type of repair, capital versus expense, and the complexity 18

of the expense repairs results in fluctuations in the historical expenses for this activity. For the test year 19

26

forecast SCE utilized the five-year average of labor and non-labor costs recorded for distribution 1

apparatus maintenance (Table II-12). 2

Labor expenses in this category include the costs incurred by SCE for the 3

distribution apparatus management, supervisors, and the apparatus crews. Non-labor expenses include 4

material costs, vehicle costs, and other allocated costs. 5

4. Removal of Idle Facilities Capital Expenditures 6

SCE removes idle assets that are no longer “used or useful,” typically because a customer 7

has left a facility that therefore no longer requires electrical service. SCE dismantles these assets and 8

removes them from rate base. Figure II-4 shows 2008-2012 recorded and 2013-2017 forecast 9

expenditures for the removal of idle facilities. 10

a) Cost Forecast 11

Expenditures in this activity increased from 2008 to 2009 due to a distribution 12

transformer bank replacement program that was undertaken in 2009. Expenditures remained at a high 13

level through 2010 as the transformer bank replacement program continued. Under this program a 14

transformer bank that was no longer serving customer load could be removed as an idle facility, instead 15

of being replaced, if there was no foreseeable use for those facilities in the near future. With the 16

completion of this program, idle facility removal expenditures reduced to more normal levels in 2011 17

and remained steady in 2012. Going forward the level of activity in this account is expected to continue 18

to remain steady as SCE does not anticipate any new programs, such as the distribution transformer 19

bank replacement program, that would impact this account. As a result, SCE expects the volume of 20

work in this activity to remain at 2011-2012 levels, and therefore SCE utilized recorded 2012 21

expenditures as the basis for its 2013-2017 forecasts. 22

27

Figure II-4 Removal of Idle Facilities

WBS Element CET-PD-CR-IF Recorded 2008-2012/Forecast 2013-2017

(100% CPUC-Jurisdictional Capital Expenditures $000)

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 4,454 8,751 9,185 6,317 6,156 6,290 6,447 6,584 6,731 6,913

Constant 2012 $ 5,104 9,806 9,875 6,521 6,156 6,156 6,156 6,156 6,156 6,156

$-

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

Nominal $ Constant 2012 $

E. Underground Structure Rehabilitation Program 1

Utilities construct underground concrete vaults to house energized equipment including switches, 2

transformers, and cable splices which may run under streets and other surface structures. Like vaults, 3

manholes are underground concrete structures, but they are smaller and typically contain no equipment, 4

only spliced cable. As these underground vault and manhole structures (hereafter “structures”) 5

deteriorate they need to be repaired or replaced. G.O. 165 requires periodic inspections of underground 6

equipment. Additionally, SCE has underground structures with no equipment that were not included in 7

SCE’s historical G.O. 165 distribution inspection and maintenance program. In 2010, SCE began 8

inspecting underground structures without equipment. By the end of 2012, SCE had inspected nearly 9

16,000 additional vaults and manholes. Going forward, all underground structures are included in 10

28

SCE’s routine inspection programs, irrespective of whether they contain equipment or not.10 This has 1

also led to an increase in the number of underground structures identified for repair and replacement, the 2

costs of which are included in this section. 3

This program focuses on the detailed field assessment, and the resulting repair or replacement of 4

underground structures. During underground detailed inspections, SCE inspectors determine whether 5

deterioration of the underground structure warrants a follow-up field investigation. This follow-up field 6

investigation is performed by a structural engineer and the results are used to determine whether the 7

underground structure needs to be repaired or replaced. 8

The number of underground structures forecast to be repaired and replaced each year is 9

determined by the number of structures to be inspected, the expected percentage of inspected structures 10

found to be deteriorated, and the expected percentage of deteriorated structures determined to require 11

replacement as a result of the follow-up field investigations. 12

Table II-13 summarizes the assumptions used to forecast vault repairs and replacements. 13

Historically, 7.76 percent of vaults inspected have been found to be deteriorated. SCE expects this rate 14

to decline to four percent as vaults are re-inspected after the current three-year inspection cycle. Of the 15

vaults identified as deteriorated, 32 percent undergo field investigations in the same year as the initial 16

inspection, while the remainder is scheduled for field investigations in the following year. Historically, 17

39 percent of field investigations in any given year result in vault replacements, and 61 percent result in 18

vault repairs. Additionally, 24 percent of the vaults identified for replacement will require shoring to 19

stabilize the structure until it can be replaced.11 20

10 See Section II.A.3 for a discussion of costs related to SCE’s underground detailed inspection program.

11 See Workpaper entitled “Underground Structure Rehabilitation Program Historical Analysis.”

29

Table II-13 Vault Inspection, Repair and Replacement Forecast Summary

2013 2014 2015 2016 2017

Vault UDI 6,787 7,094 8,847 6,312 6,597

% failing 7.76% 7.76% 7.76% 4.00% 4.00%

Total failing 527 550 686 252 264

Field Investigations (FI)

Vaults failing UDI 527 550 686 252 264% undergoing same-year FI 32% 32% 32% 32% 32%

FI from current year 169 176 220 81 84

FI from previous year 519 358 374 466 171

Total FI completed 688 534 594 547 255

New Vault Replacements Identified

Vaults undergoing FI 688 534 594 547 255

% to be replaced 39% 39% 39% 39% 39%

Total to be replaced 268 208 232 213 99

Vault Replacements with Shoring

Vaults requiring replacement 268 208 232 213 99

% to be shored 24% 24% 24% 24% 24%

Total to be shored 64 50 56 51 24

Repairs Identified

Vaults undergoing FI 688 534 594 547 255

% to be repaird 61% 61% 61% 61% 61%

Total to be repaired 420 326 362 334 156

Table II-14 summarizes the assumptions used to forecast manholes repairs and replacements. 1

Historically, 5.2 percent of manholes inspected have been found to be deteriorated. As with vaults, SCE 2

expects this rate to decline after the current three-year inspection cycle. Of the manholes identified as 3

deteriorated, 20 percent undergo field investigations in the same year as the initial inspection, while the 4

remainder is scheduled for field investigations in the following year. For manholes, 6 percent of field 5

investigations in a given year result in a replacement and 94 percent result in a repair. 6

