Transmission and Distribution (T&D) Volume 3 – System ... · PDF file(11) Alberhill 500/115 kV Substation (Project #06092).....46. SCE-03: Transmission and Distribution Volume 03

Application No.: Exhibit No.: SCE-03, Vol. 03 Witnesses: R. Woods

(U 338-E)

2015 General Rate Case

Transmission and Distribution (T&D) Volume 3 – System Planning Capital Projects

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SUMMARY

This exhibit presents the capital projects necessary to accommodate customer load growth, construct

transmission system projects, and interconnect new generation to our system.

SCE is requesting $4,145 million in capital expenditures from 2013 to 2017, of which $2,165 million is

CPUC-jurisdictional.

System Planning Capital Projects CPUC-Jurisdictional Capital Expenditures

2013-2017 Forecast (Nominal $ millions)

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 03-System Planning Capital Projects

Table Of Contents

Section Page Witness

-i-

I. SYSTEM PLANNING CAPITAL PROJECTS ................................................1 R. Woods

A. Introduction And Overview ...................................................................1

B. Electric System Overview ......................................................................3

C. 2012 GRC Authorization and Recorded Costs ......................................5

D. Planning Process ....................................................................................8

1. Overview of Project Planning ....................................................8

2. Transmission Planning Processes ..............................................9

3. Generator Interconnection Process ..........................................10

4. Load Growth Planning Process ................................................11

a) Development Of Peak Load Forecasts .........................11

b) Identification Of System Requirements .......................13

c) Development of Alternatives and Project Selection .......................................................................14

5. Construction Licensing under G.O. 131-D ..............................15

E. Transmission & Interconnection Planning Projects .............................19

1. Grid Reliability Projects ..........................................................19

(1) BC/SJV RAS Expansion (Project #07104) ............................................................20

(2) Victor 220/115 kV Substation (Project #06477)...............................................21

(3) Rio Hondo 220/66 kV Substation (Project #06714)...............................................22

(4) East Kern Wind Resource Area (EKWRA) (Project #06685) ............................23

SCE-03: Transmission and Distribution Volume 03 - System Planning Capital Projects

Table Of Contents (Continued)


-ii-

(5) Devers 115 kV SPS (Project #07243) ..............24

(6) La Cienega 220/66 kV Substation (Project #07111)...............................................24

(7) Springville 220/66 kV Substation (Project #07518)...............................................25

(8) Chino 220/66 kV Substation (Project #07120) ............................................................26

2. Transmission System Generation Interconnection Projects .....................................................................................27

(1) Sandlot 220 kV Substation (Project #6960) ..............................................................28

(2) Eldorado Ivanpah Transmission Upgrades (Project # 06551) .............................28

(3) Devers - Colorado River (DCR) (Project #04847)...............................................29

(4) Red Bluff 500/220 kV Substation (Project #06929)...............................................30

(5) Tehachapi Renewable Transmission Project - Seg. 7 and Seg. 8 (Projects #06438, #06439) ..............................................30

(6) Tehachapi Renewable Transmission Project – Segments 3B, 6 and 9 (Projects #07183, #05243, #06440) ................32

(7) Colorado River Corridor SPS (Project #07061)...............................................34

(8) Jasper 220 kV Substation (Project #06902) ............................................................34

(9) Primm 220 kV Substation (Project #07426) ............................................................35




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(10) Whirlwind #2AA and #3AA Bank Upgrades (Project #07067) ..............................35

3. Projects With Less Than $1 Million in CPUC-Jurisdictional Costs ..................................................................36

F. Load Growth Planning Programs .........................................................36

1. A-Bank Plan .............................................................................37

(1) El Casco 220/115 kV Substation (Project #05075)...............................................39

(2) Devers-Mirage 115 kV System Split (Project #05360)...............................................40

(3) Valley ‘C’ 500/115 kV Substation (Project #06807)...............................................41

(4) Ellis ‘C’ 220/66 kV Substation (Project #06221)...............................................41

(5) Santiago 220/66 kV Substation (Project #06227)...............................................42

(6) La Cienega 220/66 kV Substation (Project #06284)...............................................42

(7) La Fresa 220/66 kV Substation (Project #06824)...............................................43

(8) Vestal 220/66 kV Substation (Project #06263) ............................................................44

(9) Valley ‘AB’ 500/115 kV Substation (Project #06670)...............................................44

(10) Chino 220/66 kV Substation–Phase 1 (Project #05383)............................................45

(11) Alberhill 500/115 kV Substation (Project #06092)...............................................46




-iv-

(12) Saugus ‘C’ 220/66 kV Substation (Project #06107)...............................................46

2. Subtransmission Lines Plan .....................................................47

(1) Gould-La Canada 66 kV Recable (Project #04853)...............................................49

(2) Santiago-Borrego-Morro 66 kV Reconductor (Project #06392) .........................50

(3) Etiwanda-Alder-Randall 66kV Reconductor (Project #06028) .........................50

(4) Alder-Declez 66 kV Recable Bundle (Project #05316)...............................................51

(5) Camarillo Substation 66 kV Capacitor Bank (Project #07040).....................52

(6) Weldon Substation 66 kV Capacitor Bank (Project #05364) .....................................52

(7) Mesa-Laguna Bell-Narrows 66 kV Reconductor (Project #06070) .........................52

(8) Mesa-Rush No. 3 66 kV Recable (Project# 06844)...............................................53

(9) Carodean Substation 115 kV Capacitor Bank (Project# 07208).....................53

(10) La Cienega Subtransmission Line Project (Project #07505, #07506, #07383, #06382) ..............................................54

(11) Springville-Strathmore 66 kV Reconductor (Project #07507) .........................56

(12) Vestal-Columbine-Delano-Earlimart 66 kV Reconductor (Project #07508) ..............56

(13) Vestal-Delano-Browning 66 kV Reconductor (Project #07512) .........................57




-v-

(14) Arrowhead Reconfiguration Project (Project #04891)...............................................57

(15) Valley-Ivyglen 115 kV Line (Project #06030) ............................................................58

(16) Santa Barbara County Reliability Project (Project #04518) ..................................58

(17) Moorpark-Newbury 66 kV Line (Project #05329)...............................................59

(18) Yucca 115/12 kV Substation Loop-In (Project #07382) ..........................................61

(19) Santiago-Irvine No. 2 66 kV Recable (Project #07384)...............................................61

3. Subtransmission VAR Plan......................................................62

(1) Bunker 115 kV Cap Bank Addition (Project #06822)...............................................64

4. Distribution Substation Plan (DSP) .........................................64

(1) Las Lomas 66/12 kV Substation (Project #04422)...............................................67

(2) Mascot 66/12 kV Substation (Project #05396) ............................................................67

(3) Triton 115/12 kV Substation (Project #05353) ............................................................68

(4) Pepper 115/12 kV Substation (Project #04458)...............................................68

(5) El Sobrante 33/12 kV Substation (Project #05023)...............................................69

(6) Roadway 115/12 kV Substation (Project #05432)...............................................69




-vi-

(7) Bloomington 66/12 kV Substation (Project #06093)...............................................70

(8) Fillmore 66/16 kV Substation (Project #06220)...............................................70

(9) Devers 115/12 kV Substation (Project #06577)...............................................71

(10) La Habra 66/12 kV Substation (Project #06605)...............................................71

(11) Estrella 66/12 kV Substation (Project #06870) ............................................................72

(12) Carodean 115/12 kV Substation (Project #06948)...............................................72

(13) Delano 66/12 kV Substation (Project #07160) ............................................................73

(14) Glen Avon 66/12 kV Substation (Project #04445)...............................................73

(15) Lampson 66/12 kV Substation (Project #06292)...............................................74

(16) Downs 115/12 kV Substation (Project #06691)...............................................74

(17) Pebbly Beach 12/2.4 kV Substation (Project #06958)...............................................75

(18) Del Amo Jr 66/12 kV Substation (Project # 07216)..............................................76

(19) La Palma 66/16 kV Substation (Project #07263)...............................................76

(20) Lark Ellen 66/12 kV Substation (Project #07391)...............................................77

(21) Colonia 66/16 kV Substation (Project #05403)...............................................78




-vii-

(22) Canyon 66/12 kV Substation (Project #06301) ............................................................78

(23) San Dimas 66/12 kV Substation (Project #07307)...............................................78

(24) Orange 66/12 kV Substation (Project #07480) ............................................................79

(25) Lakeview 115/12 kV Substation (Project #05411)...............................................79

(26) Yokohl 66/12 kV Substation (Project #06067) ............................................................80

(27) Banducci 66/12 kV Substation (Project #06619)...............................................81

(28) Greenhorn 66/2.4 kV Substation (Project #06836)...............................................81

(29) Mainframe 66/4.16 kV Substation (Project #07293)...............................................82

(30) Safari 33/12 kV Substation (Project #07516) ............................................................83

(31) Circle City 66/12 kV Substation - Phase 1 (Project #06575) .................................83

(32) Falcon Ridge 66/12 kV Substation (Project #05397)...............................................84

5. Land Held for Future Use ........................................................84

G. System Improvement/Reinforcement Programs ..................................85

1. Substation Equipment Replacement Program (SERP)–Blanket Budget Item, WBS Element CET-ET-LG-SU................................................................................85

2. DSP Circuit Work–Blanket Budget Item, WBS Elements CET-ET-LG-PF and CET-ET-LG-CI .....................87




-viii-

a) New DSP Circuits ........................................................88

b) Miscellaneous Non-Circuit ..........................................91

c) Circuit Load Reduction Program (CLRP) ...................92

3. Distribution Plant Betterment–Blanket Budget Item, WBS Element CET-PD-LG-PB ...............................................94

4. Distribution VAR Plan, WBS Element CET-PD-LG-NC .....................................................................................95

5. Capacitor Automation Program, WBS Element CET-PD-LG-CV ......................................................................97

6. Circuit Automation Program–Blanket Budget Item, WBS Element CET-PD-OT-CI ................................................98

7. Substation Load Information Monitor Program, WBS CET-OT-OT-AT ..........................................................100

H. Generator Interconnection Program ...................................................101

I. Added Facilities Projects ...................................................................102

1. Port of Long Beach 66/12 Pier G (Project #06490) ...............103

2. Port of Long Beach Pier E Ship 66/12 kV Substation and 3rd Transformer (Projects #06944, #07442) ..................................................................................104

3. Leatherneck 115/33 kV Substation (Project #06752) ............105

4. Breitburn Energy Partners (Project # 07299).........................106

5. OXY Long Beach (Project # 07458) .....................................106

6. Natural 66/12 kV Substation (Project #07253) ......................107

J. Vote Solar Settlement ........................................................................107

Appendix A Witness Qualification ..................................................................................

SCE-03: Transmission & Distribution Volume 03 - System Planning Capital Projects

List Of Figures

Figure Page

-ix-

Figure I-1 Simplified System Diagram ........................................................................................................3

Figure I-2 Comparison of 2012 GRC Authorized and Recorded Expenditure (Nominal

$000) ......................................................................................................................................................6

Figure I-3 SCE Reliability Planning Process .............................................................................................10

Figure I-4 SCE Generation Interconnection Planning Processes ..............................................................11

Figure I-5 A-Bank Plan ..............................................................................................................................38

Figure I-6 Subtransmission Lines Plan ......................................................................................................48

Figure I-7 Subtransmission VAR Plan ......................................................................................................63

Figure I-8 Distribution Substation Plan (DSP) ..........................................................................................65

Figure I-9 Substation Equipment Replacement Program (SERP) Expenditures Recorded

2008-2012/Forecast 2013-2017 WBS Element CET-ET-LG-SU (Constant 2012 and

Nominal $000) .....................................................................................................................................86

Figure I-10 New DSP Circuit Capital Expenditure Recorded 2008-2012/Forecast 2013-

2017 WBS Elements CET-ET-LG-PF and CET-ET-LG-CI (Constant 2012 and

Nominal $000) .....................................................................................................................................89

Figure I-11 Miscellaneous Non-Circuit Capital Expenditures Recorded 2008-

2012/Forecast 2013-2017 WBS Elements CET-ET-LG-PF and CET-ET-LG-CI

(Constant 2012 and Nominal $000) .....................................................................................................92

Figure I-12 Circuit Load Reduction Program Capital Expenditures Recorded 2008-

2012/Forecast 2013-2017 WBS Elements CET-ET-LG-PF and CET-ET-LG-CI

(Constant 2012 and Nominal $000) .....................................................................................................94

Figure I-13 Distribution Plant Betterment Capital Expenditures Recorded 2008-

2012/Forecast 2013-2017 WBS Element CET-PD-LG-PB (Constant 2012 and

Nominal $000) .....................................................................................................................................95

Figure I-14 Distribution VAR Plan Capital Expenditures Recorded 2008-2012/Forecast

2013-2017 WBS Element CET-PD-LG-NC (Constant 2012 and Nominal $000) ..............................97


List Of Figures (Continued)

Figure Page

-x-

Figure I-15 Capacitor Automation Program Capital Expenditures Recorded 2008-

2012/Forecast 2013-2017 WBS Element CET-PD-LG-CV (Constant 2012 and

Nominal $000) .....................................................................................................................................98

Figure I-16 Circuit Automation Program Capital Expenditures Recorded 2008-

2012/Forecast 2013-2017 WBS Element CET-PD-OT-CI (Constant 2012 and

Nominal $000) ...................................................................................................................................100

Figure I-17 Substation Load Information Monitor Program Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-OT-OT-AT (Constant

2012 and Nominal $000) ...................................................................................................................101


List Of Tables

Table Page

-xi-

Table I-1 System Planning Capital Projects Expenditure Summary CPUC and FERC

Jurisdictional (Nominal $000) ...............................................................................................................2

Table I-2 System Planning Capital Projects Expenditure Summary CPUC Jurisdictional

(Nominal $000) ......................................................................................................................................3

Table I-3 Operating Date Changes for Projects Included in 2012 GRC to Current 2015-

2017 Forecast .........................................................................................................................................7

Table I-4 Licensing and Exemption Status Distribution Substation Plan ..................................................17

Table I-5 Licensing and Exemption Status Subtransmission Lines Plan ..................................................18

Table I-6 Licensing and Exemption Status A-Bank Plan ..........................................................................19

Table I-7 Transmission & Interconnection Planning Projects Capital Expenditure

Summary (Nominal $000) ..................................................................................................................19

Table I-8 Grid Reliability Projects Expenditure Summary CPUC and FERC

Jurisdictional (Nominal $000) .............................................................................................................20

Table I-9 Transmission System Generation Interconnection Projects Expenditure

Summary CPUC and FERC Jurisdictional (Nominal $000) ...............................................................27

Table I-10 Load Growth Planning Programs Capital Expenditure Summary (Nominal

$000) ....................................................................................................................................................37

Table I-11 A-Bank Plan Capital Expenditure Summary (Nominal $000) .................................................39

Table I-12 Subtransmission Lines Plan Capital Expenditure Summary (Nominal $000) ........................49

Table I-13 Subtransmission VAR Plan Capital Expenditure Summary (Nominal $000) ........................64

Table I-14 Distribution Substation Plan Capital Expenditure Summary (Nominal $000) .......................66

Table I-15 Land Held for Future Use Capital Expenditure Summary (Nominal $000) ............................85

Table I-16 Substation Equipment Replacement Program Capital Expenditure Forecast

WBS Element CET-ET-LG-SU (Nominal $000) ................................................................................87

Table I-17 DSP Circuit Work Capital Expenditures WBS Elements CET-ET-LG-PF and

CET-ET-LG-CI (Nominal $000) .........................................................................................................88

Table I-18 New Distribution Circuit Capital Expenditures WBS Elements CET-ET-LG-

PF and CET-ET-LG-CI (Nominal $000) .............................................................................................90

SCE-03: Transmission & Distribution Volume 03-System Planning Capital Projects

List Of Tables (Continued)

Table Page

-xii-

Table I-19 Added Facilities Projects Capital Expenditure Summary (Nominal $000) ..........................103

1

I. 1

SYSTEM PLANNING CAPITAL PROJECTS 2

A. Introduction And Overview 3

SCE constructs projects that incur capital expenditures to accommodate customer load growth, 4

grid reliability, interconnect new generation to our system, and respond to customer requests for 5

nonstandard service. These projects and expenditures fall into five primary categories: (1) 6

Transmission Planning Projects, (2) the Load Growth Planning Program, (3) the System 7

Improvement/Reinforcement Program, (4) the Generator Interconnection Program, and (5) Added 8

Facilities projects. 9

The Transmission Planning Projects are further divided into four sub-categories in which 10

location specific projects are identified to implement large scale upgrades of existing substations or 11

transmission lines or to construct new transmission lines. These are: 12

1. Grid Reliability Projects 13

2. Transmission System Generation Interconnection Projects 14

3. Other Transmission Planning Projects with CPUC-jurisdictional costs greater than $1 15

million1 16

4. Other Transmission Planning Projects with CPUC-jurisdictional costs less than $1 million 17

The Load Growth Planning Program is divided into four distinct sub-categories as well to 18

increase system capacity by substation expansion, new substation construction, existing subtransmission 19

line upgrades, or new subtransmission line construction. These projects can vary significantly in size 20

and complexity depending on the specific system need being addressed. These are: 21

1. A-Bank Plan 22

2. Subtransmission Lines Plan 23

3. Subtransmission Volt-Ampere Reactive (VAR) Plan 24

4. Distribution Substation Plan (DSP) 25

The System Improvement/Reinforcement Program includes smaller scale categories of work 26

that are associated with upgrading substation equipment and the distribution system to accommodate 27

load growth. The locations and specifications of these projects are identified annually based on near 28

term system evaluation. They include: 29

1 The CPUC jurisdiction costs for these projects are primarily telecommunication and IT equipment and associated labor.

2

1. Substation Equipment Replacement Program (SERP) 1

2. DSP Circuits 2

3. Distribution Plant Betterment 3

4. Distribution VAR Plan 4

5. Capacitor Automation Program 5

6. Circuit Automation Program 6

7. Substation Load Information Monitor Program (SLIM) 7

The Generator Interconnection Program includes projects and capital expenditures driven by 8

requests from generation project developers who choose to have SCE construct the facilities necessary 9

to interconnect their projects to the SCE grid. 10

The Added Facilities projects include projects SCE constructs when a load side customer 11

requests non-standard service. These projects may include portions that are customer cost responsibility 12

and portions that are rate payer funded. 13

Total costs for these projects are shown below in Table I-1 and CPUC-jurisdictional costs are 14

shown below in Table I-2. 15

Table I-1 System Planning Capital Projects Expenditure Summary

CPUC and FERC Jurisdictional (Nominal $000)

Line No.