30

Table II-14 Manhole Inspection, Repair and Replacement Forecast Summary

2013 2014 2015 2016 2017

Manhole UDI 576 2,013 8,719 550 1,922

% failing 5.20% 5.20% 5.20% 2.00% 2.00%

Total failing 30 105 453 11 38

Field Investigations

Manholes failing UDI 30 105 453 11 38

% undergoing same-year FI 20% 20% 20% 20% 20%

FI from current year 6 21 91 2 8

FI from previous year 418 24 84 362 9

Total 424 45 175 364 17

New Replacements Identified

Field Investigations completed 424 45 175 364 17

% needing replacement 6% 6% 6% 6% 6%

Total needing replacement 25 3 11 22 1

Repairs Identified

Field Investigations completed 424 45 175 364 17

% needing repair 94% 94% 94% 94% 94%

Total to be repaired 399 42 165 342 16

The field investigations, repair, and replacement forecasts shown in Table II-13 and Table II-14 1

form the basis for the O&M and capital forecasts related to the underground structure remediation 2

program. Section II.E.1 describes the expenses associated with follow-up field investigations; Section 3

II.E.2 describes the expenses associated with underground structure repairs. Section II.E.3 shows the 4

capital expenditures associated with underground structure replacements. 5

1. Cost Forecast - Underground Structure Field Investigation Expenses, Portion of 6

FERC Account 583.120 7

Follow-up field investigation expenses include the non-labor costs of an SCE-approved 8

contractor who performs the investigation and the labor costs of SCE employees who provide access to 9

the structure (Table II-15). The labor costs are for SCE crews who perform the traffic control, test, and 10

monitor air quality levels within the structures, help ensure the safety of anyone entering the 11

underground structures and working in proximity to energized high voltage equipment, and secure the 12

31

structures upon departure. In late 2012, contract negotiations resulted in lower rates for field 1

investigations by contractors, which slightly reduced the cost per investigation from 2011 to 2012. The 2

cost per field investigation in 2013 reflects a full year of this reduced cost.12 The forecast count of field 3

investigations is calculated based on the number of underground detail inspections performed multiplied 4

by the historical rates of structures failing inspection (percentage found deteriorated), as shown in Table 5

II-13 and Table II-14. 6

Table II-15 Field Investigation Expenses, Portion of FERC Account 583.120

Recorded and Adjusted 2008-2012/Forecast 2013-2015 (100% CPUC-Jurisdictional Constant 2012 $000)

2008 2009 2010 2011 2012 2013 2014 2015Labor $0 $0 $0 $10 $200 $229 $119 $134Non-Labor $0 $0 $0 $46 $956 $1,097 $571 $642 Total $0 $0 $0 $56 $1,156 $1,326 $690 $776

Investigations - - 1 35 780 1,112 579 769 Cost per Investigation $0 $1,597 $1,483 $1,192 $1,192 $1,192

Ratio of Labor to Total 17% 17% 17% 17% 17%

Basis of Forecast: Forecast Investigations * Cost per InvestigationBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

2. Cost Forecast - Underground Structure Repair Expenses, Portion of FERC Account 7

593.120 8

The underground structure repair expense forecast (Table II-16 and Table II-17) combine 9

the costs of shorings and repairs resulting from field investigations as shown in Table II-13 and Table II-10

14. The cost per repair is forecast to be $40,000 for vaults and $16,000 for manholes, while the cost per 11

shoring is forecast to be $9,000 for vaults and manholes.13 Unit costs for repairs and shoring are based 12

on 2012 recorded costs. The 2015 forecast expense is based on the average of forecast expense for 13

2015-17. 14

12 Please refer to Workpaper entitled “Underground Structure Field Investigation Cost Forecast.”

13 Please refer to Workpaper entitled “Underground Structure Repair Cost Forecast.”

32

Table II-16 Underground Structure Repair Detailed Forecast

(Constant 2012 $000)

2013 2014 2015 2016 2017Vaults

Repairs Identified 420 326 362 334 156 due same year 42 33 36 33 16 prior year rollover 328 378 293 326 301

Repairs Completed 370 411 329 359 317 Cost per Repair ($000) 40$ 40$ 40$ 40$ 40$

Subtotal ($000) 14,785$ 16,424$ 13,147$ 14,346$ 12,667$

Shorings Identified 64 50 56 51 24 due same year 40 32 35 32 15 prior year rollover 34 24 19 21 19

Shorings Completed 74 56 54 53 34 Cost per Shoring ($000) 9$ 9$ 9$ 9$ 9$

Subtotal ($000) 657$ 497$ 480$ 471$ 302$

Manholes

Repairs Identified 399 42 165 342 16 due same year 36 4 15 31 1 prior year rollover 139 363 38 150 311 Repairs Completed 175 367 53 181 312

Cost per Repair ($000) 16$ 16$ 16$ 16$ 16$ Subtotal ($000) 2,720$ 5,703$ 824$ 2,813$ 4,848$

Shorings Identified - - - - - due same yearprior year rollover 3 Shorings completed 3

Cost per Shoring ($000) 9$ 9$ 9$ 9$ 9$ Subtotal ($000) 27$ -$ -$ -$ -$

Total 18,188$ 22,624$ 14,450$ 17,629$ 17,818$ 2015-17 average 16,632$

33

Table II-17 Underground Structure Repairs, Portion of FERC Account 593.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $0 $0 $0 $55 $667 $1,798 $2,262 $1,669Non-Labor $0 $0 $0 $551 $6,296 $16,390 $20,362 $14,964 Total $0 $0 $0 $606 $6,963 $18,188 $22,624 $16,633

Ratio of Labor to Total 9% 10% 10% 10% 10%

Basis of Forecast: Forecast repairs * cost per repair + Forecast shoring * cost per shoringBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

3. Cost Forecast - Underground Structure Replacements14 1

Underground structure replacements are forecast based on the historical failure rates from 2

field investigations, as shown in Table II-13 and Table II-14. Due to their size, complexity, and 3

location, underground structure replacements can involve long lead times to complete the design and 4

construction. Additionally, SCE must acquire permits and coordinate with local authorities to mitigate 5

impacts on residents; thus, this planning process can greatly lengthen the time required to complete 6

underground structure replacements. As of year-end 2012, the underground structure replacement 7

program has identified 449 underground structures for replacement. Table II-18 shows the schedule for 8

completing these currently identified underground structure replacements as well as those that are 9

forecast to be identified during future field investigations. As of June 30, 2013, SCE has completed 95 10

structures designs and 31 structure replacements. 11

Based on current forecasts, SCE would reach steady state replacement rates by 2024 for 12

vaults and 2018 for manholes. Table II-18 and Figure II-5 show the expenditures associated with these 13

replacements. 14

14 WBS CET-PD-IR-UG.

34

Table II-18 Underground Structure Replacement Forecast

(Constant 2012 $000)

2013 2014 2015 2016 2017Vault Replacements

Queue - Year Start 425 523 510 527 525Added 268 208 232 213 99 Completed (170) (221) (215) (215) (197)Queue - Year End 523 510 527 525 427 Cost per Vault $000 $300 $300 $300 $300 $300Vault expenditure ($000) 51,000 66,300 64,500 64,500 59,100

Manhole Replacements

Queue - Year Start 24 39 34 25 27Added 25 3 11 22 1 Completed (10) (8) (20) (20) (16)Queue - Year End 39 34 25 27 12 Cost per Manhole $000 $150 $150 $150 $150 $150

Manhole expenditure ($000) 1,500 1,200 3,000 3,000 2,400

Total ($000) 52,500 67,500 67,500 67,500 61,500

Structure Replacement Forecast

The unit costs for replacing a vault are estimated at $300 thousand, while the unit costs 1

for replacing a manhole are estimated at $150 thousand. These estimates are based on similar work 2

performed in previous years. 3

35

Figure II-5 Underground Structure Replacement Capital Expenditures

WBS Element CET-PD-IR-UG Recorded 2008-2012/Forecast 2013-2017


F. Overhead Conductor Program 1

As previously discussed, SCE is continually refining its inspection and maintenance programs. 2

One such example is SCE’s new overhead conductor program, developed with SCE’s engineering 3

department, which will evaluate the entire overhead distribution system over the next seven years. This 4

program will focus on identifying potential splice, connector, and wire failures under certain operational, 5

environmental, and mechanical conditions to mitigate the risk of downed conductors. 6

Beginning in the fourth quarter of 2013, SCE will start documenting and analyzing information 7

regarding splices, connectors, conductor type, and conductor size on SCE’s distribution system. SCE 8

will use this information to analyze, identify, and prioritize conditions for remediation as part of an 9

effort to reduce potential incidents of downed wire on SCE’s distribution system. The analysis will 10

consider the number and type of splices on a particular span, wire size, distance of conductor from the 11

substation, age of the circuit, and branch line fuse protection for the conductor, among many other items. 12

36

Through the overhead conductor program, SCE seeks to elevate public safety through 1

proactively inspecting for drivers behind potential incidents involving downed wire. 2

1. Cost Forecast 3

Using a seven-year assessment cycle, SCE will inspect overhead conductor spans 4

associated with approximately 206,000 poles per year.15 The expenses in this category are driven by the 5

cost of inspections, planning and analysis, and crew charges for the completion of repairs. Based on 6

previous assessments, it is estimated that approximately 11 percent of conductor spans will include 7

splices and 20 percent will contain connectors. Of the splices identified, it is estimated that 24 percent 8

will require a repair expense for remediation based on previous assessments. Likewise, for connectors, 9

it is estimated that 10 percent will require a repair expense for remediation. Table II-19 summarizes the 10

assumptions used to forecast splice and connector remediation activities. 11

Table II-19 Overhead Conductor Program Unit Forecast

2 0 1 3 2 0 1 4 2 0 1 5 2 0 1 6 2 0 1 7I n s p e c t io n s 51 ,500 206 ,000 206 ,000 206 ,000 206 ,000

S p lic e s S p lic e s ide n tif ie d (11% ) 5 ,665 22 ,660 22 ,660 22 ,660 22 ,660 S p lic e s to re m e dia te (24% ) 1 ,360 5 ,438 5 ,438 5 ,438 5 ,438

C o n n e c to rs C onne c tors ide n tif ie d (20% ) 10 ,300 41 ,200 41 ,200 41 ,200 41 ,200 C onne c tors to re m e dia te (10% ) 1 ,030 4 ,120 4 ,120 4 ,120 4 ,120

N o te : on ly a po r tion o f the re m e d ia tion a c tiv itie s w ill be c om ple te d in the ye a r ide n tif ie d .

Table II-20 shows the forecast expenses for these remediation activities.16 The forecasts 12

include incremental cost associated with the inspection, assessment, and remediation of identified items. 13

The program will begin inspections in 2013, with remediation activities continuing to ramp up over 14

time, and is forecast to reach a steady state of remediation activities by 2017. The 2015 forecast expense 15

is based on the average of forecast expense for 2015-17. 16

15 See SCE-03, Vol. 06, Pt. 2. This is based on the number of poles to be assessed for pole loading. Executing these

programs together will improve efficiency.