Project Category Prior 2013 2014 2015 2016 2017 Total

1 Transmission & Interconnection Planning Projects 2,880,640 1,075,689 580,662 214,934 80,715 32,441 4,865,082 2 Load Growth Planning Programs 448,920 194,889 371,272 412,991 307,802 57,699 1,793,572 3 System Improvement/Reinforcement Programs 25,905 122,662 114,032 108,494 101,143 112,746 584,981 4 Generator Interconnection Program 38,725 66,292 11,993 11,617 11,126 10,000 149,752 5 Added Facilities Projects 91,255 52,426 32,466 24,290 18,527 18,216 237,182 6 Total System Planning Capital Projects 3,485,445 1,511,959 1,110,426 772,326 519,312 231,101 7,630,569

3

Table I-2 System Planning Capital Projects Expenditure Summary

CPUC Jurisdictional (Nominal $000)

Line No.


1 Transmission & Interconnection Planning Projects 171,450 114,302 44,279 13,239 1,347 55 344,672 2 Load Growth Planning Programs 404,554 178,395 325,627 371,341 265,681 36,452 1,582,051 3 System Improvement/Reinforcement Programs 25,905 122,662 114,032 108,494 101,143 112,746 584,981 4 Generator Interconnection Program 26,873 64,338 11,993 11,617 11,126 10,000 135,947 5 Added Facilities Projects 91,255 52,411 32,466 24,290 18,527 18,216 237,167 6 Total System Planning Capital Projects 720,037 532,109 528,398 528,982 397,823 177,469 2,884,818

B. Electric System Overview 1

Figure I-1 below is a simplified diagram of our electric power system. It shows the flow of 2

electricity from generating plants to end-use customers. I describe the system below. 3

Figure I-1 Simplified System Diagram

4

Generating plants produce electricity and typically interconnect to our high voltage (220 kV2 and 1

500 kV) transmission system. Our transmission system is designed to transfer large quantities of power 2

over long distances to substations that step down voltage to the subtransmission level (66 kV or 115 3

kV). We refer to these kinds of substations as “A-substations.” Our A-substations connect the 4

transmission system to the subtransmission system and are like the off-ramps that move freeway traffic 5

onto main boulevards and thoroughfares. 6

From the A-substations, networks of subtransmission lines (operating at 66 kV and 115 kV) 7

deliver smaller amounts of electricity to substations that we call “B-substations.” These substations 8

step-down voltage from the subtransmission levels (66 kV and 115 kV) to distribution levels (typically 4 9

kV, 12 kV, and 16 kV). This next reduction in voltage allows us to safely move electricity from our 10

subtransmission lines to distribution circuits, similar to traffic signals that direct automobiles from main 11

boulevards and thoroughfares onto neighborhood streets. 12

From the B-substations, primary distribution circuits (typically operating at 4 kV, 12 kV, or 16 13

kV) deliver electricity over localized areas to service transformers mounted overhead on utility poles or 14

placed at ground level. These service transformers provide the final voltage reduction on our system, 15

stepping down voltage to the levels used by our customers (e.g., 120/240 volts for single-phase service 16

to residential customers). This last reduction in voltage allows us to safely “package” electricity for its 17

final delivery to consumers. From the low voltage side of our service transformers, secondary 18

conductors carry electricity directly to customers’ electric panels and billing meters through a service 19

connection. 20

At all levels of our electric power system, capacitor banks are used to supply needed reactive 21

power to our system and help maintain voltage at adequate levels. These capacitor banks may be 22

installed inside substations (at our A-substations and B-substations) or directly connected to our 23

distribution circuits. 24

Collectively, these facilities form a continuous pathway to deliver electricity from generating 25

plants to end-use customers. Just as a chain is only as strong as its weakest link, the reliability of our 26

electric system is only as strong as its weakest component. The failure of any link in the chain could 27

result in the interruption of service to customers. 28

2 kV is an abbreviation for “kilovolts” or one thousand volts. See workpaper entitled “Electrical Abbreviations” for a list

of commonly used abbreviations (and their corresponding definitions) that appear throughout this testimony and corresponding workpapers.

5

To maintain service reliability as the demand for electricity increases, we must plan to expand, 1

upgrade, and reinforce all levels of our electric system, including transmission, subtransmission, and 2

distribution assets. By properly planning and executing system expansion projects, we are able to: 3

Preserve employee and public safety by operating our transmission, subtransmission, 4

distribution, and substation facilities within their established loading limits; 5

Maintain sufficient capacity to serve our customers especially during periods of peak 6

demand; 7

Minimize overall costs to our customers by expanding our system in an orderly, proactive 8

fashion rather than an emergency, reactive fashion; and 9

Provide generators the opportunity to connect to our system as required by federal and state 10

regulations. 11

C. 2012 GRC Authorization and Recorded Costs 12

Figure I-2 below shows the capital expenditure authorized in the 2012 GRC and the capital 13

expenditure recorded by the programs discussed in this chapter. As compared to the Commission’s 14

authorization in our 2012 GRC, SCE spent more on the Distribution Substation Program (DSP), DSP 15

Circuits, and Added Facility/Interconnection Facility (AF/IF) projects. Conversely, SCE spent less on 16

Transmission Substation Projects (TSP) and Transmission Projects. In total, SCE was authorized $478 17

million and spent $464 million on the categories of work discussed in this chapter. 18

6

Figure I-2 Comparison of 2012 GRC Authorized and Recorded Expenditure

(Total Company Nominal $000)

$55 $6

($52)

($74) ($1)

$52

($1)

-

100

200

300

400

500

600

2012Authorized

DSP DSP Circuits TSP TransProjects

Circ.Automation

AF/IF Other 2012Recorded

DSP DSP Circuits TSP Trans Projects

Circ. Automation AF/IF Other Diff from Auth

$478$464

The amounts we are authorized and record can vary for a variety of reasons including (1) longer 1

licensing times than initially anticipated, (2) changes in our load growth forecast, and (3) uncertainty 2

regarding authorized spending levels due to the delay in receiving a 2012 GRC decision. When these 3

kinds of things happen, SCE redirects funds among categories of work to account for changes. 4

With regard to DSP, SCE recorded capital expenditures of approximately $145 million in 2012 5

as compared to $89 million authorized by the Commission. However, SCE still had to expend at a level 6

similar to its forecast and thus recorded more than authorized. Conversely, we spent less on TSP and 7

Transmission projects. This was driven primarily by project delays and changes in project operating 8

dates. For example, the Alberhill Project recorded less capital expenditure in 2012 than we initially 9

forecast. This was caused by delays in the licensing process. Table I-3 below shows projects included 10

in the 2012 GRC that have been delayed into the 2015-2017 timeframe. Some of these changes are 11

because of our new planning process described below and others are due to permitting and construction 12

delays. 13

7

Table I-3 Operating Date Changes for Projects Included in 2012 GRC

to Current 2015-2017 Forecast

ProjectNumber (PIN)

Project Name2012 GRC

ODCurrent

OD

Transmission Substation Plan - A Bank06824 La Fresa 220/66 kV Substation 6/1/2012 12/31/201506670 Valley 500/115 kV Substation 2/1/2014 3/1/201606107 Saugus 220/66 kV Substation 6/1/2013 6/1/201706092 Alberhill 500/115 kV Substation 6/1/2014 6/1/2017

Transmission Substation Plan - Subtransmission Lines06030 Valley-Ivyglen 115 kV 6/1/2012 12/31/201504891 Arrowhead Reconfiguration Project 12/31/2012 12/31/201505329 Moorpark-Newbury 66 kV 6/1/2011 6/1/201604518 Goleta 220 kV N-2 Line Contingency 6/1/2012 6/1/2016

Distribution Substation Plan (DSP)05403 Colonia 66/16 kV Substation 6/1/2013 6/1/201505411 Lakeview 115/12 kV Substation 6/1/2013 6/1/201606619 Banducci 66/12 kV Substation 6/1/2013 6/1/2016

In 2012, SCE began a program called “Operational Excellence” aimed at making our operations 1

more efficient. As described in Mr. Mead’s testimony in Exhibit SCE-03, Volume 1, two of the 2

Operational Excellence initiatives transformed our load growth planning methods. This resulted in 3

fewer major load growth projects and more miscellaneous work on distribution circuits. Specifically, 4

we began considering available capacity over a wider area and improved the accuracy in the way we 5

analyze area temperatures. 6

The capacity planning optimization effort focused on increasing the use of existing assets by 7

establishing processes and tools that allow system planners to evaluate available capacity within a wider 8

planning area. This involved utilizing existing infrastructure to balance electric power from highly 9

loaded substation and circuits to less loaded substations and circuits. The objective is to more uniformly 10

utilize adjacent substations and circuits in a given area. Although this approach can only balance 11

utilization over a specific area, the change in our method has eliminated projects or reduced project scale 12

for our load growth plan. 13

As a summer peaking utility, our load growth plan is driven in part by an analysis of historical 14

temperatures in an area. We have incorporated changes in the tools we use for this analysis that allow 15

system planners to perform more rigorous statistical analysis of temperatures. We have also begun 16

using more years of history in our data set. This allows us to better normalize peak load data and to 17

8

more accurately forecast loading during heat storms. The result of these changes is an improvement in 1

our ability to plan for load growth. 2

D. Planning Process 3

1. Overview of Project Planning 4

Two groups plan the projects in this chapter, Transmission & Interconnection Planning 5

(TIP) and Distribution Engineering. TIP is responsible for 220 kV and 500 kV transmission projects, 6

transmission voltage substation projects, and certain projects on our subtransmission (66 kV and 115 7

kV) system. The projects planned by TIP are on the portion of SCE’s system under operational control 8

of the California Independent System Operator (CAISO).3 9

TIP’s projects include those developed as part of CAISO’s Comprehensive Transmission 10

Planning Process. As described in Section 24 of the CAISO Tariff, this process identifies projects 11

needed for reliability, projects needed to interconnect large generation, projects needed to meet policy 12

goals, and projects driven by economics.4 As part of CAISO’s planning process, SCE’s transmission 13

plan is designed to facilitate compliance with NERC, WECC, and CAISO system performance 14

requirements. These requirements include the NERC Transmission Planning standards,5 the WECC 15

Regional Business Practice document entitled “TPL-001-WECC-RBP,”6 and the California ISO 16

Planning Standards. Lastly, SCE maintains and follows its own transmission planning standards, which 17

reference the regulatory documents discussed above and describe the technical design components 18

necessary to meet our regulatory compliance obligations. 19

The second group, Distribution Engineering, is responsible for projects on the portion of 20

the system not controlled by the CAISO. This includes certain subtransmission projects, distribution 21

voltage level substation projects, and distribution circuit work.7 Distribution Engineering uses electrical 22

3 California Independent System Operator Corporation, Fifth Replacement FERC Electric Tariff, (available at

http://www.caiso.com/rules/Pages/Regulatory/Default.aspx).

4 California Independent System Operator Corporation, Fifth Replacement FERC Electric Tariff, (available at http://www.caiso.com/rules/Pages/Regulatory/Default.aspx).

5 North American Energy Reliability Corporation (NERC) Reliability Standards are available at www.nerc.com and describe the design and operating requirements for transmission systems.

6 Western Electricity Coordinating Council (WECC), System Performance TPL-001-WECC-RBP-2, December 2011. (Available at www.wecc.biz).

7 Subtransmission voltages are 66 kV and 115 kV. Typical distribution voltages on SCE’s system include 16 kV, 12 kV, and 4 kV.

9

facility peak loading data, load growth forecasts, and forecasted additions to our system to develop 1

projects to support reliable, safe delivery of service. Distribution Engineering’s plan also incorporates 2

data about third party generators. 3

These engineers plan projects to mitigate existing or expected violations of SCE’s 4

loading thresholds. They evaluate whether or not our facilities will exceed their rating under normal and 5

abnormal conditions. If we find that our existing facilities cannot meet projected demand, we must 6

develop a mitigation plan to maintain system reliability. Mitigation might be as simple as upgrading an 7

existing circuit to transfer load from one substation to another or as complicated as greenfield 8

construction of a new large substation. 9

Whether projects are developed under the processes managed by TIP or by Distribution 10

Engineering, the project sponsor develops a preliminary scope and cost for the project. This scope and 11

cost are then reviewed with various internal stakeholders to validate that the solution is achievable and 12

can be accomplished in the manner planned. In most cases, primary and alternative projects are 13

developed. 14

Once approved, the appropriate design and execution groups take over the project.8 In 15

addition, SCE determines whether or not a project needs to be licensed under G.O. 131-D.9 Larger 16

projects are managed by the Major Projects Organization (MPO) through licensing, design, and 17

construction. During this process, TIP and Distribution Engineering remain engaged to make sure the 18

final project meets the original intent and need. 19

2. Transmission Planning Processes 20

SCE performs an Annual Transmission Reliability Assessment (ATRA) for its portion of 21

the California Independent System Operator (CAISO) controlled grid. The purpose of this assessment is 22

to: 23

Evaluate the performance of the SCE transmission system under peak and off-peak 24

conditions for near-term and longer-term planning horizons;10 25

Determine transmission constraints, if any, under stressed system conditions;11 and 26

8 SCE organizes its work into a few categories. Work might be managed by Technical Planning, Substation Engineering,

or Transmission Planning.

9 Rules Relating to the Planning and Construction of Electric Generation, Transmission,/Power/Distribution Line Facilities and Substations Located in California, General Order 131-D (1995).

10 For planning horizons, “near-term” refers to one- to five-years-out while “longer-term” refers to six- to ten-years-out.

10

Identify upgrades needed to maintain reliability of the transmission system and 1

comply with FERC approved NERC Reliability Standards, WECC approved 2

Regional Criteria, CAISO Planning Standards, and SCE Transmission Planning 3

Criteria. 4

The ATRA is performed in coordination with the CAISO in accordance with the 5

CAISO’s FERC jurisdictional tariff12 and NERC Reliability Standards. SCE also performs the ATRA in 6

parallel with the CAISO’s annual comprehensive Transmission Planning Process and can be described 7

in 6 stages. Figure I-3 below illustrates the ATRA process. 8

Figure I-3 SCE Reliability Planning Process

3. Generator Interconnection Process 9

SCE facilitates the CAISO generator interconnection process to assist power plants to 10

interconnect to SCE’s CAISO-controlled grid. For a comprehensive reference of CAISO’s process and 11

Continued from the previous page 11 “Stressed system conditions” refers to an instance of the electric grid when there is maximum transmission line loading.

12 California Independent System Operator Corporation, Fifth Replacement FERC Electric Tariff, May 2013, (available at http://www.caiso.com/Documents/CombinedConformedTariff-May1_2013.pdf).