16 See Workpaper entitled “Overhead Conductor Program Cost Forecast.”

37

Table II-20 Overhead Conductor Program, Portion of FERC Account 593.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $0 $0 $0 $0 $0 $51 $1,549 $3,748Non-Labor $0 $0 $0 $0 $0 $10 $292 $612 Total $0 $0 $0 $0 $0 $61 $1,841 $4,360

Ratio of Labor to Total 84% 84% 86%

Recorded Forecast

G. Pole Inspection and Replacement 1

Inspection, repair, and replacement of SCE’s over 1.4 million poles have many drivers. Most of 2

these are to maintain pole strength, which might be compromised due to pole deterioration or pole 3

loading. The programs to assess and remediate pole deterioration are included in this section. The Pole 4

Loading Program is discussed in detail in Exhibit SCE-03, Volume 6, Part 2. SCE also performs pole 5

replacement while constructing line extensions to provide service, after storms, when vehicles or other 6

external factors damage poles, or when poles need to be relocated, to name a few. The costs associated 7

with these activities are included in the relevant accounts for those activities, and are not included here. 8

1. Distribution Pole Inspections, Portion of FERC Account 583.120 9

SCE established the distribution pole inspection program to comply with G.O. 165, 10

which became effective in 1997. G.O. 165 requires intrusive inspections for all poles at least 15 years 11

old to be completed within 10 years of program inception. Thereafter, it requires all poles to be 12

intrusively inspected by the time they are 25-years old and then re-inspected at least once every 20 13

years. SCE completed its first cycle of intrusive inspections in 2007. 14

G.O. 165 defines intrusive inspections as “involving movement of soil, taking samples 15

for analysis, and/or using more sophisticated diagnostic tools beyond visual inspections or instrument 16

reading.” “Intrusive” inspections involve drilling into the pole’s interior in order to identify and 17

measure the extent of internal decay, if any, which is typically undetectable with external observation 18

alone. SCE’s inspection standards describe six types of inspections satisfying this definition which 19

38

apply different combinations of digging, boring, and sounding depending on the type of pole and its 1

setting. SCE inspectors may also perform a visual inspection on poles that are in the inspection grid but 2

that are younger than 15 years old to look for signs of obvious external damage such as damage from 3

vehicles or woodpeckers. 4

Poles due for inspection under G.O. 165 guidelines in any given year are spread over 5

SCE’s 50,000 square-mile service territory, often requiring significant drive time between poles. 6

Moreover, the number of inspections that are due any year can vary significantly from year-to-year, 7

depending on the ages of the poles and when the last inspections were performed, which in turn can lead 8

to significant variation in the number of pole replacements required from one year to the next. Both of 9

these are inefficient for resource allocation. 10

These inspections are somewhat technical in nature and having inspectors with proper 11

training and experience is important. As a result, maintaining a stable inspection workforce is key to a 12

successful intrusive inspection program. In 2009, SCE began performing inspections on a “grid” basis 13

to reduce travel time per inspection and to levelize the number of inspections (and therefore 14

replacements) required per year. In addition to inspecting every pole due under the minimum G.O. 165 15

requirements, SCE began inspecting all poles within a defined region or “grid” during the same year. 16

As a result, all poles receiving intrusive inspections within the grid will be due for their next inspection 17

in the same future year. 18

In 2009, SCE also began transitioning to a ten-year inspection cycle that meets and 19

exceeds G.O. 165 requirements and matches industry best practices. The other two California IOUs, 20

SDG&E and PG&E, have also transitioned to 10-year pole inspection cycles. SCE performs both a 21

visual and an intrusive inspection on every pole due for an intrusive inspection under G.O. 165. For 22

poles that will not be due for an intrusive inspection until the next inspection cycle, SCE only performs a 23

visual inspection. For example, a new pole might be installed within a grid three years after that grid 24

underwent intrusive inspections; seven years later, all poles in that grid will be inspected again. To meet 25

G.O. 165 requirements, this pole must be intrusively inspected at least once before the end of its 25th 26

year. However, under the grid-based system it will be inspected twice, once at age 7 and again at age 27

17. In this case, SCE performs a visual inspection in the pole’s 7th year and an intrusive inspection in 28

its 17th year, thus meeting G.O. 165’s requirement. 29

39

a) Cost Forecast 1

Maintaining the grid-based inspection system and a ten-year inspection cycle 2

requires that 10 percent of the wood distribution pole population be inspected every year (approximately 3

130,000 poles). Transitioning to the grid-based system required more inspections per year for a short 4

period in order to align the inspection cycles of poles in each grid. When this transition began in 2009, 5

SCE performed approximately 152,000 intrusive pole inspections. In 2010, SCE inspected 6

approximately 141,000 poles. In 2011, SCE inspected 99,000 poles, lower than a long-term run rate as 7

O&M was constrained and had to be diverted to other emergent issues. In 2012, O&M was constrained 8

due to uncertainty related to the delayed 2012 GRC decision, and inspections fell to approximately 9

74,000 poles. In order to remain on the ten-year grid cycle, SCE plans to inspect approximately 219,000 10

poles in 2013, 125,000 poles in 2014, and 149,000 poles in 2015. 11

Pole inspections are performed by contract personnel, and therefore most of the 12

costs recorded for this activity are non-labor expenses. SCE contracts provide different rates for 13

inspections depending on type and sequence of inspections. Rates for intrusive inspections are higher 14

than rates for visual inspections, and rates for non-grid inspections are higher than rates for grid-based 15

inspections. The reduction in unit costs shown in Table II-21 reflects the transition to grid-based 16

inspections, reductions in contract rates, and an increase in the ratio of visual to intrusive inspections. 17

The forecast unit rate is based on the forecast mix of inspection types.17 Total costs in this activity were 18

forecast by multiplying the forecast unit rate by the forecast units. The labor to non-labor allocation is 19

based on 2012 recorded allocations. 20

17 Please see Workpaper entitled “G.O. 165 Pole Inspection Cost Forecast.”

40

Table II-21 Distribution Pole Inspections, Portion of FERC Account 583.120


2008 2009 2010 2011 2012 2013 2014 2015Labor $106 $430 $494 $243 $350 $1,066 $593 $778Non-Labor $2,088 $7,275 $6,152 $4,270 $2,795 $8,510 $4,743 $6,222 Total $2,194 $7,705 $6,646 $4,513 $3,145 $9,576 $5,336 $7,000

Inspections 31,837 151,998 140,755 99,019 74,075 219,885 125,385 149,385 Cost per Inspection $69 $51 $47 $46 $42 $44 $43 $47


Basis of Forecast: Forecast Inspections * Cost per InspectionBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

Costs associated with distribution poles are shown in Table II-21. Transmission 1

wood pole intrusive inspections are performed on both a grid and circuit basis in accordance with SCE’s 2

maintenance practices on file with the California Independent System Operator. For Transmission wood 3

pole inspection costs, please see Mr. Kedis’s testimony in Exhibit SCE-03, Volume 08. 4

2. Deteriorated Pole Replacements Capital Expenditures 5

This section includes the costs associated with distribution and transmission pole 6

replacements that are based on inspection results from the program described previously. After 7

inspection, the poles that are identified as needing replacement are prioritized based on the extent of 8

deterioration. The priority ratings are 9

1. Priority 1 if the pole needs to be replaced within 72 hours of inspection 10

2. Priority 2A, if the pole needs to be replaced within one year of inspection 11

3. Priority 2B, if it needs to be replaced within two years of inspection 12

4. Priority 2C, if it needs to be replaced within three years of inspection 13

Poles are also identified for replacement by field crews and planners during Overhead 14

Detailed Inspections or while performing other work, if they are found unsuitable for climbing or for 15

supporting new equipment. 16

41

Table II-22 shows the results of intrusive inspections as requested by the Commission in 1

D.12-11-051, Ordering Paragraph 19.18 2013 results reflect data collected as of May 2013. These 2

inspection findings are compiled and quality checked during the course of the year. Therefore, the 3

priority categories of the inspections performed in 2013 are not yet available. 4

Table II-22 Pole Inspection Findings, Transmission and Distribution

2012 2013 2012 2013P1 93 P1 2

P2 - 1yr 1,359 P2 - 1yr 316P2 - 2yr 633 P2 - 2yr 137P3 - 3yr 1,743 P2 - 3yr 537

Pass 70,247 Pass 11,945Total 74,075 80,415 12,937 5,609

Transmission ResultsDistribution Results

a) Cost Forecast 5

In any given year, the number of poles that are replaced under this program are 6

the sum of all the poles that have a replacement due date for that year. Figure II-6 and Figure II-7 show 7

the forecasts for pole replacements by year for transmission and distribution poles.19 These forecasts are 8

derived from the number of inspections completed in previous years, number of inspections forecast in 9

future years, and historical failure rate by priority. The 2012 recorded cost per pole replacement was 10

used to forecast unit costs.20 11

18 “In addition, we direct SCE to provide in the next GRC information about how many priority 1, 2, and 3 conditions were

identified by the actual number of intrusive inspections performed in 2012 and 2013 so that the Commission may evaluate the utility of an accelerated inspection program.” D.12-11-051, pp. 180-1.

19 See Workpaper entitled “Capital Pole Replacement Forecast.”

20 See Workpaper entitled “Pole Replacement Unit Cost Forecast.”

42

Figure II-6 Deteriorated Pole Replacement, Distribution Capital Expenditures

Portion of WBS Element CET-PD-IR-DP Recorded 2008-2012/Forecast 2013-2017


43

Figure II-7 Deteriorated Pole Replacement, Transmission Capital Expenditures

Portion of WBS Element CET-PD-IR-TR Recorded 2008-2012/Forecast 2013-2017

(Total Company $000)

3. Aged Pole Replacement Capital Expenditures 1

As shown in Figure II-9, SCE must transition from an average of fewer than 10,000 poles 2

replaced per year under the deteriorated pole program in 2012 to 35,000 pole replacements per year in 3

2015 resulting from both the deteriorated pole program and the Pole Loading Program.21 This increase 4

21 See, SCE-03, Vol. 6, Pt. 2.

44

in workload has significant implications on operations across multiple disciplines – planning, 1

scheduling, contract strategy, construction, quality assurance, and work-order closing. In order to create 2

a viable transition, SCE has undertaken a program to replace poles that have reached approximately 70 3

years of service. This program will develop the operational capability required to complete the 4

replacement of 35,000 poles beginning in 2015. By replacing the aged poles, SCE is able to more 5

smoothly ramp up to the number of pole replacements and get operationally ready for the Pole Loading 6

Program. 7

To develop this program, SCE examined wood pole failures in SCE’s distribution and 8

transmission systems and correlated the likelihood of pole failure increases to pole age. Using a sample 9

of distribution poles, SCE determined that mean time to replacement due to in-service failure or 10

inspection failure for its wood poles to be 62 years.22 After this age, pole failure rates increase 11

dramatically. Poles reaching the age of 70 are projected to have an 88 percent or greater chance of 12

either failing in service or failing their next inspection by age 80. Currently SCE has over 46,000 poles 13

aged 70 or older in its distribution system Figure II-8. 14

22 Please see Workpaper entitled “Pole Failure Rates.”

45

Figure II-8 Age of Distribution Wood Poles

Given the high risk of failure of these poles, SCE will begin proactively replacing poles 1

aged approximately 70 and older in 2013 until the total pole replacements from the deteriorated pole 2

program and the Pole Loading Program reaches 35,000 poles per year, as shown in Figure II-9. 3

46

Figure II-9 Programmatic Pole Replacements

a) Cost Forecasts 1

As described above, the number of poles to be replaced under this program is 2

based on the need for operational readiness for a longer term pole replacement program. As shown in 3

Figure II-9, SCE is ramping up pole replacements to 16,500 poles in 2013, 25,100 poles in 2014, and 4

35,000 poles in 2015. The counts for aged pole replacements were derived as the difference between the 5

total number of poles SCE needs to replace each year and the poles that are forecast to be replaced under 6

Deteriorated Pole and Pole Loading Programs. The total number of poles expected to be replaced under 7

the Aged Pole Replacement Program is 25,398 from 2013-2015. The remaining aged poles will be 8

assessed and replaced under the Pole Loading Program. 9

SCE forecast the same unit cost per replacement for both the aged and 10

deteriorated pole replacement programs (Figure II-10). In both cases, 2012 recorded cost per pole 11

replacement were used to forecast unit costs.23 12

23 See Workpaper entitled “Pole Replacement Unit Cost Forecast.”

47

Figure II-10 Aged Pole Replacement Capital Expenditures

Portion of WBS CET-PD-IR-DP Recorded 2008-2012/Forecast 2013-2017


H. Joint Pole Activities 1

1. Joint Pole Organization (JPO) Expenses, Portion of FERC Account 583.120 2

JPO is responsible for the execution and administration of all joint pole agreements 3

where SCE shares the ownership of electric poles with other utilities. JPO is also responsible for the 4

execution and administration of agreements to lease pole space to other utilities. Both joint ownership 5

and lease arrangements fulfill SCE’s requirement to provide non-discriminatory access under D.98-6