11

requirements, please refer to CAISO’s business practice manual and procedures found on their 1

website.13 2

SCE’s Generation Interconnection Planning group performs its Phase 1 and Phase 2 3

studies in coordination with the CAISO in accordance with the CAISO’s FERC jurisdictional tariff14 and 4

NERC Reliability Standards. The SCE Generator Interconnection Process is illustrated in Figure I-4 5

below. 6

Figure I-4 SCE Generation Interconnection Planning Processes

4. Load Growth Planning Process 7

Capital projects necessary to serve new load added to the system are identified through an 8

annual planning process. This process uses technical studies that determine the system requirements to 9

serve projected load growth. The major steps in the planning process for all of the load growth planning 10

programs are described below. 11

a) Development Of Peak Load Forecasts 12

The first step in our planning process is to develop peak load forecasts for all of 13

our distribution circuits, B-substations, and A-substations. Our forecasts cover the next 10 years and are 14

13 California Independent System Operator Corporation, Business Practice Manual for Generator Interconnection

Procedures, (available at http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx).

14 California Independent System Operator Corporation, FERC order 1000 compliance phase 1 - tariff, (available at http://www.caiso.com/informed/Pages/StakeholderProcesses/FERCOrder1000Compliance.aspx).

12

developed using a bottom-up approach.15 To build the load forecasts, we consider historical growth 1

rates, local economic conditions, and development plans.16 2

We also incorporate the effects of new lighting standards, SmartConnect Meters, 3

increased electrical demand associated with Plug-in Electric Vehicles (PEV), and distributed generation. 4

This information, gathered from a variety of sources, is synthesized to produce our forecast for each 5

distribution circuit, B-substation, and A-substation in our system. 6

Our forecast incorporates two specific energy efficiency factors. The first is the 7

effects of the Huffman Bill (AB 1109) which encouraged the use of more energy efficient lighting.17 8

The second factor is the effect of Edison SmartConnect meter deployment. We expect that customers 9

will reduce usage with the greater transparency that SmartConnect provides. We anticipate both of these 10

factors to reduce future load growth. 11

We also expect increasing use of PEVs to increase load on our system. In the 12

2012 GRC filing, capital investment due to PEV load growth was forecasted separately.18 Subsequently, 13

we began including PEV load directly into our load growth forecast. The PEV forecast used in this 14

filing is documented in Mr. Kjaer’s Integrated Planning & Environmental Affairs testimony in Exhibit 15

SCE-09, Volume 2. 16

SCE has also incorporated the effects of distributed generation in our load 17

forecast.19 In 2012, SCE has evaluated how much photovoltaic distributed generation can be reasonably 18

relied on to offset load peak conditions. SCE's study determined that the amount of photovoltaic 19

generation that can be considered dependable varies with the time of day. For example, our study 20

showed that at noon approximately 17 percent of nameplate capacity can be considered dependable, 21

while approximately two percent of nameplate capacity can be considered dependable at 5:00 PM. We 22

use the information produced by the study to adjust peak loads and forecast loads for our planning 23

15 Our aggregated B-substation load forecast for the 2013-2022 period under the “likely case” scenario is 1.53 percent per

year, although we expect differences station to station.

16 These plans come from municipalities in our service territory, developers, large commercial customers, and industrial customers.

17 AB 1109 (Huffman) Lightning Efficiency & Toxics Reduction Act, October 2007.

18 D.12-11-051, p. 144.

19 Distributed generation in our forecast was the subject of a settlement SCE reached with the Vote Solar initiative. This settlement and SCE’s actions to meet its terms are discussed later in this exhibit.

13

process. In making this adjustment, we consider the time of day when the peak occurs and the 1

dependable generation at that time. 2

The result of our planning is a forecast of peak loads through all of our 3

distribution circuits, B-substations, and A-substations.20 This forecast is the basis of our load growth 4

plan.21 5

b) Identification Of System Requirements 6

The next step is to perform technical studies that determine whether peak load 7

around the system can be accommodated using existing transmission, subtransmission, distribution, and 8

substation facilities. We also determine whether, under peak loading condition, we can maintain 9

acceptable system reliability. 10

We use planning criteria as the basis for designing a reliable system. We consider 11

loading limits for system facilities under normal and contingency conditions based on manufacturer 12

equipment limitations and thermal loading characteristics. Loading limits are also compared to load 13

forecasts for each year in our 10-year plan considering potential heat storm conditions during that 14

period. 15

When our analysis indicates load will exceed loading limits, we identify potential 16

projects to mitigate violations of our planning criteria. These projects are necessary to minimize the risk 17

of overloading equipment, which increases the risk of failures (like transformer fires) and service 18

interruptions that might impact many customers over widespread geographic areas. 19

For example, if we forecast that a particular B-substation will be at 103 percent of 20

capacity in the year 2016, our distribution engineers will develop a plan to mitigate that violation of our 21

criteria. In planning, we consider the most cost effective way to mitigate overloads within reasonable 22

operating constraints. We first consider utilizing existing infrastructure to balance loading between area 23

substation and circuits. If that is not possible, we consider upgrading existing facilities to transfer load 24

to adjacent substations. In some cases, the appropriate alternative is the addition of a new transformer to 25

an existing substation or, possibly, a new B-substation altogether. 26

20 In rare cases, SCE also develops high case based scenarios to avoid deferring projects that require licensing and long

lead times. Deferring these projects can increase costs and prevent SCE from deliver the most cost effective solution.

21 The bottoms-up forecast is compared to SCE’s top-down ESM forecast as discussed in Mr. Cushnie's testimony in Exhibit SCE-02, Volume 4. Once developed, these forecasts are compared and any difference are analyzed.

14

In D.12-11-051, the Commission directed SCE to include in this filing “an 1

estimate of unused distribution capacity for the test year, and address it in connection with SCE’s 2

forecast Load Growth during the rate cycle at issue.”22 To estimate this capacity, we have summed the 3

differences between the capacity of each Parent B-Substation in the system and the forecast load on that 4

station in the test year.23 Our system is currently approximately 77 percent utilized. 5

However, this calculation cannot be used in planning capacity additions. For 6

example, consider two similarly sized substations; one substation in northernmost part of our system 7

might be at 110 percent utilization, while a substation in the southernmost part of our system might be at 8

80 percent utilization. This aggregates to 95 percent using the calculation described above. However, 9

geographic constraints and current location of distribution facilities prevent us from using the southern 10

substation to serve load in the north. Therefore capacity is still needed at the overloaded northern 11

substation. To properly plan our system, we must examine loading and capacity on a facility by facility 12

basis. 13

In addition, this utilization calculation is influenced by the fact that capacity can 14

only be added in discrete quantities. Typically, a capacity increase involves adding one new transformer 15

to a substation. For our B substations, these transformers are typically 28 MVA of capacity.24 If a 16

station is overloaded by 5 MVA, we would add a new 28 MVA transformer. Immediately after this 17

addition, a calculation like the one above would show 23 MVA of “unused capacity” at this substation. 18

This is reflected in the system utilization calculation. Therefore, the aggregated system utilization is 19

misleading. 20

c) Development of Alternatives and Project Selection 21

Where our load forecast indicates loading limits will be exceeded, we identify 22

potential projects to address that. In doing so, we identify and evaluate project alternatives, considering 23

a range of options, including load balancing between substations, new circuits, and substation capacity 24

increases. 25

22 See D.12-11-051, at pp. 19-20.

23 In this case, Parent B-Substations are those that are directly downstream from an A-Substation. Some of our B-Substations are served from Parent B-Substation and are defined as Child B-Substations. If we were to include the capacity and load through these stations, we would be double counting. For this reason, we have only considered Parent B-Substation in our calculation.

24 MVA stands for mega volt-amperes and is a measure of power transfer capacity. One MVA is equal to 1 MW at a power factor of 1.

15

As mentioned previously, we review the technical feasibility of each alternative 1

with various internal stakeholders responsible for design, construction, operation, and maintenance of 2

the project. Using stakeholder input, we eliminate alternatives that are not technically feasible. From 3

the feasible set of alternatives, we select a project considering reliability, operational flexibility, and cost 4

effectiveness. 5

5. Construction Licensing under G.O. 131-D 6

SCE is required to comply with the licensing provisions of General Order 131-D (G.O. 7

131-D) before constructing electric facilities operating at voltages greater than 50 kV.25 During SCE’s 8

last GRC proceeding, the Commission disallowed some of SCE’s Distribution Substation Plan and 9

Subtransmission Line capital forecast because “there was insufficient data [on construction authority] to 10

timely evaluate whether the projects were likely to come into service during [the] rate case cycle.”26 11

Table I-4, Table I-5, and Table I-6 below contain licensing and exemption information 12

for each of these projects. In addition to identifying the projects for which Certificate of Public 13

Convenience and Necessity (CPCN)27 or Permit to Construction (PTC)28 applications have already been 14

filed pursuant to G.O. 131-D, a review of the remaining listed projects was made to determine (1) the 15

need for a CPCN or PTC application to be filed pursuant to G.O. 131-D, (2) whether a project could 16

qualify for an exemption under G.O. 131-D, or (3) whether a project was subject to the G.O. 131-D 17

provisions. The determinations regarding the application and exemption status for the projects in our 18

current load growth plan are provided in Table I-4 below. 19

Based on these determinations, the planned projects fall into four primary categories. 20

First, there are those projects for which a CPCN29 or PTC30 has already been filed. Second, there are 21

those projects for which SCE currently expects a CPCN or PTC to be filed. Third, there are those 22

projects which are considered exempt under the provisions of G.O. 131-D, Section III.B.1. (e.g., a 23

25 Rules Relating to the Planning and Construction of Electric Generation, Transmission,/Power/Distribution Line Facilities

and Substations Located in California, General Order 131-D (1995).

26 D.12-11-051, at 142.

27 General Order 131-D, Section A.

28 See Id. Section B.

29 CPCNs are required for projects involving construction of transmission line facilities operating at 200 kV or greater.

30 PTCs are required for projects involving construction of subtransmission line facilities operating between 50 kV and 200 kV and substations operating above 50 kV.

16

project involving construction for the minor relocation of existing power lines facilities up to 2,000 in 1

length may qualify for a PTC exemption under G.O. 131-D, Section III.B.1.c.). Lastly, there are those 2

projects known as “substation modification” projects31 which are not subject to PTC requirements 3

because they involve construction within an existing substation that does not exceed the substation’s 4

previously rated voltage. 5

31 See Id. Section B.

17

Table I-4 Licensing and Exemption Status

Distribution Substation Plan

Line No.

Project # Project NameOperating

DatePreliminary Licensing

Determination

1 05353 Triton 115/12 kV Substation Apr 2013 PTC Already Filed

2 04458 Pepper 115/12 kV Substation Jun 2013 Substation Modification

3 05023 El Sobrante 33/12 kV Substation Jun 2013 Substation Modification

4 05432 Roadway 115/12 kV Substation Jun 2013 Substation Modification

5 06093 Bloomington 66/12 kV Substation Jun 2013 Not Subject to PTC

6 06220 Fillmore 66/16 kV Substation Jun 2013 Substation Modification

7 06577 Devers 115/12 kV Substation Jun 2013 Substation Modification

8 06605 La Habra 66/12 kV Substation Jun 2013 Exemption C

9 06870 Estrella 66/12 kV Substation Jun 2013 Substation Modification

10 06948 Carodean 115/12 kV Substation Jun 2013 Substation Modification

11 07160 Delano 66/12 kV Substation Jun 2013 Substation Modification

12 04445 Glen Avon 66/12 kV Substation Jun 2013 Substation Modification

13 06292 Lampson 66/12 kV Substation Jun 2014 Not Subject to PTC

14 06691 Downs 115/12 kV Substation Jun 2014 PTC Already Filed

15 06958 Pebbly Beach 12/2.4 kV Substation Jun 2014 Not Subject to PTC

16 07216 Del Amo Jr 66/12 kV Substation Jun 2014 Substation Modification

17 07263 La Palma 66/12 kV Substation Jun 2014 Substation Modification

18 07391 Lark Ellen 66/12 kV Substation Jun 2014 Substation Modification

19 05403 Colonia 66/16 kV Substation Jun 2015 Substation Modification

20 06301 Canyon 66/12 kV Substation Jun 2015 Substation Modification

21 07307 San Dimas 66/12 kV Substation Jun 2015 Substation Modification

22 07480 Orange 66/12 kV Substation Jun 2015 Substation Modification

23 05411 Lakeview 115/12 kV Substation Jun 2016 PTC Already Filed

24 06067 Yokohl 66/12 kV Substation Jun 2016 Customer EIR

25 06619 Banducci 66/12 kV Substation Jun 2016 PTC Already Filed

26 06836 Greenhorn 66/2.4 kV Substation Jun 2016 Substation Modification

27 07293 Mainframe 66/4.16 kV Substation Jun 2016 PTC Filing Expected

28 07516 Safari 33/12 kV Substation Jun 2016 Substation Modification

29 06575 Circle City 66/12 kV Substation (Phase 1) Jun 2016 PTC Filing Expected

30 05397 Falcon Ridge 66/12 kV Substation Dec 2016 PTC Already Filed

18


Subtransmission Lines Plan

Line No.



Determination

1 06392 Santiago-Borrego-Morro 66 kV Reconductor Mar 2013 Exemption G

2 06028 Etwiwanda-Alder-Randall 66 kV Reconductor Apr 2013 Exemption G

3 05316 Alder-Declez 66 kV Recable Bundle Jun 2013 Exemption D

4 07040 Camarillo Substation 66 kV Capacitor Bank Jun 2013 Substation Modification

5 05364 Weldon Substation 66 kV Capacitor Bank Dec 2013 Substation Modification

6 06070 Mesa-Laguna Bell-Narrows 66 kV Reconductor Dec 2013 Exemption G

7 06844 Mesa-Rush No. 3 66 kV Recabel Jun 2014 Exemption B & C

8 07208 Carodean Substation 115 kV Capacitor Bank Jun 2014 Substation Modification

9 Multiple La Cienega Subtransmission Line Project Jun 2015 Exemption G

10 07507 Springville-Strathmore 66 kV Reconductor Jun 2015 Exemption G

11 07508 Vestal-Columbine-Delano-Earlimart 66 kV Reconductor Jun 2015 Exemption G

12 07512 Vestal-Delano-Browning 66 kV Reconductor Jun 2015 Exemption G

13 04891 Arrowhead Reconfiguration Project Dec 2015 Exemption B

14 06030 Valley-Ivyglen 115 kV Line Dec 2015 PTC Already Filed

15 04518 Santa Barbara County Reliability Project Jun 2016 PTC Already Filed

16 05329 Moorpark-Newbury 66 kV Line Jun 2016 Expecting to File

17 07382 Yucca 115/12 kV Substation Loop-In Jun 2016 Exemption G

18 07384 Santiago-Irvine No. 2 66kV Recable Jun 2016 Exemption B

19


A-Bank Plan

Line No.



Determination

1 05075 El Casco 220/115 kV Substation Jun 2013 PTC Already Filed

2 05360 Devers-Mirage 115 kV System Split Jun 2013 PTC Already Filed

3 06807 Valley 'C' 500/115 kV Substation Jun 2013 Substation Modification

4 06221 Ellis 'C' 220/66 kV Substation Jun 2013 Substation Modification

5 06845 Gould 220/66 kV Substation Nov 2013 Substation Modification

6 06227 Santiago 220/66 kV Substation Dec 2013 Substation Modification

7 06284 La Cienega 220/66 kV Substation Jun 2014 Substation Modification

8 06824 La Fresa 220/66 kV Substation Dec 2014 Exemption G

9 06263 Vestal 220/66 kV Substation Jun 2015 Substation Modification

10 07518 Springville 220/66 kV Substaiton Jun 2015 Substation Modification

11 06670 Valley 'AB' 500/115 kV Substation Mar 2016 Substation Modification

12 06092 Alberhill 500/115 kV Substation Jun 2017 CPCN Already Filed13 06107 Saugus 'C' 220/66 kV Substation Jun 2017 Exemption G14 05383 Chino 220/66 kV Substation (Phase 1) Jun 2016 Substation Modification

E. Transmission & Interconnection Planning Projects 1

As discussed earlier, these projects fall into four categories: (1) projects needed to support grid 2

reliability, (2) projects needed to interconnect generation, including renewable energy, to SCE’s 3

transmission system, (3) primarily FERC-jurisdictional projects with more than $1 million in CPUC 4

jurisdictional information technology expenditures, and (4) projects with less than $1 million in CPUC-5

jurisdictional expenditures. These projects are discussed below in Table I-7. 6

Table I-7 Transmission & Interconnection Planning Projects Capital Expenditure Summary


Line No.

Project Category Prior 2013 2014 2015 2016 2017 Total CPUC

1 Grid Reliability Projects 94,514 71,497 37,365 4,987 - - 208,362 139,641 2 Transmission System Generation Interconnection 1,756,841 767,990 325,605 113,971 34,123 - 2,998,530 170,208 3 Subtotal of Transmission & Interconnection Projects 1,851,355 839,486 362,970 118,958 34,123 - 3,206,892 309,849 4 Projects with CPUC-jurisdictional SCE Cost <$1M 1,029,285 236,203 217,693 95,976 46,592 32,441 1,658,190 34,824 5 Total 2,880,640 1,075,689 580,662 214,934 80,715 32,441 4,865,082 344,672

1. Grid Reliability Projects 7

Grid reliability projects, such as those described below, are necessary to provide reliable 8

service to our customers as the demand for electricity increases in our service territory and to provide 9

20

continuity of service under various system conditions, including abnormal system conditions.32 Without 1

these improvements to our transmission system, the reliability and safety of SCE’s electric grid would 2

potentially degrade, which compromises SCE’s ability to adequately serve its customers and can 3

potentially endanger SCE employees and the public. 4

Table I-8 below, contains a list of the Grid Reliability projects that have over $1 million 5

in CPUC-jurisdictional capital expenditures and are expected to be completed and operational by the end 6

of 2017. 7

Table I-8 Grid Reliability Projects Expenditure Summary


Line No.


DatePrior 2013 2014 2015 2016 2017 Total CPUC

1 07104 BC/SJV RAS Expansion Jun 2013 1,448 134 - - - - 1,582 1,582 2 06477 Victor 220/115 kV Substation Oct 2013 60,706 2,209 - - - - 62,915 13,506 3 06714 Rio Hondo 220/66 kV Substation Oct 2013 13,291 1,026 - - - - 14,317 8,394 4 06685 East Kern Wind Resource Area (EKWRA) Jun 2014 16,447 66,834 32,325 - - - 115,606 113,458 5 07243 Devers 115 kV SPS Jun 2014 - 138 1,970 - - - 2,108 2,108 6 07111 La Cienega 220/66 kV Substation Dec 2014 2,620 820 595 - - - 4,036 202 7 07518 Springville 220/66 kV Substation Jun 2015 - - 2,131 2,176 - - 4,307 215 8 07120 Chino 220/66 kV Substation Dec 2015 - 336 344 2,811 - - 3,491 175 9 Total Grid Reliability Projects 94,514 71,497 37,365 4,987 - - 208,362 139,640

Eight projects have been identified with CPUC-jurisdictional project costs equal 8

to or greater than $1 million. A description and justification for each of these projects is provided 9

below. The total cost for these eight projects is $208.362 million. The CPUC-jurisdictional cost for 10

these projects is $139.640 million, of which $101.040 million is from 2013 to 2017. 11

(1) BC/SJV RAS Expansion (Project #07104) 12

The Big Creek/San Joaquin Valley transmission corridor serves the cities 13

of Hanford, Tulare and Visalia. Load growth in this area has resulted in the need to modify the existing 14

Big Creek/San Joaquin Valley Remedial Action Scheme (BC/SJV RAS). The project includes the 15

installation of protective relays in the Mechanical Electrical Equipment Room (MEER) at both Rector 16

and Liberty Substations. The telecommunication scope of work includes installing redundant 17

communication paths between Rector and Liberty Substations. Without this project, SCE projects 18

loading on the Big Creek 1-Rector 220 kV line, Big Creek 3-Rector 220 kV line, and Magunden-Vestal 19

32 Abnormal conditions include, for example, planned facility outages for maintenance, unplanned facility outages due to

equipment failures, and facilities removed from service as a result of a fault on the system.

21

No. 1 and 2 220 kV lines to exceed their capacity under N-2 line outage conditions. Under an N-2 1

condition, SCE forecasts the lines will exceed their emergency rating by as much as 103 percent in 2

2013. 3

The operating date is June 2013 with a total project cost of $1.582 million 4

all of which is CPUC jurisdictional.33 5

(2) Victor 220/115 kV Substation (Project #06477) 6

Victor Substation is located in the city of Victorville. The Victor 3rd A-7

bank and Rebuild of the 115 kV Switchrack Project will increase capacity at Victor Substation in order 8

to meet growing customer demand for electricity and to reconfigure the 115 kV switchrack. 9

Victor Substation has two 220/115 kV transformer banks, numbered as 10

Bank No.1 and Bank No.2, which transform voltages from 220 kV to 115 kV. Because customer load in 11

the area has grown, either Bank No. 1 or Bank No. 2 will be overloaded beyond its allowable long-term 12

emergency loading limits if either bank fails for any reason. As of 2013, if one of the banks fails, the 13

remaining bank would be overloaded to 127 percent of its emergency rating. 14

In addition, the existing 115 kV switchrack configuration is obsolete and 15

must be rebuilt in order provide a proper level of reliability. The term “switchrack” collectively refers to 16

the line and bus configuration and equipment for the for the 115 kV voltage level. This particular rack 17

dates back to 1950, when it was originally built by the California Electric Utility Company. 18

This project is required to meet future load demand at Victor Substation. 19

In addition to the installation of the 3rd A-bank for load growth, the project includes installation of the 4th 20

A-bank for continuity of service to load during construction. Because three banks are required to be in 21

service at all times, a fourth bank was added so that while a bank was disconnected for construction, 22

load service would not be jeopardized. The project also includes the removal of the existing switchrack 23

and construction of a new breaker-and-a half configuration 115 kV switchrack. Phase 1 of the project 24

includes replacement of approximately half of the 115 kV switchrack, installation of two new 220/115 25

kV banks, and relocation of six subtransmission lines into the new portion of the switchrack. Phase 2 26

includes the remainder of the 115 kV switchrack rebuild as well as relocation of remaining elements into 27

the new switchrack. At the completion of the 115 kV switchrack rebuild the 4th A-bank will become an 28

energized spare for the station and remain in its location in the station as well as in the switchrack. 29

33 Refer to workpaper entitled “BC/SJV RAS Expansion (Project #07104).”

22

Because the existing Mechanical Electrical Equipment Room (MEER) is full and additional relays and 1

other equipment are needed for the breakers associated with the new switchrack, a new MEER is 2

needed. The telecommunication scope of work for this project includes the necessary interception of the 3

existing communication circuits and connecting them into the new MEER. 4

The operating date is October 2013 with a total project cost of $62.915 5

million. This includes $13.506 million of CPUC-jurisdictional expenditures.34 6

(3) Rio Hondo 220/66 kV Substation (Project #06714) 7

Rio Hondo Substation is located in the city of Irwindale. SCE will install 8

eight circuit breakers at Rio Hondo Substation. At Rio Hondo Substation, all four of the 220/66 kV 9

transformers were connected directly to the 220 kV buses without breakers. Sectionalizing breakers 10

were inserted in the middle of each bus as a means of separating each transformer such that a bus outage 11

would not result in loss of half of the station transformation capacity. 12

Today, SCE recognizes the difficulties of managing operations and 13

maintenance with this practice, especially at higher load levels compared with past years. Back-up 14

clearing of a fault is a situation where a primary breaker fails to open, necessitating a number of 15

breakers to open which can result in removal of large sections of a substation from operation, which is a 16

situation that can significantly reduce reliability. 17

As part of a system-wide effort to improve reliability and restore 18

operational flexibility and maintainability, SCE initiated a program for all 220/66 kV transformers that 19

are currently connected directly to the bus as described above to connect into either a “double-breaker” 20

or “breaker-and-a-half” position, as appropriate. These breaker arrangements maintain electrical 21

connection of the transformers for faults on other substation equipment and prevent removal of large 22

sections of a substation from operation. 23

The scope of the project includes installing eight higher rated circuit 24

breakers at Rio Hondo Substation. Because system short circuit duties overall are slowly increasing 25

over time, the new breakers being installed will be capable of interrupting 40 kA of short circuit duty. 26

The operating date is October 2013 with a total project cost of $14.317 million. This includes $8.394 27

million of CPUC-jurisdictional expenditures.35 28

34 Refer to workpaper entitled “Victor 220/115 kV Substation (Project #06477).”

35 Refer to workpaper entitled “Rio Hondo 220/66 kV Substation (Project #06714).”

23

(4) East Kern Wind Resource Area (EKWRA) (Project #06685) 1

East Kern Wind Resource Area (EKWRA) 66 kV Reconfiguration Project 2

will separate the existing Antelope-Bailey 66 kV subtransmission system into two systems. Studies on 3

service-to-load and deliverability of local generation identified three criteria violations: (a) base case 4

overload; (b) single contingency overload; and (c) voltage criteria violation for single contingency at the 5

EKWRA. To mitigate these criteria violations, local generation and load in the Antelope-Bailey 66 kV 6

system will be transferred to WindHub substation. The EKWRA 66 kV Reconfiguration Project will 7

separate the existing Antelope-Bailey 66 kV subtransmission system into two systems. 8

The EKWRA includes both SCE customers as well as numerous wind 9

generation projects. This area also includes the approximate geographic area between the towns of 10

Tehachapi to the town of Mojave. The electric system serving this general area today is part of the 11

CAISO controlled Antelope-Bailey 66 kV system. The Antelope-Bailey 66 kV system has experienced 12

operational, and reliability challenges caused by growing load in the southern portion of the system and 13

the increasing production capability of existing renewable resources in the northern portion of this 14

system. 15

The EKWRA 66 kV Reconfiguration Project will separate the existing 16

Antelope-Bailey 66 kV system into two systems: the EKWRA 66 kV system and the Antelope-Bailey 17

66 kV system. The reconfigured electric system serving customers and generators in the EKWRA will 18

be served radially from SCE’s new Windhub Substation and as such will not be under CAISO control. 19

The reconfigured Antelope-Bailey 66 kV electric system that serves the 20

general area of the city of Lancaster and Palmdale will remain parallel to the 220 kV system at Antelope 21

and Bailey Substations and will retain the label of the Antelope-Bailey 66 kV system. The north-to-22

south lines that once connected EKWRA to the Antelope-Bailey 66 kV system will be opened. The 23

project will segregate the EKWRA northern system from the Antelope-Bailey 66 kV System and 24

connect it to the Windhub substation. Windhub Substation will be a new source bus located directly in 25

the middle of the northern system. 26

Finally, the Antelope-Bailey 66 kV System is in parallel with the 220 kV 27

system at Antelope and Bailey Substations through two 66 kV subtransmission lines. By virtue of 28

opening a single 66 kV breaker at Neenach Substation, the final step to create two radial 66 kV systems 29

from Antelope and Bailey 220 kV Substations can be accomplished. This last step will be taken when 30

operationally convenient and necessary. When this step occurs, SCE expects that the two new radial 66 31

24

kV systems would no longer be under the CAISO’s operational authority, nor would the facilities remain 1

under FERC. Instead, they would move into SCE operational authority and would become CPUC-2

jurisdictional. The EKWRA Project was approved by the CAISO in March 2010. The project plans to 3

install two new 230/66 kV 280 MVA transformer bank, three 28.8 MVAR capacitors, and eighteen 4

miles of new/reconductored cable. 5

The operating date is June 2014 and the total project cost is estimated to 6

be $115.606 million of which $113.458 million is CPUC jurisdictional.36 7

(5) Devers 115 kV SPS (Project #07243) 8

The Devers 115 kV special protection system (SPS) is necessary to 9

maintain electric system reliability and protect 115 kV subtransmission facilities in the Palm Springs 10

area. 11

The project is necessary to mitigate thermal overload conditions on the 12

Devers-Eisenhower-Thornhill, Devers-Farrell-Windland, Devers-Garnet, and Farrell-Garnet 115 kV 13

lines under N-2 line outage conditions. 14

The project includes the installation of protective relays and associated 15

equipment to support the SPS in the Mechanical Electrical Equipment Rooms (MEER) at Eisenhower, 16

Farrell, Garnet, Thornhill, and Devers Substations. The telecommunication scope of work includes 17

installing redundant communication paths and associated equipment between the aforementioned 18

substations. The operating date is June 2014 with a total project cost of $2.108 million, which is 100 19

percent CPUC-jurisdictional expenditures.37 20

(6) La Cienega 220/66 kV Substation (Project #07111) 21

La Cienega Substation is located in Culver City. SCE will install four 22

circuit breakers at La Cienega Substation. At La Cienega Substation, two 220/66 kV transformers are 23

connected directly to the buses without breakers. This substation was originally constructed in this 24

arrangement a number of years ago when SCE used fewer breakers per element. 25

SCE recognizes the difficulties of managing operations and maintenance 26

with this practice, especially at the higher load levels SCE now has. Back-up clearing of a fault is a 27

situation in which a primary breaker fails to open, necessitating a number of breakers to open. This can 28

36 Refer to workpaper entitled “East Kern Wind Resource Area (EKWRA). (Project #06685).”

37 Refer to workpaper entitled “Devers 115 kV SPS (Project #07243).”

25

then lead to an outage of large sections of a substation from operation, which significantly reduces 1

reliability. 2







The scope of the project includes installing four-220 kV circuit breakers at 9

La Cienega 220 kV Substation to connect the two 220/66 kV transformers to the 220 kV buses. The 10

operating date is December 2014 with a total project cost of $4.036 million. This includes $0.202 11


(7) Springville 220/66 kV Substation (Project #07518) 13

Springville Substation is a 220/66 station located in the city of Strathmore. 14

SCE will install four circuit breakers at Springville Substation. At Springville Substation, one 220/66 15

kV transformer is connected directly to the bus without breakers. SCE recognizes the difficulties of 16

managing operations and maintenance with this practice, especially at higher load levels compared with 17

past years. Back-up clearing of a fault is a situation where a primary breaker fails to open, necessitating 18

a number of breakers to open which can result in an outage of large sections of a substation, which can 19

reduce reliability. 20







The scope of the project includes replacing two single-phase 220/66kV 27

transformer banks with one new 220/66kV three phase transformer bank. The new transformer bank 28

will be connected to the 220kV buses through two new 220 kV circuit breakers. The two-66kV circuit 29

38 Refer to workpaper entitled “La Cienega 220/66 kV Substation (Project #07111).”

26

breakers that connect the 220/66kV transformer to the 66 kV buses will also be replaced. The existing 1

ground bank will be relocated and installed with the new transformer. The operating date is June 2015 2

with a total project cost of $4.307 million, which includes $0.215 million of CPUC-jurisdictional 3

expenditures.39 4

(8) Chino 220/66 kV Substation (Project #07120) 5

Chino Substation is a 220/66 station located in the city of Chino. SCE 6

will install four circuit breakers at Chino Substation. At Chino Substation, one 220/66 kV transformer 7

and the Chino-Mira Loma No. 1 220 kV transmission line are connected directly to the bus without 8

breakers. 9

SCE recognizes the difficulties of managing operations and maintenance 10

with this practice, especially at higher load levels compared with past years. Back-up clearing of a fault 11

is a situation where a primary breaker fails to open, necessitating a number of breakers to open which 12

can result in an outage of large sections of a substation, which can reduce reliability. 13







The scope of the project includes installing four-220 kV circuit breakers at 20

Chino 220 kV Substation to connect the 220/66 kV transformer and Chino-Mira Loma No. 1 21

transmission line to the 220 kV buses. Since there is insufficient space in the existing dilapidated 22

control room, two new Mechanical Electrical Equipment Rooms (MEER) are required in order to install 23

the additional protective relays and equipment associated with the new circuit breakers. These two new 24

MEER include a new 220/66 kV MEER and a 12 kV MEER. All new equipment will be installed in 25

this new MEER to replace the existing aged equipment in the control room. 26

The operating date is December 2015 with a total project cost of $3.491 27


39 Refer to workpaper entitled “Springville 220/66 kV Substation (Project #07518).”

40 Refer to workpaper entitled “Chino 220/66 kV Substation (Project #07120).”

27

2. Transmission System Generation Interconnection Projects 1

SCE is obligated under the Federal Power Act and the CAISO Tariff to interconnect and 2

integrate renewable generation facilities. The CPUC, which regulates Investor-Owned Utilities (IOUs) 3

like SCE, has an objective to facilitate the construction of transmission facilities that will advance 4

California’s Renewable Portfolio Standard (RPS) goals. 5

The Tehachapi Renewable Transmission Project demonstrates how SCE accomplishes 6

this by meeting the following three goals. The first goal is to interconnect and integrate privately-7

developed wind energy generators located in the Antelope Valley and Tehachapi areas of north Los 8

Angeles and south Kern County, collectively referred as the Tehachapi Wind Resource Area (TWRA), 9

into the SCE electrical grid. The second goal is to enable California utilities to comply with the state 10

mandated RPS goals by providing improved access to renewable resources in the TWRA. The third 11

goal is to address the load serving reliability needs of the CAISO controlled grid due to projected load 12

growth in the Antelope Valley as well as projected South of Lugo power transfer increases associated 13

with load growth in Southern California. Table I-9 below, contains a list of the renewable 14

interconnection projects that have over $1 million in CPUC-jurisdictional capital expenditures and are 15

expected to be completed and operational by the end of 2017. 16

Table I-9 Transmission System Generation Interconnection Projects Expenditure Summary


Line No.