10.058. JPO generates invoices and receives payments from joint pole users for all capital investments 7

and maintenance-related expenses. JPO receives invoices from other joint pole owners, validates the 8

amounts and makes payment. JPO works with all parties on the Southern California Joint Pole 9

Committee to establish policies and resolve issues that affect all committee members. JPO also 10

48

establishes, monitors, and updates joint pole policies and procedures related to joint pole use and 1

billings. JPO performs audits on poles to identify safety deficiencies and unauthorized attachments. 2

Table II-23 Joint Pole Organization Expenses

(Portion of FERC Account 583.120) Recorded and Adjusted 2008-2012/Forecast 2013-2015


2008 2009 2010 2011 2012 2013 2014 2015Labor $2,745 $2,916 $2,827 $2,459 $2,927 $3,016 $3,016 $3,016Non-Labor $346 $450 $506 $917 $413 $324 $324 $324 Total $3,091 $3,366 $3,333 $3,376 $3,340 $3,340 $3,340 $3,340


Basis of Forecast: 2012 Recorded with additional headcountBasis of Labor/Non-Labor Split: Forecast based

Recorded Forecast

a) Cost Forecast 3

As shown in Table II-23, the expenses in this account have remained stable since 4

2008. Two administrative aides who are currently working as contract employees will be hired as SCE 5

employees in 2013. Hence, SCE proposes to use the 2012 recorded expenses to develop the forecast for 6

2015.24 The costs for the two administrative aides will move from non-labor to labor expenses. 7

2. Joint Pole Expense Credits, Portion of FERC Account 583.120 8

For poles jointly owned with other utilities (e.g., a telephone or wireless company), SCE 9

recovers some of the costs from these utilities for activities such as pole inspections or replacements. 10

SCE tracks and records the net annual debits and credits between SCE and other participants in 11

accordance with joint pole agreements. 12

Joint Pole Expense Credits are driven by three operational activities: pole inspections, 13

pole maintenance, and penalties. When SCE performs an inspection or performs O&M maintenance 14

activities on a pole that is jointly owned, the expense incurred is shared with the other joint owner(s). In 15

addition, when SCE-owned poles are used by other parties without permission, penalties are levied 16

against them. These penalties are recorded as credits in this FERC Account. 17

24 See Workpaper entitled “583.120 Joint Pole Support Workpaper.”

49

Table II-24 Joint Pole Credit Expenses

Portion of FERC Account 583.120 Recorded and Adjusted 2008-2012/Forecast 2013-2015


2008 2009 2010 2011 2012 2013 2014 2015

Labor -$ -$ -$ -$ -$ -$ -$ -$ Non-Labor (430)$ (961)$ (1,019)$ (1,361)$ (2,032)$ (2,598)$ (1,875)$ (2,087)$ Total (430)$ (961)$ (1,019)$ (1,361)$ (2,032)$ (2,598)$ (1,875)$ (2,087)$


Basis of Forecast: LYR credits per unit work * units of workBasis of Labor/Non-Labor Split: LYR

Recorded Forecast

a) Cost Forecast 1

Table II-25 shows the recorded and forecast credits from intrusive inspections, 2

pole maintenance, and penalties. The intrusive inspection credits were forecast using the distribution 3

pole inspection counts discussed previously and the forecast credit per pole inspection. The recorded 4

credit per pole inspection fluctuates based on the type of pole, type of inspection, and the number of 5

joint owners the cost can be shared with. Therefore SCE has used a five-year average unit cost to 6

forecast the credit per pole inspection in the future. Pole maintenance credits are also driven by the 7

number of poles maintained, type of pole, and number of joint owners on each pole. These credits have 8

increased from 2008-2012, and in accordance with D. 89-12-057, SCE has used 2012 recorded credits as 9

the basis for the forecast. Penalty credits depend on how many unauthorized attachments SCE finds and 10

shows an upward trend from 2008 to 2012. Therefore, SCE has used 2012 recorded penalty credits as 11

the basis for the forecast. Table II-24 summarizes the joint pole expense credits. 12

50

Table II-25 Joint Pole Credits – Forecast by Activity Types

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017a Inspection Credits (2012 $) (247,257) (629,949) (611,422) (697,796) (1,120,685) (1,686,230) (963,730) (1,168,694) (1,155,884) (1,202,001)

Pole Inspections 31,837 151,998 140,755 99,019 74,075 219,385 125,385 149,385 150,385 156,385 Credit per pole inspection (2012 $) (8) (4) (4) (7) (15) (8) (8) (8) (8) (8)Forecast unit cost based on 2008-2012 average

b Pole Maintenance Credits (2012 $) (79,653) (209,578) (308,418) (399,950) (544,384) (544,384) (544,384) (544,384) (544,384) (544,384)Forecat based on 2012 recorded

c Penalty Credits (2012 $) (103,598) (121,041) (99,855) (264,423) (366,902) (366,902) (366,902) (366,902) (366,902) (366,902)Forecat based on 2012 recorded

a+b+c Total Joint Pole Expense Credits (2012 $)

(430,508) (960,568) (1,019,696) (1,362,169) (2,031,972) (2,597,516) (1,875,016) (2,079,981) (2,067,170) (2,113,287)

2015-2017 Average (2,086,813)

3. Joint Pole Replacement Capital Credits 1

As discussed in the previous section, for certain activities, such as when SCE replaces a 2

distribution or transmission pole, it recovers some of the costs from joint owners. The capital credits 3

included in this section reflects the net payments SCE receives from joint owners for pole replacement. 4

SCE tracks and records the net annual debits and credits between SCE and other participants in 5

accordance with joint pole agreements. 6

a) Cost Forecast 7

The forecast joint pole credit per pole replaced was estimated based on historical 8

pole replacements under deteriorated pole program and other programs and the total credits received 9

from 2008 through 2012. Table II-26 and Figure II-11 show the recorded count of poles replaced under 10

these programs and the credits recorded as a result of those pole replacements.25 Other programs that 11

result in pole replacements include line extensions to provide service, storms, when vehicles or other 12

external factors damage poles, or when poles need to be relocated. The average credit per pole from 13

2008 through 2012 was $765 in constant 2012 dollars. SCE used $800 as the forecast credit per pole 14

replaced.26 15

25 Note the joint pole credits resulting from the Pole Loading Program are not forecast here. Those credits can be found in

SCE-03, Vol. 06, Pt. 2.