Project #

Project NameOperating

DatePrior 2013 2014 2015 2016 2017 Total CPUC

1 06960 Sandlot 220 kV Substation Apr 2013 30,706 19,397 - - - - 50,103 46,799 2 06551 Eldorado Ivanpah Transmission Upgrades Jul 2013 157,643 176,550 50,317 - - - 384,511 10,244 3 04847 Devers - Colorado River (DCR) Sep 2013 522,823 242,181 94,970 - - - 859,974 8,819 4 06929 Red Bluff 500/220 kV Substation Dec 2013 146,857 85,488 1,669 - - - 234,014 7,673 5 06438 Tehachapi Renewable Transmission Project - Seg. 7 Jan 2015 155,754 22,610 25,448 3,322 - - 207,134 34,061 6 06439 Tehachapi Renewable Transmission Project - Seg. 8 Mar 2015 269,010 67,768 72,246 24,086 - - 433,110 32,804 7 07183 Tehachapi Renewable Transmission Project - Seg. 3B Dec 2012 63,500 2,750 - - - - 66,250 2,995 8 05243 Tehachapi Renewable Transmission Project - Seg. 6 Nov 2013 136,920 105,855 25,609 13,329 9,531 - 291,244 1,646 9 06440 Tehachapi Renewable Transmission Project - Seg. 9 Dec 2013 270,636 21,473 6,536 - - - 298,645 6,240

10 07061 Colorado River Corridor SPS Jun 2015 183 100 100 2,393 - - 2,775 282 11 06902 Jasper 220 kV Substation Oct 2015 1,178 1,553 9,352 43,571 1,350 - 57,005 11,056 12 07426 Primm 220 kV Substation Oct 2015 257 2,436 16,644 6,277 - - 25,614 6,100 13 07067 Whirlwind #2AA and #3AA Bank Upgrades Dec 2016 1,373 19,827 22,713 20,993 23,243 - 88,150 1,487 14 Total 1,756,841 767,990 325,605 113,971 34,123 - 2,998,530 170,208

Nine projects have been identified with CPUC-jurisdictional project costs equal to or 17

greater than $1 million. A description and justification for each of these projects is provided below. 18

28

The total cost for these nine projects is $2.999 billion. The CPUC-jurisdictional cost for these projects 1

is $170.208 million, of which $53.548 million is from 2013 to 2017. 2

(1) Sandlot 220 kV Substation (Project #6960) 3

A new 220 kV collector substation (Sandlot) is needed to interconnect and 4

integrate new renewable generation in Hinkley. This project will provide the transmission infrastructure 5

needed to interconnect solar generation along the Cool Water-Kramer 220 kV transmission corridor. 6

The project includes construction of a new 220 kV substation. The Cool 7

Water-Kramer No. 1 220kV line will be connected into and out of (“looped into”) the new Sandlot 8

Substation to form the Kramer-Sandlot and Cool Water 220 kV lines. Protective relays and 9

telecommunications equipment are required to support a special protection system (SPS). 10

This project has a telecommunication component of over $1 million 11

dollars. The telecommunications scope includes new diversely routed fiber optic telecommunication 12

system for communications between generation customer facilities and Sandlot Substation. This 13

includes fiber optic cable between Sandlot and Kramer; Sandlot and Tortilla; and Victor to Kramer as 14

well as multiplex equipment and channel equipment at the Kramer, Lugo, and Victor Substations. 15

The operating date is April 2013, with total project costs of $50.103 16


(2) Eldorado Ivanpah Transmission Upgrades (Project # 06551) 18

The Eldorado Ivanpah Transmission Upgrades project is needed in order 19

to: comply with the state-mandated RPS; and integrate planned renewable generation resources from 20

the Ivanpah Dry Lake Area. 21

SCE’s existing transmission facilities in the area will not be able to 22

provide the transmission capacity needed for the projected solar generation development. The Eldorado-23

Ivanpah Transmission Upgrades project will provide the electrical facilities and capacity necessary to 24

access and deliver power from renewable resources. It will also enable Nevada to export clean energy to 25

California. This project also supports state and federal renewable energy goals and supports the 26

reduction of greenhouse gas emission. 27

The scope of this project includes: (1) constructing a new 220/115 kV 28

Ivanpah substation near Primm, Nevada; (2) replacing of a portion of an existing 115 kV 29

41 Refer to workpaper entitled “Sandlot 220 kV Substation (Project #06960).”

29

subtransmission line with a 35-mile double-circuit 220 kV transmission line; (3) connecting the new 1

Ivanpah Substation to SCE’s Eldorado Substation near Boulder City, Nevada; (4) upgrades at Eldorado 2

Substation to support the connection of new transmission lines; and (5) constructing two separate 3

telecommunications pathways and communication equipment to connect the project to SCE’s existing 4

telecommunications system. 5

SCE performed an alternative analysis, which was included in the PEA 6

application (Application A.09-05-027) filed May 28, 2009. The proposed project was selected as the 7

most feasible alternative that meets all of the project objectives. 8

The operating date is July 2013 with a total project cost of $384.511 9


(3) Devers - Colorado River (DCR) (Project #04847) 11

The DCR Project includes building the California portion of the Devers-12

Palo Verde No. 2 (DPV2) transmission project. This project will provide the transmission infrastructure 13

needed for developers to transfer additional capacity for new renewable and conventional generation 14

from the solar energy rich areas of eastern Riverside County to energy customers in Southern California. 15

The project will assist California in meeting its aggressive renewable energy goals of 33 percent by 16

2020. The project consists of constructing the California portion of DCR, a new 113 mile 500 kV line 17

from the new Colorado River Switchyard to SCE's existing Devers Substation. This project also 18

involves construction of the Devers Valley No. 2 line, a new 42 mile 500 kV transmission paralleling an 19

existing line connecting SCE’s Devers Substation to SCE’s existing Valley Substation in Romoland 20

California. Also, a construction of other reactive support equipment is needed for voltage support, 21

including shunt capacitors and a Static VAR System. The CPUC approved SCE’s application to build 22

the California portion of the project in November 2009. 23

The telecommunications scope of work to support the Devers - Colorado 24

River 500 kV transmission line includes the installation of a new digital microwave path from 25

Chuckwalla Communication Site to Colorado River Switchyard, new fiber optic cable from Colorado 26

River Switchyard to Blythe Service Center, from Colorado River Switchyard to Buck Blvd. (WAPA), 27

from Mirage Substation to the 500kV right of way of the Devers - Colorado River 500 kV T/L, and 28

associated multiplexers and equipment at various locations. 29

42 Refer to workpaper entitled “Eldorado Ivanpah Transmission Upgrades (Project #06551).”

30


application (Application A.05-04-015) filed April 11, 2005. The proposed project was selected as the 2


The operating date is September 2013 and the total project cost is 4

estimated to be $859.974 million. This includes $8.819 million of CPUC-jurisdictional expenditures.43 5

(4) Red Bluff 500/220 kV Substation (Project #06929) 6

A new 500/220 kV collector substation (Red Bluff) is needed to 7

interconnect new renewable generation projects in the Desert Center Area. This project will provide the 8

transmission infrastructure needed to interconnect additional capacity along the Devers-Colorado River 9

transmission corridor. 10

The project consists of constructing a new 500/220 kV substation five 11

miles east of Desert Center, California that is ultimately designed for four 500/220 transformer banks, 12

initially equipped with one transformer bank. The existing Devers-Palo Verde 500 kV line will be 13

connected into and out of (“looped into”) Red Bluff Substation to form the Colorado River-Red Bluff 14

No. 1 and Devers-Red Bluff No. 1 500kV T/L's. The Devers-Colorado River No. 2 500 kV line (Project 15

#04847) will be looped into Red Bluff Substation to form the Colorado River-Red Bluff No. 2 and 16

Devers-Red Bluff No. 2 500kV T/L's. 17

The telecommunications scope of work to support the new substation and 18

transmission lines includes the installation of various telecommunications equipment at Devers, Red 19

Bluff, and Colorado River substations necessary to provide redundant and diverse circuitry for 20

protection of the 500 kV T/L network. 21

The operating date is December 2013 and the total project cost is 22

estimated to be $234.014 million. This includes $7.673 million of CPUC-jurisdictional expenditures.44 23

(5) Tehachapi Renewable Transmission Project - Seg. 7 and Seg. 8 24

(Projects #06438, #06439) 25

The Tehachapi Renewable Transmission Project (TRTP) is divided into 11 26

segments. Segment 1-3 collectively are referred to as the Antelope Transmission Project. Segments 4-27

11 are referred to as TRTP. This section of the testimony includes Segments 7 and 8. 28

43 Refer to workpaper entitled “Devers - Colorado River (DCR). (Project #04847).”

44 Refer to workpaper entitled “Red Bluff 500/220 kV Substation (Project #06929).”

31

TRTP Segment 7 consists of the initial phase of a new Vincent-Mira Loma 1

500 kV Transmission Line between Vincent and the Mesa Substations, located in the cities of Palmdale 2

and Monterey Park respectively. Segment 8 consists of the final phase of the new Vincent-Mira Loma 3

500 kV Transmission Line between Mesa Substation and Mira Loma Substation, located in the city of 4

Ontario. Both Segment 7 and 8 were approved by the CAISO in 2007 and have a scheduled operating 5

date of January 2015. 6

The Tehachapi Renewable Transmission Project supports the intent of 7

Senate Bill 1078, which established a program requiring IOUs to have 20 percent of the energy used 8

produced by renewable generation sources, such as biomass, geothermal, small hydro, solar, and wind 9

by the year 2017. Specific to SCE, the project would increase SCE’s ability to deliver additional 10

renewable energy from the Tehachapi to its load centers in the greater Los Angeles basin and in the 11

rapidly growing portions of both western Riverside and San Bernardino Counties. This project will help 12

improve system reliability and increase operational flexibility. Without this work, SCE will jeopardize 13

the reliability and safety of its electric grid, and compromise its ability to serve its customers. 14

Segment 7 of the Vincent-Mira Loma 500 kV transmission line section 15

between Vincent and the Mesa area will be completed by replacing the Vincent-Rio Hondo No.2 220 kV 16

transmission line with 500 kV construction, and upgrading existing transmission near Vincent and 17

between the city of Duarte and the Mesa area. The upgrades near Vincent involve removing five miles 18

of the Vincent-Rio Hondo No.2 220 kV single circuit transmission line between Vincent and the 19

Angeles National Forest and replacing it with a new five mile 500 kV single circuit transmission line. 20

The upgrades between the city of Duarte and the Mesa area involve removal of the remaining section of 21

existing Antelope-Mesa 220 kV and replacing it with approximately 15 miles of new double-circuit 500 22

kV transmission line section. In addition, in order to maximize the use of the existing transmission 23

right-of-way, several 66 kV subtransmission lines between the Rio Hondo and Mesa areas need to be 24

relocated to either new right-of-way or SCE franchise. 25

Segment 7 also includes a telecommunication portion that involves the 26

extension of Optic Ground Wire (OPGW) into the communication room at Rio Hondo Substation, and 27

the installation of associated multiplexers and equipment, copper and fiber optic cables in underground 28

ducts when 66 kV subtransmission lines are rerouted, and fiber wrap optic cables. 29

Segment 8, the remaining portion of Vincent-Mira Loma 500 kV 30

transmission line between the Mesa area and Mira Loma, will be double-circuit 500 kV mostly located 31

32

in existing SCE transmission line right-of-way. In order to utilize the existing right-of-way, 220 kV 1

transmission consolidations will be required. These consolidations include the removal of an existing 2

220 kV “idled” transmission line segment, the removal of an existing 220 kV single-circuit line and 3

replacement with new 220 kV double-circuit line, and the relocation of several 66 kV subtransmission 4

lines in the Chino area. 5

SCE plans to install fiber optic cables as part of Segment 8. This is 6

necessary to replace the fiber optic cables to be removed with the Mesa-Chino 220 kV transmission line. 7

SCE will also install associated equipment at various locations including a new communications room at 8

the Mira Loma substation. 9

The operating date for Segment 7 is January 2015, with a total project cost 10

of $207.134 million. This includes $34.061 million of CPUC-jurisdictional expenditures.45 11

The operating date for Segment 8 is March 2015 with a total project cost 12

of $433.110 million. This includes $32.804 million of CPUC-jurisdictional expenditures.46 13

(6) Tehachapi Renewable Transmission Project – Segments 3B, 6 and 9 14

(Projects #07183, #05243, #06440) 15

The Tehachapi Renewable Transmission Project (TRTP) is divided into 11 16

segments. Segment 1-3 collectively are referred to as the Antelope Transmission Project. Segments 4-17

11 are referred to as TRTP. This section of the testimony includes Segments 3B, 6, and 9, as these 18

particular segments have a telecommunication component of over $1 million dollars. All segments 19

include a series of new and updated electric transmission lines and substations that will deliver 20

electricity from new wind farms in the Tehachapi area to SCE customers and the California transmission 21

grid. TRTP is a vital part of meeting California’s renewable energy goals. 22

Segment 3B includes the construction of a new Highwind 220/66 kV 23

Substation located in Kern County. Also included is a new 9.6-mile 220 kV single-circuit transmission 24

line between Windhub Substation and Highwind Substation. Highwind serves as a collector station for 25

renewable generation in the area and sends the power to the grid via the new Highwind-Windhub 220 26

kV line. 27

45 Refer to workpaper entitled “Tehachapi Renewable Transmission Project - Seg. 7 (Project #06438).”


33

Segment 6 includes a new 500 kV transmission line from Rio Hondo to 1

Vincent Substation located between Irwindale and Palmdale. 2

Segment 9 involves the installation of substation equipment and upgrades 3

at Antelope, Vincent, Windhub, and Whirlwind Substations to connect new 220 kV and 500 kV 4

transmission lines and to help maintain proper voltage levels. 5

The telecommunication work for Segment 3B includes a new 6

communication room at Highwind Substation with new facility equipment, DC power system, antenna 7

tower and microwave antennas, microwave terminal equipment, lightwave terminal equipment, channel 8

equipment, and data network equipment. The optic ground wire will be extended to the 9

telecommunications room. 10

The telecommunication work for Segment 6 will include new 11

communications circuits at Vincent Substation required for (1) protecting the new transmission line and 12

(2) providing new communication circuits to a new control house at Vincent Substation. 13

The telecommunication work for Segment 9 can be separated by 14

substation. At Whirlwind Substation, a new communication room will be constructed with new facility 15

equipment, DC power system, antenna tower, and microwave antennas, microwave terminal equipment, 16

lightwave terminal equipment, channel equipment, and data network equipment. The optic ground wire 17

will be extended to the telecommunications room. At Windhub Substation, SCE will install additional 18

lightwave terminal equipment, channel equipment, and data network equipment in the communication 19

room that was constructed as part of TRTP 1-3 (also known as Antelope Transmission Project 1–3). 20

Also, the optical power ground wire will be extended to the communications room. 21

Segment 3B includes $2.995 million of CPUC-jurisdictional cost out of a 22

total project cost of $66.250 million. These facilities were placed in service December 2012, although 23

the project has expenditures in 2013 and is included here as a result.47 24

Segment 6 includes $1.646 million of CPUC-jurisdictional cost out of a 25

total project cost of $291.244 million. The operation date of this project is November 2013; however, 26

SCE expects to spend subsequent environmental capital.48 27

47 Refer to workpaper entitled “Tehachapi Renewable Transmission Project - Seg. 3B (Project #07183).”


34

Segment 9 includes $6.240 million of CPUC-jurisdictional cost out of a 1

total project cost of $298.645 million. The operation date of this project is December 2013.49 2

(7) Colorado River Corridor SPS (Project #07061) 3

The Devers-Red Bluff 500 kV transmission corridor will serve as a major 4

transmission path to deliver power to Southern California from Arizona as well as from generation 5

interconnected at Colorado River and Red Bluff Substation. 6

A new special protection scheme (SPS) is required in the event of an N-250 7

line outage of both Devers-Red Bluff 500 kV lines. If this N-2 should occur, the SPS will trip 8

generation interconnected at Colorado River and Red Bluff Substations to mitigate against system 9

instability and voltage collapse. 10

The project includes the installation of protective relays and associated 11

equipment to support the SPS in the Mechanical Electrical Equipment Room (MEER) at Devers, 12

Colorado River, and Red Bluff Substations. The telecommunication scope of work includes installing 13

redundant communication paths and associated equipment between Devers, Colorado River, and Red 14

Bluff Substations. The operating date is June 2015 with a total project cost of $2.775 million. This 15

includes $0.282 million of CPUC-jurisdictional expenditures.51 16

(8) Jasper 220 kV Substation (Project #06902) 17

A new 220 kV collector substation (Jasper) is needed to interconnect and 18

integrate new renewable generation in Lucerne Valley. This project will provide the transmission 19

infrastructure needed to interconnect wind generation along the Lugo-Pisgah 220 kV transmission 20

corridor. 21

The project consists of constructing a new 220 kV substation. The Lugo-22

Pisgah No. 1 220 kV line will be connected into and out of (“looped into”) the new Jasper Substation to 23

form the Jasper-Lugo and Jasper-Pisgah 220 kV lines. A new Cool Water 220 kV line will be 24

terminated into Jasper Substation. Protective relays and equipment are required to support a special 25

protection system (SPS). 26


50 Loss of two power system elements.

51 Refer to workpaper entitled “Colorado River Corridor SPS (Project #07061).”

35

The telecommunications scope includes new diversely routed fiber optic 1

telecommunication system for communications between existing SCE facilities and Jasper Substation. 2

This includes new overhead and underground fiber optic cables as well as new fiber optic multiplex 3

equipment and channel equipment at Jasper, Cottonwood, Lugo, Pisgah, and Gale Substations as well as 4

at Cool Water Generating Station. 5

The operating date is October 2015 with total project costs of $57.005 6


(9) Primm 220 kV Substation (Project #07426) 8

A new 220 kV collector substation (Primm) is needed to interconnect new 9

renewable generation projects in Primm, Nevada. This project will provide the transmission 10

infrastructure needed to interconnect solar generation along the Eldorado-Ivanpah 220 kV transmission 11

corridor. 12

The project consists of constructing a new 220 kV substation (switching 13

station). The existing Eldorado-Ivanpah No. 1 220 kV line will be connected into and out of (“looped 14

into”) the new Primm Substation to form the Eldorado-Primm and Ivanpah-Primm 220 kV T/Ls. Also, a 15

single 220 kV generation tie line will be interconnected to the new substation. 16

The telecommunications scope of work to support the new substation and 17

transmission lines includes the installation of fiber optic cable between Ivanpah and Primm Substation to 18

meet the diverse routing requirements for the Ivanpah-Primm 220 kV transmission line. All required 19

light-wave channel and related terminal equipment at Primm, Eldorado, and Ivanpah Substation will be 20

installed to support the new fiber optic lines. 21

The operating date is October 2015, with total project costs of $25.614 22


(10) Whirlwind #2AA and #3AA Bank Upgrades (Project #07067) 24

Whirlwind Substation is located in Tehachapi. A new 500/220 kV 25

transformer bank and special protection scheme (SPS) is needed at Whirlwind Substation to increase 26

substation capacity and interconnect new renewable solar generation. 27

52 Refer to workpaper entitled “Jasper 220 kV Substation (Project #06902).”

53 Refer to workpaper entitled “Primm 220 kV Substation (Project #07426).”

36

The scope of the project includes installing a new 500/220 kV transformer 1

bank. One position on the 500 kV switchrack and one position on the 220 kV switchrack at Whirlwind 2

will be equipped each with two circuit breakers and four disconnect switches. Diverse 3

telecommunication paths and terminal equipment are required at Whirlwind to support the SPS. 4

Additional renewable generators in the Tehachapi area are expected to sign Large Generator 5

Interconnection Agreements (LGIA) in 2013. These generators will trigger a third 500/220 kV 6

transformer bank at Whirlwind Substation and associated circuit breakers and disconnect switches as 7

described above. 8

The #2AA bank operating date is December 2014 and the #3AA bank 9

operating date is December 2016, with total project costs of $88.150 million. This includes $1.487 10


3. Projects With Less Than $1 Million in CPUC-Jurisdictional Costs 12

SCE has several Transmission projects that have less than $1 million in CPUC-13

jurisdictional expenditures with planned operating dates between 2013 and 2017.55 The capital forecasts 14

for these projects is $626.3 million in total, with $18.634 million of CPUC-jurisdictional costs from 15

2013 – 2017. Consistent with the approach SCE has taken in previous rate cases, SCE has not presented 16

detailed descriptions of these projects, but instead show the forecasts in workpapers. 17

F. Load Growth Planning Programs 18

As described in the above, the load growth planning program is separated into four categories in 19

which projects are identified and costs forecasts are developed. Descriptions of these categories and 20

related project are included Table I-10 below. Load growth planning also includes projects with less 21

than $1 million in CPUC-jurisdictional costs, which are not discussed in detail.56 22

54 Refer to workpaper entitled “Whirlwind #2AA and #3AA Bank Upgrades (Project #07067).” The total project cost for

Whirlwind #2AA is $42.808 million and the total project cost for Whirlwind #3AA is $45.342 million.

55 Forecasts for these projects are included in the workpapers entitled “Transmission and Interconnection Planning Projects Under $1 Million.”

56 Forecasts for these projects are included in the workpapers entitled “Load Growth Projects Under $1 Million.”

37

Table I-10 Load Growth Planning Programs Capital Expenditure Summary


Line No.


1 A-Bank Plan 242,410 57,985 166,224 141,124 137,989 54,525 800,258 2 Subtransmission Lines Plan 45,919 30,565 68,981 92,626 26,685 - 264,778 3 Subtransmission VAR plan 1,965 111 - - - - 2,076 4 Distribution Substation Plan (DSP) 155,694 102,329 133,621 163,212 135,666 - 690,522 5 Land Held for Future Use - - - 13,251 4,044 - 17,295 6 Subtotal of Load Growth Projects 445,988 190,990 368,827 410,213 304,385 54,525 1,774,928 7 Projects <$1M 2,932 3,898 2,445 2,777 3,418 3,174 18,644 8 Total 448,920 194,889 371,272 412,991 307,802 57,699 1,793,572

1. A-Bank Plan 1

As discussed in Section I-B, A-banks are step-down transformers located at our A-2

substations that reduce our system voltage from the transmission level (220 kV or 500 kV) to the 3

subtransmission level (66 kV or 115 kV). In the A-Bank Plan, we annually review requirements for our 4

500/115 kV, 220/115 kV, and 220/66 kV A-banks over a ten-year planning horizon. Without a 5

comprehensive A-Bank Plan, we would run the risk of loading our A-banks beyond their capabilities as 6

the demand for electricity continues to increase in our service territory. This could ultimately result in 7

A-bank equipment failures and service interruptions to hundreds of thousands of customers over 8

widespread geographic areas. 9

The objective of the A-Bank Plan, as shown in Figure I-5 below, is to provide for 10

adequate A-bank capacity at each A-substation to serve forecast peak loads under a one-in-five year heat 11

storm condition. We evaluate the ability of each A-bank to operate within its established loading limits 12

under normal conditions with all facilities in service (“base case”), and also under contingency 13

conditions when critical equipment is out of service (“N-1”). When we forecast that an A-bank will 14

become overloaded at some point within our ten-year planning horizon, we evaluate whether we can 15

utilizing existing infrastructure to balance electric power from highly loaded substation to less loaded 16

substations. If we cannot, a project to expand, upgrade, or reinforce our system is initiated. Typical 17

projects in the A-Bank Plan include installing new A-banks at existing A-substations, replacing existing 18

A-banks with higher capacity rated A-banks, and developing new 500/115 kV, 220/115 kV, or 220/66 19

kV A-substations. 20

38

Figure I-5 A-Bank Plan

Table I-11 below provides A-Bank Plan capital expenditures for projects that will be 1

completed in the 2013-2017 period. 2

39

Table I-11 A-Bank Plan Capital Expenditure Summary


Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 05075 El Casco 220/115 kV Substation Jun 2013 115,416 1,977 - - - - 117,392 2 05360 Devers-Mirage 115kV System Split Jun 2013 30,800 160 - - - - 30,960 3 06807 Valley 'C' 500/115 kV Substation Jun 2013 4,929 100 - - - - 5,029 4 06221 Ellis 'C' 220/66 kV Substation Jul 2013 23,043 812 - - - - 23,854 5 06227 Santiago 220/66 kV Substation Dec 2013 185 8,886 - - - - 9,071 6 06284 La Cienega 220/66 kV Substation Jun 2014 13,768 1,721 1,387 - - - 16,877 7 06824 La Fresa 220/66 kV Substation Dec 2014 17,820 14,413 15,148 147 2 - 47,530 8 06263 Vestal 220/66 kV Substation Jun 2015 2,597 2,998 6,621 6,378 - - 18,593 9 06670 Valley 'AB' 500/115 kV Substation Mar 2016 193 4,026 14,209 8,335 4,302 - 31,065

10 05383 Chino 220/66 kV Substation-Phase 1 Jun 2016 575 50 6,007 14,724 23,632 - 44,988 11 06092 Alberhill 500/115 kV Substation Jun 2017 30,064 14,886 85,668 95,635 107,141 52,809 386,203 12 06107 Saugus 'C' 220/66 kV Substation Jun 2017 3,021 7,957 37,184 15,905 2,912 1,716 68,695 13 Total A-Bank Plan 242,410 57,985 166,224 141,124 137,989 54,525 800,258

Twelve A-Bank projects have been identified with project costs equal to or greater than 1

$1 million. A description and justification for each of these projects is provided below. The total cost 2

for these twelve projects is $800.3 million of which $396.3 million is CPUC-jurisdictional cost forecast 3

from 2013 to 2017. 4

(1) El Casco 220/115 kV Substation (Project #05075) 5

El Casco 220/115 kV Substation57 is a new planned substation to be 6

located in the city of Calimesa. The purpose of the project is to build electrical facilities necessary to 7

serve forecast demand in north Riverside County and to maintain safe and reliable service to customers 8

in this area. The project scope is to construct a new substation consisting of two 280 MVA, 220/115 kV 9

transformer banks, two 28 MVA, 115/12 kV transformer banks, and three new 12 kV distribution 10

circuits. The project scope also includes rebuilding and reconstructing approximately 15 miles of 11

existing 115 kV subtransmission lines, rebuilding the existing 115 kV switchracks at both Banning 12

115/33 kV Substation and Zanja 115/33 kV Substation, and installing telecommunications equipment at 13

both the El Casco Substation and SCE’s existing Mill Creek Communications site. The operating date is 14

June 2013 with a total project cost of $117.392 million.58 This project was included in SCE’s 2012 15

57 See Application A.07-02-022 (Proponent’s Environmental Assessment–El Casco System Project) for a detailed

discussion of the purpose and need for this project.

58 Refer to workpaper entitled “El Casco 220/115 kV Substation (Project #05075).”

40

GRC filing with a June 2010 operating date but was subsequently moved to June 2013 due to delays in 1

acquiring the necessary permits to construct the project. 2

SCE has identified one alternative to this project—to add a new 280 MVA 3

transformer bank at Vista 220/115 kV Substation, construct approximately 14 miles of new 115 kV 4

subtransmission lines, rebuild approximately 18 miles of existing 115 kV subtransmission lines, add a 5

new 28 MVA transformer bank at Maraschino 115/12 kV Substation with five new 12 kV distribution 6

circuits, rebuild the 115 kV switchracks at Banning 115/33 kV Substation and Zanja 115/33 kV 7

Substation, and install telecommunications equipment at Vista, Maraschino, Banning, and Zanja 8

Substations. The alternative analysis was included in the PEA (Application A.07-02-022, filed February 9

16, 2007) which was approved on December 18, 2008 (Decision 08-12-031) later modified. The total 10

estimated cost of this alternative is $123.867 million. The proposed project was selected as the least 11

cost alternative. 12

(2) Devers-Mirage 115 kV System Split (Project #05360) 13

The Devers-Mirage 115 kV Subtransmission System Split is necessary to 14

maintain electric system reliability, enhance operational flexibility, and serve projected electrical 15

demand in the Palm Springs area. The project is necessary to relieve thermal overload conditions on the 16

existing Mirage-Concho leg of the Devers-Capwind-Concho-Mirage 115 kV subtransmission line and 17

the Mirage-Tamarisk 115 kV subtransmission line. 18

The project includes the rearrangement of the following 115 kV 19

subtransmission lines in order to split the existing Devers 115 kV Subtransmission System between the 20

Devers and Mirage Substations into two separate 115 kV subtransmission systems, forming the 21

proposed Devers 115 kV Subtransmission System and the proposed Mirage 115 kV. Furthermore, a 22

new 220/115 kV transformer will be installed at Mirage Substation. The rearranged 115 kV 23

subtransmission lines include the Mirage-Santa Rosa, Mirage-Santa Rosa-Tamarisk, Mirage-Capwind-24

Devers-Tamarisk, Mirage-Concho, Devers-Eisenhower-Thornhill, Eisenhower-Tamarisk, and Farrell-25

Garnet. The operating date is June 2013 with a total project cost of $30.960 million.59 26


application (Application A.08-01-029) filed January 31, 2008. The proposed project was selected as the 28


59 Refer to workpaper entitled “Devers-Mirage 115kV System Split (Project #05360).”

41

(3) Valley ‘C’ 500/115 kV Substation (Project #06807) 1

Valley 500/115 kV Substation is located in the city of Romoland and 2

serves the areas of Glen Ivy, Lake Elsinore, Murrieta, Perris, Romoland, Sun City, Temecula, 3

Winchester, and unincorporated areas of Riverside County. SCE has identified that the circuit breakers 4

on the 115 kV bus section at the Valley 500/115 kV Substation exceed their short-circuit duty equipment 5

rating. The project scope is to replace a total of sixteen 115 kV circuit breakers at Valley 500/115 kV 6

Substation with higher short circuit duty rated units. The operating date is June 2013 with a total project 7

cost of $5.029 million.60 This project was included in SCE’s 2012 GRC filing with a December 2010 8

operating date but was subsequently moved to June 2013. There are no alternatives to this project. The 9

proposed project is the only viable technical solution. 10

(4) Ellis ‘C’ 220/66 kV Substation (Project #06221) 11

Ellis 220/66 kV Substation is located in the city of Huntington Beach and 12

serves communities in north Orange County. By 2013, the “A” 66 kV bus section at Ellis 220/66 kV 13

Substation is projected to exceed its capacity limit due to continuing load growth in the area. The 14

project scope is to install a new 280 MVA transformer bank on the “C” 66 kV bus section at Ellis 15

220/66 kV Substation (thereby increasing total transformer capacity from 840 MVA to 1120 MVA at 16

the station), rearrange various 66 kV subtransmission lines to permanently transfer four substations from 17

the “A” 66 kV bus section to the “C” 66 kV bus section, and replace the north and south 220 kV buses 18

with 2156 kcmil ACSR. Without the project, the loading on the “A” 66 kV bus section at Ellis 220/66 19

kV Substation exceeded the substation’s capacity limit in 2011 under normal operating conditions. This 20

project has been separated into two phases. Phase 1 includes the installation of a new 280 MVA 21

transformer and the subtransmission lines rearrangement. Phase 2 includes replacing the north and 22

south 220 kV buses. This project was included in SCE’s 2012 GRC filing with a June 2010 operating 23

date but was subsequently moved to June 2011 (Phase 1) and June 2013 (Phase 2) due to delays in 24

acquiring the necessary permits to construct the project. Phase 1 had an operating date of June 2011 and 25

Phase 2 has an operating date of July 2013. The total project cost is $23.854 million.61 26

SCE has identified one alternative to this project—to install a new 280 27

MVA transformer bank at Johanna 220/66 kV Substation and construct approximately 1.8 miles of new 28

60 Refer to workpaper entitled “Valley “C” 500/115 kV Substation (Project #06807).”

61 Refer to workpaper entitled “Ellis “C” 220/66 kV Substation (Project #06221).”

42

66 kV subtransmission line to permanently transfer Gisler 66/12 kV Substation and Talbert 66/12 kV 1

Substation from the Ellis 66 kV system to the Johanna 66 kV system. The total estimated cost of this 2

alternative is $29.140 million. The proposed project was selected as the least cost alternative. 3

(5) Santiago 220/66 kV Substation (Project #06227) 4

Santiago 220/66 kV Substation is located in the city of Irvine and serves 5

communities in south Orange County. By the end of 2013, Santiago 220/66 kV Substation is projected 6

to approach its capacity limit due to continuing load growth in the area. The project scope is to install 7

the existing spare 280 MVA transformer bank at Santiago 220/66 kV Substation as a permanent unit 8

(thereby increasing total transformer capacity from 840 MVA to 1120 MVA at the station) and split the 9

Santiago 66 kV system. Without the project, the loading at Santiago 220/66 kV Substation is projected 10

to reach 96.2 percent of the substation’s capacity limit by the end of 2013 under normal operating 11

conditions. The operating date is December 2013 with a total project cost of $9.071 million.62 This 12

project was included in SCE’s 2012 GRC filing with a June 2010 operating date but was subsequently 13

moved to December 2013 due to delays in acquiring the necessary permits to construct the project. 14