26 See Workpaper entitled “Capital Pole Replacements in Other Programs” (for forecast of poles replaced in other programs).

51

Table II-26 Joint Pole Credit Unit Credit Analysis

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Total Credits (2012 $000) (11,526) (15,391) (9,983) (11,701) (15,645) (19,600) (24,080) (14,400) (14,400) (14,400) Deteriorated Poles 9,354 8,291 7,194 8,399 8,794 7,500 7,600 8,102 10,000 10,000 Aged Poles - - - - - 9,000 14,500 1,898 - - Other Programs 9,354 8,291 7,194 8,399 8,794 8,000 8,000 8,000 8,000 8,000 Total Replacements 18,708 16,582 14,388 16,798 17,588 24,500 30,100 18,000 18,000 18,000 Unit cost (2012 $000) (0.616)$ (0.928)$ (0.694)$ (0.697)$ (0.890)$ (0.800)$ (0.800)$ (0.800)$ (0.800)$ (0.800)$

Figure II-11 Joint Pole Credits, Distribution and Transmission Capital Expenditures

WBS Elements CET-PD-CR-JD and CET-PD-CR-JT Recorded 2008-2012/Forecast 2013-2017


I. Wood Pole Disposal 1

When wood poles are removed from service, they must be appropriately disposed of to mitigate 2

adverse environmental impact. Disposal is complicated, as all poles have been treated with chemical 3

52

preservatives, and, since 2006, these poles have been considered hazardous waste. Wood pole disposal 1

records the cost of disposing of distribution wood poles removed from the system. 2

a) Cost Forecast 3

Table II-27 shows the recorded costs, pole counts, and unit costs from 2008 to 4

2012, along with the forecast for 2013-2017. Disposal costs vary depending on the type of pole and 5

costs have fluctuated from year to year. Therefore, SCE utilized the five-year average cost of $101 per 6

pole, rounded to $100 for forecasting purposes, as the basis for the forecast. Figure II-12 summarizes 7

the recorded expenditures and requests in this category. 8

Table II-27 Wood Pole Disposal Unit Cost Analysis

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Wood Pole Disposal (2012 $000)

1,562 1,711 2,091 1,681 1,306 2,450 3,010 1,800 1,800 1,800

Deteriorated Poles 9,354 8,291 7,194 8,399 8,794 7,500 7,600 8,102 10,000 10,000 Aged Poles - - - - - 9,000 14,500 1,898 - - Other Programs 9,354 8,291 7,194 8,399 8,794 8,000 8,000 8,000 8,000 8,000 Total Replacements 18,708 16,582 14,388 16,798 17,588 24,500 30,100 18,000 18,000 18,000 Unit cost (2012 $000)

0.083$ 0.103$ 0.145$ 0.100$ 0.074$ 0.100$ 0.100$ 0.100$ 0.100$ 0.100$

53

Figure II-12 Wood Pole Disposal Capital Expenditures

WBS Element WBS CET-PD-OT-WP Recorded 2008-2012/Forecast 2013-2017


Additional capital expenditures incurred for wood pole disposal under the Pole Loading program 1

are discussed in Exhibit SCE-03, Volume 06, Part 2. 2

54

J. Summary of FERC Accounts 1

1. FERC Account 583.120 2

Table II-28 Inspection of Distribution Overhead and Underground Lines and Equipment

Summary of FERC Account 583.120 Recorded and Adjusted 2008-2012/Forecast 2013-2015

(100% CPUC-Jurisdictional 2012 Constant $000)

2008 2009 2010 2011 2012 2013 2014 2015Annual Circuit Patrols and Air Patrols Labor $950 $612 $439 $563 $653 $653 $653 $653 Non-Labor $353 $565 $657 $479 $370 $370 $370 $370 Sub-Total $1,303 $1,177 $1,096 $1,042 $1,023 $1,023 $1,023 $1,023

Overhead Detail Inspections (ODI) Labor $2,000 $2,425 $2,591 $2,746 $2,904 $4,372 $4,422 $4,295 Non-Labor $1,652 $1,617 $1,272 $1,333 $2,335 $3,517 $3,558 $3,455 Sub-Total $3,652 $4,042 $3,863 $4,079 $5,239 $7,889 $7,980 $7,750

Underground Detail Inspections (UDI) Labor $1,591 $1,438 $2,320 $3,210 $4,430 $4,257 $4,042 $4,389 Non-Labor $736 $662 $1,051 $2,270 $1,046 $1,005 $954 $1,036 Sub-Total $2,327 $2,100 $3,371 $5,480 $5,476 $5,262 $4,996 $5,425

Field Investigations Labor $0 $0 $0 $10 $200 $229 $119 $134 Non-Labor $0 $0 $0 $45 $956 $1,097 $571 $642 Sub-Total $0 $0 $0 $55 $1,156 $1,326 $690 $776

Joint Pole Organization Labor $2,745 $2,916 $2,827 $2,459 $2,927 $3,016 $3,016 $3,016 Non-Labor $346 $450 $506 $917 $413 $324 $324 $324 Sub-Total $3,091 $3,366 $3,333 $3,376 $3,340 $3,340 $3,340 $3,340

Joint Pole Credits Labor $0 $0 $0 $0 $0 $0 $0 $0 Non-Labor (430)$ (961)$ (1,019)$ (1,361)$ (2,032)$ (2,598)$ (1,875)$ (2,087)$ Sub-Total (430)$ (961)$ (1,019)$ (1,361)$ (2,032)$ (2,598)$ (1,875)$ (2,087)$