SCE has identified one alternative to this project–to install a new 280 15

MVA transformer bank at Viejo 220/66 kV Substation, construct approximately 16.7 miles of new 66 16

kV subtransmission line, and rebuild approximately 3.0 miles of existing 66 kV subtransmission line to 17

permanently transfer Borrego 66/12 kV Substation, Moulton 66/12 kV Substation, and Niguel 66/12 kV 18

Substation from the Santiago 66 kV system to the Viejo 66 kV system. The total estimated cost of this 19


(6) La Cienega 220/66 kV Substation (Project #06284) 21

La Cienega 220/66 kV Substation is located in the city of Los Angeles and 22

serves communities in west Los Angeles County. By 2014, La Cienega 220/66 kV Substation is 23

projected to approach its capacity limit due to continuing load growth in the area. The project scope is 24

to install a new 280 MVA transformer bank at La Cienega 220/66 kV Substation (increasing total 25

transformer capacity from 560 MVA to 840 MVA at the station) and upgrading the substation 26

automation to SA2. Without the project, the loading at La Cienega 220/66 kV Substation is projected to 27

reach 96.7 percent of the substation’s capacity limit by 2014 under normal operating conditions. This 28

project is includes installing a new 280 MVA transformer bank and upgrading the substation automation 29

62 Refer to workpaper entitled “Santiago 220/66 kV Substation (Project #06227).”

43

to SA2. The operating date is June 2014 and the total project cost for this project is $16.877 million.63 1

This project was included in SCE’s 2012 GRC filing with a June 2012 operating date but was 2

subsequently moved to June 2014 due to lower than anticipated load growth in the area. 3

SCE has identified one alternative to this project–to add a new 280 MVA 4

transformer bank at El Nido 220/66 kV Substation and construct approximately 1.6 miles of new 66 kV 5

subtransmission line and rebuild approximately 4.4 miles of existing 66 kV subtransmission line to 6

permanently transfer Marine 66/16 kV Substation and Tahiti 66/16 kV Substation from the La Cienega 7

66 kV system to the El Nido 66 kV system. The total estimated cost of this alternative is $18.877 8

million. The proposed project was selected as the least cost alternative. 9

(7) La Fresa 220/66 kV Substation (Project #06824) 10

La Fresa 220/66 kV Substation is located in the city of Torrance and 11

serves communities in south Los Angeles County. By the end of 2013, the “B” 66 kV bus section at La 12

Fresa 220/66 kV Substation is projected to exceed its capacity limit due to continuing load growth in the 13

area. The project scope is to install a new 280 MVA transformer bank on the “A” 66 kV bus section at 14

La Fresa 220/66 kV Substation (thereby increasing total transformer capacity from 750 MVA to 1030 15

MVA at the station) and rearrange various 66 kV subtransmission lines to permanently transfer 16

Compress 66/12 kV Substation and Mobil Oil 66/12 kV Substation from the “B” 66 kV bus section to 17

the “A” 66 kV bus section. The scope also includes the construction of one Mechanical Electrical 18

Equipment Room (MEER). Without the project, the loading on the “B” 66 kV bus section at La Fresa 19

220/66 kV Substation is projected to reach 101.8 percent of the substation’s capacity limit by 2013 20

under normal operating conditions. This project is split into two phases. Phase 1 includes installing a 21

280 MVA transformer bank and subtransmission lines rearrangement and has an operating date of June 22

2013. Phase 2 includes constructing one new MEER and has an operating date of December 2014. The 23

total project cost is $47.530 million.64 24


MVA transformer bank at El Nido 220/66 kV Substation. construct approximately 10 miles of new 26

subtransmission lines, and reconfigure approximately 2 miles of existing subtransmission line to transfer 27

Yukon 66/16 kV and 66/4 kV Substations, Northrop 66/4 kV Substation, and Bridge 66/4 kV Substation 28

63 Refer to workpaper entitled “La Cienega 220/66 kV Substation (Project #06284).”

64 Refer to workpaper entitled “La Fresa 220/66 kV Substation (Project #06824).”

44

to El Nido 220/66 kV Substation. The total estimated cost for this project is $56.389 million. This 1

project could not be feasibly be constructed in time to address the projected overload at La Fresa. The 2

proposed project was selected as the least cost alternative. 3

(8) Vestal 220/66 kV Substation (Project #06263) 4

Vestal 220/66 kV Substation is located in Richgrove and serves 5

communities in Tulare County. By 2015, Vestal 220/66 kV Substation is projected to exceed its 6

capacity limit due to continuing load growth in the area. The project scope is to replace two existing 7

100 MVA transformer banks with two 280 MVA transformer banks (thereby increasing total 8

transformer capacity from 200 to 560 MVA). Currently, both of the existing 100 MVA A-bank 9

transformers at Vestal 220/66 kV Substation are connected directly to the Vestal 220 kV switchrack 10

without circuit breakers. The project scope includes installing four new 220 kV circuit breakers at 11

Vestal 220/66 kV Substation to connect each of these two A-bank transformers to the Vestal 220 kV 12

switchrack in double-breaker positions. Without the project, the loading at Vestal 220/66 kV Substation 13

is projected to reach 127.8 percent of the substation’s capacity limit by 2015 under N-1 transformer 14

outage conditions. The operating date is June 2015 with a total project cost of $18.593 million.65 15

SCE has identified one alternative to this project—to construct a new 40 16

mile 66 kV subtransmission line from Springville Substation to Delano Substation, install one 280 MVA 17

bank at Springville, and install one 28 MVAR capacitor at Delano. The total estimated cost of this 18


(9) Valley ‘AB’ 500/115 kV Substation (Project #06670) 20

Valley 500/115 kV Substation is located in the city of Romoland and 21

serves communities in southwest Riverside County. SCE’s Transmission Planning Criteria & 22

Guidelines (TPG) requires that A-bank transformers be connected to substation switchracks through 23

circuit breakers.66 Currently, two of the four existing A-bank transformers at Valley 500/115 kV 24

Substation are connected directly to the Valley 115 kV switchrack without circuit breakers. In addition 25

to this, the substation was constructed as a Gas Insulated Substation (GIS). Maintenance of this GIS has 26

become problematic because the manufacturer of this GIS is no longer in business and replacement parts 27

65 Refer to workpaper entitled “Vestal 220/66 kV Substation (Project #06263).”

66 Our reliability planning criteria specifies “All new ‘A’ and ‘AA’ bank additions” must be connected to the switchrack by circuit breakers and “When adding or replacing an “A” or “AA” transformer bank…all transformer banks at the station” must be connected to the switchrack by circuit breakers.

45

are no longer available. The project scope is to construct a new Air Insulated Substation (AIS) 115 kV 1

switchrack, transfer all positions from the existing GIS 115 kV switchrack to the AIS 115 kV 2

switchrack, install four additional transformer bank breakers, and retire the existing GIS. The operating 3

date is March 2016 with a total project cost of $31.065 million.67 This project was included in SCE’s 4

2012 GRC filing with a February 2014 operating date but was subsequently moved to March 2016 due 5

to project prioritization. 6

SCE has identified one alternative to this project–to rebuild the existing 12 7

position Gas Insulated Switchrack (GIS) and install four new circuit breakers. The total estimated cost 8

of this alternative is $38.970 million. The proposed project was selected as the least cost alternative. 9

(10) Chino 220/66 kV Substation–Phase 1 (Project #05383) 10

Chino 220/66 kV Substation is located in the city of Chino and serves 11

communities in southwest San Bernardino County and east Los Angeles County. By 2020, Chino 12

Substation is projected to exceed its capacity limit due to continuing load growth in the area. The 13

current switchrack cannot accommodate group operated disconnects. In addition it has been identified 14

that the circuit breakers at Chino 220/66 kV Substation exceed their short-circuit duty equipment rating. 15

The project is separated into two phases. The scope of Phase 1 is to rebuild the switchrack to 16

accommodate the replacement of 45 circuit breakers with higher rated circuit breakers and installation of 17

36 sets of group operated disconnects to improve safety and operability of the switchrack. The scope of 18

Phase 2 is to install a new 280 MVA transformer bank increasing the capacity from 840 MVA to 1120 19

MVA. The operating date of Phase 1 is June 2016 with a cost of $44.988 million.68 The operating date 20

of Phase 2 is June 2020. Because the operating date of Phase 2 is outside of the 2015 rate case window, 21

the cost of Phase 2 is not be included in this filing. 22


MVA transformer bank at Mira Loma 220/66 kV Substation, construct a new 20 mile 66 kV 24

subtransmission line from Mira Loma Substation to Firehouse Substation, and rebuild the switchrack at 25

Chino Substation. The total estimated cost for this project is $96.750 million. The proposed project was 26

selected as the least cost alternative. 27

67 Refer to workpaper entitled “Valley “AB” 500/115 kV Substation (Project #06670).”

68 Refer to workpaper entitled “Chino 220/66 kV Substation-Phase 1 (Project #05383).”

46

(11) Alberhill 500/115 kV Substation (Project #06092) 1

Alberhill 500/115 kV Substation69 is a new planned substation to be 2

located in the San Jacinto Region of southwestern Riverside County. The purpose of the project is to 3

serve current and projected demand for electricity and maintain electric system reliability in 4

southwestern Riverside County. The project scope is to construct a new substation consisting of two 5

560 MVA, 500/115 kV transformer banks. The project scope also includes constructing two new 500 6

kV transmission line segments to connect the new substation to SCE’s Serrano-Valley 500 kV 7

transmission line, constructing a new 115 kV subtransmission line and modifying four existing 115 kV 8

subtransmission lines to transfer five existing 115/12 kV substations presently served by the Valley 9

South 115 kV system to the new Alberhill 115 kV system, and installing telecommunications 10

improvements to connect the new facilities to SCE’s telecommunications network. The operating date 11

is June 2017 with a total project cost of $386.203 million from inception through 2017.70 However, 12

there is an additional $10 million of capital expenditure expected after the operating date of the project. 13


subsequently moved to June 2017 due to delays in acquiring the necessary permits to construct the 15

project. 16

SCE has identified one alternative to this project–to construct a 500/115 17

kV Substation in a different location and construct two 40 mile 500 kV transmission lines. The total 18

estimated cost for this project is $818.356 million. The proposed project was selected as the least cost 19

alternative. 20

(12) Saugus ‘C’ 220/66 kV Substation (Project #06107) 21

Saugus 220/66 kV Substation is located in the city of Santa Clarita and 22

serves communities in northwest Los Angeles County and east Ventura County. By 2015, Saugus 23

220/66 kV Substation is projected to exceed its capacity limit due to continuing load growth in the area. 24

The project scope is to install a new 280 MVA transformer bank at Saugus 220/66 kV Substation 25

(thereby increasing total transformer capacity from 840 MVA to 1120 MVA at the station), split the 26

Saugus 66 kV system and upgrade the substation automation to SA2. Without the project, the loading at 27

69 See Application A.09-09-022 (Proponent’s Environmental Assessment–Alberhill System Project) for a detailed

discussion of the purpose and need for this project.

70 Refer to workpaper entitled “Alberhill 500/115 kV Substation (Project #06092).”

47

Saugus 220/66 kV Substation is projected to reach 102.6 percent of the substation’s capacity limit by 1

2015 under normal operating conditions. This project is separated into two phases. Phase 1 includes 2

installing a new 280 MVA transformer bank and splitting the Saugus 66 kV system and has an operating 3

date of June 2015. Phase 2 includes upgrading the substation automation and has an operating date of 4

June 2017. The total project cost is $68.695 million.71 This project was included in SCE’s 2012 GRC 5

filing with a June 2013 operating date but was subsequently moved to June 2015 (Phase 1) and June 6

2017 (Phase 2) due to delays in acquiring the necessary permits to construct the project. 7

SCE has identified one alternative to this project–to construct a new 8

220/66 kV Substation. The total estimated cost for this project is $100.531 million. The proposed 9

project was selected as the least cost alternative. 10

2. Subtransmission Lines Plan 11

As discussed earlier, networks of subtransmission lines operating at 66 kV or 115 kV 12

deliver electricity from the low voltage side of our A-substations to our B-substations. In the 13

Subtransmission Lines Plan, we annually review requirements for these 66 kV and 115 kV 14

subtransmission networks over a ten-year planning horizon. Without a comprehensive Subtransmission 15

Lines Plan, we would run the risk of loading our 66 kV and 115 kV subtransmission lines beyond their 16

capabilities as the demand for electricity continues to increase in our service territory. This could 17

ultimately result in failures of our overhead and/or underground subtransmission lines and service 18

interruptions to tens of thousands of customers over fairly limited geographic areas. 19

The objective of the Subtransmission Lines Plan, is to provide for adequate 66 kV or 115 20

kV line capacity in each of our subtransmission networks to serve forecast peak loads at our B-21

substations, as shown in Figure I-6 below. We evaluate the ability of each subtransmission line to 22

operate within its established loading limits under normal conditions with all facilities in service (“base 23

case”), and also under contingency conditions when critical equipment is out of service (“N-1”). We 24

also perform studies to evaluate that adequate subtransmission voltage can be maintained at the high 25

voltage side of our B-substations under contingency conditions. When we forecast that a 26

subtransmission line will become overloaded or we will not be able to maintain adequate B-Substation 27

voltage, we evaluate whether we can utilizing existing infrastructure to balance electric power from 28

highly loaded subtransmission line to less loaded subtransmission line. If we cannot, we initiate a 29

71 Refer to workpaper entitled “Saugus “C” 220/66 kV Substation (Project #06107).”

48

capital project to expand, upgrade, or reinforce our subtransmission system. Typical projects in the 1

Subtransmission Lines Plan include replacing existing subtransmission lines with higher capacity rated 2

subtransmission lines, constructing new subtransmission lines, and installing 66 kV or 115 kV capacitor 3

banks at specific B-Substations. 4

Figure I-6 Subtransmission Lines Plan

Table I-12 below provides Subtransmission Lines Plan costs we have already 5

incurred (i.e., expenditures made in 2012 or prior years for projects that will be completed in the 2013-6

2017 period) and forecast costs for projects planned to be completed through 2014.7

49

Twenty-two subtransmission line projects have been identified with project costs 1

equal to or greater than $1 million. A description and justification for each of these projects is provided 2

below. The total cost for these 22 projects is $264.8 million of which $213.3 million is CPUC-3

jurisdictional cost forecast from 2013 to 2017. 4

(1) Gould-La Canada 66 kV Recable (Project #04853) 5

The Gould-La Canada 66 kV Subtransmission Line serves La Canada 6

Substation in the city of La Canada. As of 2012, loading on the Gould-La Canada 66 kV 7

Subtransmission Line exceeded its capacity limit due to continued load growth in the area and so this 8

project was put in service November 2012. However, minor residual work is required in 2013 prior to 9

closing this project. The estimated total project cost is $3.459 million.72 The project scope was to 10

replace 0.8 miles of 1750 aluminum conductor in the Gould-La Canada 66 kV Subtransmission Line 11

with higher capacity rated 3000 copper conductor. Without this project, loading on the Gould-La 12

72 Refer to workpaper entitled “Gould-La Canada 66 kV Recable (Project #04853).”

Table I-12 Subtransmission Lines Plan Capital Expenditure Summary


Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 04853 Gould-La Canada 66 kV Recable Nov 2012 2,117 1,342 - - - - 3,459 2 06392 Santiago-Borrego-Morro 66 kV Reconductor Mar 2013 2,009 3,577 - - - - 5,586 3 06028 Etiwanda-Alder-Randall 66 kV Reconductor Apr 2013 1,833 461 - - - - 2,293 4 05316 Alder-Declez 66 kV Recable Bundle Jun 2013 906 251 - - - - 1,157 5 07040 Camarillo Substation 66 kV Capacitor Bank Jun 2013 609 1,242 - - - - 1,851 6 05364 Weldon Substation 66 kV Capacitor Bank Dec 2013 500 5,120 18 - - - 5,638 7 06070 Mesa-Laguna Bell-Narrows 66 kV Reconductor Dec 2013 27 4,181 - - - - 4,208 8 06844 Mesa-Rush No. 3 66 kV Recable Jun 2014 96 478 864 - - - 1,438 9 07208 Carodean Substation 115 kV Capacitor Bank Jun 2014 6 436 614 - - - 1,055