Distribution Intrusive Pole Inspections Labor $106 $430 $494 $243 $350 $1,066 $593 $778 Non-Labor $2,088 $7,275 $6,152 $4,270 $2,795 $8,510 $4,743 $6,222 Sub-Total $2,194 $7,705 $6,646 $4,513 $3,145 $9,576 $5,336 $7,000

Total 583.120 Labor $7,392 $7,821 $8,671 $9,231 $11,464 $13,593 $12,845 $13,265 Non-Labor $4,745 $9,608 $8,619 $7,953 $5,883 $12,225 $8,645 $9,962 Total Expenses $12,137 $17,429 $17,290 $17,184 $17,347 $25,818 $21,490 $23,227

Recorded Forecast

$‐

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

55


Table II-29 Planned Maintenance of Distribution Overhead and Underground Lines



2008 2009 2010 2011 2012 2013 2014 2015Distribution Apparatus Labor $2,711 $3,320 $3,200 $2,970 $3,241 $3,087 $3,087 $3,087 Non-Labor $1,351 $2,051 $1,830 $1,306 $760 $1,460 $1,460 $1,460 Sub-Total $4,062 $5,371 $5,030 $4,276 $4,001 $4,547 $4,547 $4,547

Distribution Preventive Maintenacne Labor $14,554 $20,570 $19,277 $20,498 $21,376 $21,376 $21,376 $21,376 Non-Labor $20,257 $28,831 $30,390 $32,023 $29,503 $29,503 $29,503 $29,503 Sub-Total $34,811 $49,401 $49,667 $52,521 $50,879 $50,879 $50,879 $50,879

Underground Structure Repairs and Shoring Labor $0 $0 $0 $55 $667 $1,798 $2,262 $1,669 Non-Labor $0 $0 $0 $551 $6,296 $16,390 $20,362 $14,964 Sub-Total $0 $0 $0 $606 $6,963 $18,188 $22,624 $16,633

Conductor Splice Program Labor $0 $0 $0 $0 $0 $51 $1,549 $3,748 Non-Labor $0 $0 $0 $0 $0 $10 $292 $612 Sub-Total $0 $0 $0 $0 $0 $61 $1,841 $4,360

Distribution Transformer Preventive Maintenance Labor $1,580 $848 $1,155 $1,080 $1,048 $1,143 $1,143 $1,143 Non-Labor $772 $437 $557 $956 $468 $638 $638 $638 Sub-Total $2,352 $1,285 $1,712 $2,036 $1,516 $1,781 $1,781 $1,781

Graffiti Removal Labor $5 $9 $21 $35 $70 $70 $70 $70 Non-Labor $599 $544 $552 $591 $571 $571 $571 $571 Sub-Total $604 $553 $573 $626 $641 $641 $641 $641

Bark Beetle Labor $305 $276 $260 $206 $181 $181 $181 $181 Non-Labor $8,878 $5,227 $4,115 $2,701 $2,089 $2,089 $2,089 $2,089 Sub-Total $9,183 $5,503 $4,375 $2,907 $2,270 $2,270 $2,270 $2,270

Vegetation Management Labor $2,180 $3,260 $5,519 $4,975 $4,285 $4,285 $4,285 $4,285 Non-Labor $45,265 $47,212 $56,993 $55,310 $53,450 $53,450 $53,450 $53,450 Sub-Total $47,445 $50,472 $62,512 $60,285 $57,735 $57,735 $57,735 $57,735


Recorded Forecast

$‐

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

56


Table II-30 Distribution Overhead and Underground Breakdown Maintenance



2008 2009 2010 2011 2012 2013 2014 2015Breakdown Maintenance Labor $8,260 $10,129 $8,135 $11,334 $13,949 $13,949 $13,949 $13,949 Non-Labor $6,744 $10,851 $7,941 $11,892 $13,505 $13,505 $13,505 $13,505 Sub-Total $15,004 $20,980 $16,076 $23,226 $27,454 $27,454 $27,454 $27,454


Recorded Forecast

$‐

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

Appendix A

Witness Qualification

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF MELVIN A. STARK 3

Q. Please state your name and business address for the record. 4

A. My name is Melvin Stark, and my business address is 1 Innovation Way, Pomona, CA. 5

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 6

A. I am the Manager of Maintenance & Inspection (“M&I”) organization within SCE’s 7

Transmission and Distribution organization. In this capacity, I am responsible for developing 8

and setting strategy for the implementation of maintenance and inspection policies and practices 9

on the Transmission and Distribution electric systems for the Power Delivery Business Line. 10

Q. Briefly describe your educational and professional background. 11

A. I graduated from the University of La Verne in 1988 with a Bachelor of Arts degree in Business 12

Administration. I received an MBA degree from ULV in 1992. In 1999, I added a Finance 13

concentration to my graduate degree. I joined SCE in December 1987 as a financial analyst in 14

the Treasurer’s Department. Since July of 1991, I have held a variety of positions involving 15

regulatory and legislative matters. During this time, I have had extensive regulatory and 16

legislative experience working with the California Public Utilities Commission, the Federal 17

Energy Regulatory Commission, and state and federal legislative bodies. From 1998 to 2004, I 18

was a project manager in the California Public Utilities Commission Regulation section of 19

TDBU, and worked on such projects as the Order Instituting Investigation into SCE’s line 20

maintenance practices. I became the Manager of Maintenance & Inspections in the Power 21

Delivery business line in 2004. In October of 2011, I began a temporary cross-training 22

assignment as a manager in our Substation Construction and Maintenance organization. I 23

returned to my current role as Manager of Maintenance & Inspections in April of 2013. 24

Q. What is the purpose of your testimony in this proceeding? 25

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-03, 26

Volume 6, Part – 1, entitled Transmission and Distribution - Distribution Maintenance, as 27

A-2

identified in the Table of Contents thereto. 1

Q. Was this material prepared by you or under your supervision? 2

A. Yes, it was. 3

Q. Insofar as this material is factual in nature, do you believe it to be correct? 4

A. Yes, I do. 5

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 6

judgment? 7

A. Yes, it does. 8

Q. Does this conclude your qualifications and prepared testimony? 9

A. Yes, it does. 10

transmission and distribution (t&d) volume 6, part 1 ... · exhibit no.: sce-03, vol. 06, part...

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