10 06382 La Cienega-Culver 66 kV Recable Jun 2015 - 21 2,951 1,798 - - 4,771 11 07383 La Cienega-Beverly-Culver 66 kV Recable: La Cienega Leg Jun 2015 - 598 1,493 2,684 - - 4,775 12 07505 La Cienega-Beverly-Culver 66 kV Recable: Beverly Leg Jun 2015 - 571 1,427 2,566 - - 4,565 13 07506 Culver-Sawtelle 66 kV Recable Jun 2015 - 137 343 618 - - 1,098 14 07507 Springville-Strathmore 66 kV Reconductor Jun 2015 - - - 4,262 - - 4,262 15 07508 Vestal-Columbine-Delano-Earlimart 66 kV Reconductor Jun 2015 - - 570 1,419 2,555 - 4,544 16 07512 Vestal-Delano-Browning 66 kV Reconductor Jun 2015 - - 156 389 700 - 1,245 17 04891 Arrowhead Reconfiguration Project Dec 2015 118 477 2,663 1,494 - - 4,753 18 06030 Valley-Ivy Glen 115 kV Line Dec 2015 15,845 7,603 46,715 41,647 10 - 111,821 19 04518 Santa Barbara County Reliability Project Jun 2016 8,334 2,689 9,591 30,800 15,914 - 67,328 20 05329 Moorpark-Newbury 66 kV Line Jun 2016 13,519 1,379 1,274 2,656 4,230 - 23,058 21 07382 Yucca 115/12 kV Substation Loop-In Jun 2016 - - 36 1,632 2,086 - 3,754 22 07384 Santiago-Irvine No. 2 66 kV Recable Jun 2016 - - 266 662 1,191 - 2,119 23 Total Subtransmission Lines Plan 45,919 30,565 68,981 92,626 26,685 - 264,778

50

Canada 66 kV Subtransmission Line is projected to reach 128.7 percent under N-1 line outage 1

conditions. This project was included in SCE’s 2012 GRC filing with a June 2011 operating date but 2

was subsequently moved to November 2012 due to delays in acquiring the necessary permits to 3

construct the project. 4

SCE has identified one alternative to this project–to construct a new 3 mile 5

long, 66 kV subtransmission line from Gould Substation to Arroyo Substation. The total estimated cost 6


(2) Santiago-Borrego-Morro 66 kV Reconductor (Project #06392) 8

The Santiago-Borrego-Morro 66 kV Subtransmission Line serves Morro 9

Substation in the city of Laguna Beach. By the end of 2013, loading on the Morro leg of the Santiago-10

Borrego-Morro 66 kV Subtransmission Line is projected to exceed its capacity limit under N-1 line 11

outage conditions due to continuing load growth in the area. The project scope is to replace 3.98 miles 12

of 336 ACSR conductor in the Morro leg of the Santiago-Borrego-Morro 66 kV Subtransmission Line 13

with higher capacity rated 954 SAC conductor. Without this project, loading on the Morro leg of the 14

Santiago-Borrego-Morro 66 kV Subtransmission Line is projected to reach 116.6 percent of its capacity 15

by 2013 under N-1 line outage conditions. The operating date is March 2013 with a total project cost of 16

$5.586 million.73 This project was included in SCE’s 2012 GRC filing with a June 2012 operating date 17

but was subsequently moved to March 2013 due to delays in acquiring the necessary permits to 18

construct the project. 19

SCE has identified one alternative to this project–to construct a new 6.3 20

mile long, 66 kV subtransmission line from Borrego Substation to Niguel Substation. The total 21

estimated cost of this alternative is $9.232 million. The proposed project was selected as the least cost 22

alternative. 23

(3) Etiwanda-Alder-Randall 66kV Reconductor (Project #06028) 24

The Etiwanda-Alder-Randall 66 kV Subtransmission Line serves Alder 25

Substation in the city of Rialto and Randall Substation in the city of Fontana. As of 2012, loading on the 26

Etiwanda-Alder-Randall 66 kV Subtransmission Line exceeded its capacity limit due to continued load 27

growth in the area. The project scope is to replace 3.0 miles of 653 aluminum conductor in the 28

Etiwanda-Alder-Randall 66 kV Subtransmission Line with higher capacity rated 954 aluminum 29

73 Refer to workpaper entitled “Santiago-Borrego-Morro 66 kV Reconductor (Project #06392).”

51

conductor. Without this project, loading on the Etiwanda-Alder-Randall 66 kV Subtransmission Line is 1

projected to reach 108.4 percent under N-1 line outage conditions. The operating date is April 2013 2

with a total project cost of $2.293 million.74 This project was included in SCE’s 2012 GRC filing with a 3

June 2012 operating date but was subsequently moved to April 2013 due to delays in acquiring the 4

necessary permits to construct the project. 5


mile long, 66 kV subtransmission line from Etiwanda Substation to Randall Substation. The total 7


alternative. 9

(4) Alder-Declez 66 kV Recable Bundle (Project #05316) 10

The Alder-Declez 66 kV Subtransmission Line serves Alder Substation in 11

the city of Rialto and Declez Substation in the city of Fontana. By the end of 2013, loading on the 12

underground section of the Alder-Declez 66 kV Subtransmission Line is projected to exceed its capacity 13

limit due to continuing load growth in the area. The project scope is to bundle 0.98 miles of existing 14

1750 kcmil75 aluminum underground cable in the Alder-Declez 66 kV Subtransmission Line with a 15

parallel run of 1750 kcmil aluminum underground cable. Without this project, loading on the 16

underground section of the Alder-Declez 66 kV Subtransmission Line is projected to reach 101.6 17

percent of its capacity by the end of 2013 under N-1 line outage conditions. The operating date is June 18

2013 with a total project cost of $1.157 million.76 This project was included in SCE’s 2012 GRC filing 19

with a June 2010 operating date but was subsequently moved to June 2013 due to delays in acquiring the 20

necessary permits to construct the project. 21

SCE has identified one alternative to this project–to replace approximately 22

0.82 miles of existing 1750 kcmil aluminum underground cable in the Alder-Declez 66 kV 23

Subtransmission Line with higher capacity rated 3000 kcmil copper underground cable in a new 24

underground vault and conduit system. The total estimated cost of this alternative is $4.024 million. 25

The proposed project was selected as the least cost alternative. 26

74 Refer to workpaper entitled “Etiwanda-Alder-Randall 66 kV Reconductor (Project #06028).”

75 kcmil is an abbreviation for one thousand circular mils. A circular mil is a unit of area, equal to the area of a circle with a diameter of one mil (one thousandth of an inch). A circular mil is a unit for referring to the area of the cross section of a wire or cable with a circular cross section.

76 Refer to workpaper entitled “Alder-Declez 66 kV Recable Bundle (Project #05316).”

52

(5) Camarillo Substation 66 kV Capacitor Bank (Project #07040) 1

Camarillo 66/12 kV Substation is located in the city of Camarillo. By the 2

end of 2013, the 66 kV bus voltage at Camarillo Substation is projected to fall below the minimum 3

acceptable level of 95 percent of nominal voltage due to continuing load growth in the area. The project 4

scope is to install one staged 28.8 MVAR, 66 kV switched capacitor bank at Camarillo Substation. 5

Without this project, the 66 kV bus voltage at Camarillo Substation is projected to drop 6.7 percent 6

below its nominal level by 2013 under N-1 line outage conditions. The operating date is June 2013 with 7

a total project cost of $1.851 million.77 8

SCE has identified one alternative to this project–to replace 19.1 miles of 9

conductor in the Santa Clara-Camarillo 66 kV Subtransmission Line with higher capacity rated 954 SAC 10

conductor. The total estimated cost of this alternative is $11.018 million. The proposed project was 11


(6) Weldon Substation 66 kV Capacitor Bank (Project #05364) 13

Weldon 66/12 kV Substation is located in the city of Weldon. By the end 14

of 2013, the 66 kV bus voltage at Weldon Substation is projected to fall below the minimum acceptable 15

level of 95 percent of nominal voltage due to continuing load growth in the area. The project scope is to 16

install a 10.8 MVAR, 66 kV switched capacitor bank at Weldon Substation. Without this project, the 66 17

kV bus voltage at Weldon Substation is projected to drop 7.6 percent below its nominal level by the end 18

of 2013 under normal operating conditions. The operating date is December 2013 with a total project 19

cost of $5.638 million.78 This project was included in SCE’s 2012 GRC filing with a June 2013 20

operating date but was subsequently moved to December 2013 due to delays in acquiring the necessary 21

permits to construct the project. 22


MVAR, 66 kV switched capacitor bank at Isabella Substation. The total estimated cost of this 24


(7) Mesa-Laguna Bell-Narrows 66 kV Reconductor (Project #06070) 26

The Mesa-Laguna Bell-Narrows 66 kV Subtransmission Line serves 27

Narrows Substation in the city of Pico Rivera and Laguna Bell Substation in the city of Commerce. By 28

77 Refer to workpaper entitled “Camarillo Substation 66 kV Capacitor Bank (Project #07040).”

78 Refer to workpaper entitled “Weldon Substation 66 kV Capacitor Bank (Project #05364).”

53

the end of 2013, loading on the Narrows leg of the Mesa-Laguna Bell-Narrows 66 kV Subtransmission 1

Line is projected to exceed its capacity limit due to continuing load growth in the area. The project 2

scope is to replace 2.3 miles of 336 ACSR conductor and 2.8 miles of 4/0 copper conductor in the 3

Narrows leg of the Mesa-Laguna Bell-Narrows 66 kV Subtransmission Line with higher capacity rated 4

954 SAC conductor. Without this project, loading on the Narrows leg of the Mesa-Laguna Bell-5

Narrows 66 kV Subtransmission Line is projected to reach 110.1 percent of its capacity by the end of 6

2013 under N-1 line outage conditions. The operating is December 2013 with a total project cost of 7

$4.208 million.79 8


mile long, 66 kV subtransmission line from Mesa Substation to Narrows Substation. The total estimated 10

cost of this alternative is $9.073 million. The proposed project was selected as the least cost alternative. 11

(8) Mesa-Rush No. 3 66 kV Recable (Project# 06844) 12

The Mesa-Rush No.3 66 kV Subtransmission Line serves Rush Substation 13

in the city of Rosemead. By 2014, loading on the Mesa-Rush No.3 66 kV Subtransmission Line is 14

projected to exceed its capacity limit due to continuing load growth in the area. The project scope is to 15

replace 0.6 miles of 1250 kcmil aluminum cable in the Mesa-Rush No. 3 66 kV Subtransmission Line 16

with the higher capacity rated 3000 kcmil copper cable. Without this project, loading on the Mesa-Rush 17

No.3 66 kV Subtransmission Line is projected to reach 101.9 percent of its capacity by 2014 under 18

normal operating conditions. The operating date is June 2014 with a total project cost of $1.438 19

million.80 20

SCE has identified one alternative to this project—to construct a new 1.5 21

mile long subtransmission line from the Mesa-Rosemead No. 2 66 kV subtransmission line to Rush 22

Substation. The total estimated cost of this alternative is $4.384 million. The proposed project was 23


(9) Carodean Substation 115 kV Capacitor Bank (Project# 07208) 25

Carodean 115/12 kV Substation is located in the city of Twenty -Nine 26

Palms. By 2014 the 115 kV bus voltage at Carodean Substation is projected to fall below the minimum 27

acceptable level of 95 percent of nominal voltage due to continuing load growth in the area. The project 28

79 Refer to workpaper entitled “Mesa-Laguna Bell-Narrows 66 kV Reconductor (Project #06070).”

80 Refer to workpaper entitled “Mesa-Rush No. 3 66 kV Recable (Project #06844).”

54

scope is to install two 14.4MVAR, 115 kV switched capacitor banks at Carodean Substation. Without 1

this project, the 66 kV bus voltage at Carodean Substation is projected to drop 6.2 percent below its 2

nominal level by 2014 under N-1 line outage conditions. The operating date is June 2014 with a total 3

project cost of $1.055 million.81 4

SCE has identified one alternative to this project–to install a 28.8 MVAR, 5

115 kV switched capacitor bank at Hi Desert 115/12 kV Substation. The total estimated cost of this 6


(10) La Cienega Subtransmission Line Project (Project #07505, #07506, 8

#07383, #06382) 9

Project #07505: The La Cienega-Beverly-Culver 66 kV Subtransmission 10

Line serves Beverly Substation in the city of Beverly Hills and Culver Substation in the city of Culver 11

City. By 2015, the Beverly leg of the La Cienega-Beverly-Culver 66 kV Subtransmission Line is 12

expected to exceed its capacity limit due to continuing load growth in the area. The project scope is to 13

replace 2.76 miles of 1750 kcmil aluminum underground cable with higher capacity rated 2000 kcmil 14

copper underground cable and replace 0.47 miles of 1750 kcmil aluminum underground cable with 15

higher capacity rated 3000 kcmil copper underground cable in the Beverly leg of the La Cienega-16

Beverly-Culver 66 kV Subtransmission Line. Without this project, loading on the Beverly leg of the La 17

Cienega-Beverly-Culver 66 kV Subtransmission Line is projected to reach 101 percent of its capacity by 18

2015 under N-1 line outage conditions. The operating date is June 2015 with a total project cost of 19

$4.565 million.82 20

Project #07506: The Culver-Sawtelle 66 kV Subtransmission Line serves 21

Culver Substation in the city of Culver City and Sawtelle Substation in the city of Los Angeles. By 22

2019, the Culver-Sawtelle 66 kV Subtransmission Line is expected to exceed its capacity limit due to 23

continuing load growth in the area. The project scope is to replace .47 miles of 1750 kcmil aluminum 24

underground cable in the Culver-Sawtelle 66 kV Subtransmission Line with higher capacity rated 3000 25

kcmil copper underground cable. All of this scope of work will be located in the same structures that 26

Project # 07505 is located in. Without this project, loading on the Culver-Sawtelle 66 kV 27

Subtransmission Line is projected to reach 100.6 percent of its capacity by 2019 under N-1 line outage 28

81 Refer to workpaper entitled “Carodean Substation 115 kV Capacitor Bank (Project #07208).”

82 Refer to workpaper entitled “La Cienega-Beverly-Culver 66 kV Recable: Beverly Leg (Project #07505).”

55

conditions. In order to reduce outages and coordinate work with Project # 07505, the operating date for 1

the Culver-Sawtelle project is June 2015 with a total project cost of $1.098 million.83 2

Project #07383: The La Cienega-Beverly-Culver 66 kV line serves 3

Beverly Substation in the city of Beverly Hills and Culver Substation in the city of Culver City. By 4

2015, the La Cienega leg of the La Cienega-Beverly-Culver 66 kV Subtransmission Line is expected to 5

approach its capacity limit due to continuing load growth in the area. The project scope is to replace 1.2 6

miles of 1750 kcmil aluminum underground cable in the La Cienega leg of the La Cienega-Beverly-7

Culver 66 kV Subtransmission Line with higher capacity rated 3000 kcmil copper underground cable. 8

Without this project, loading on the La Cienega leg of the La Cienega-Beverly-Culver 66 kV 9

Subtransmission Line is projected to reach 100 percent of its capacity by 2015 under N-1 line outage 10

conditions. The operating date is June 2015 with a total project cost of $4.775 million.84 11

Project #06382: The La Cienega-Culver 66 kV line serves Culver 12

Substation in the city of Culver City. By 2015, La Cienega -Culver 66 kV Subtransmission Line is 13

expected to approach its capacity limit due to continuing load growth in the area. The project scope is to 14

replace 1.2 miles of 1750 kcmil aluminum underground cable with higher capacity rated kcmil copper 15

underground cable in the La Cienega -Culver 66 kV Subtransmission Line. Without this project, 16

loading on the La Cienega -Culver 66 kV Subtransmission Line is projected to reach 100 percent of its 17

capacity by 2015 under N-1 line outage conditions. The operating date is June 2015 with a total project 18

cost of $4.771 million.85 19

SCE has identified one alternative to these projects–to construct a second 20

66 kV subtransmission line from La Cienega to Culver in existing ducts and structures. This alternative 21

defers or eliminates the need for 4 subtransmission lines projects: Project #s 7383, 6382, 7505 and 22

7506. The total estimated cost of this alternative is $27.522 million. The sum of the four proposed 23

subtransmission lines projects is more cost effective than the alternative. The proposed projects were 24

selected as the least cost alternatives. 25

83 Refer to workpaper entitled “Culver-Sawtelle 66 kV Recable (Project #07506).”

84 Refer to workpaper entitled “La Cienega-Beverly-Culver 66 kV Recable: La Cienega Leg (Project #07383).”

85 Refer to workpaper entitled “La Cienega-Culver 66 kV Recable (Project #06382).”

56

(11) Springville-Strathmore 66 kV Reconductor (Project #07507) 1

The Springville-Strathmore 66 kV Subtransmission Line serves 2

Strathmore Substation in Strathmore. By 2015, loading on the Springville-Strathmore 66 kV 3

Subtransmission Line is projected to exceed its capacity limit due to continuing load growth in the area. 4

The project scope is to replace 7.2 miles of 2/0 copper conductor in the Springville-Strathmore 66 kV 5

Subtransmission Line with higher capacity rated 954 SAC conductor. Without this project, loading on 6

the Springville-Strathmore 66 kV Subtransmission Line is projected to reach 112.8 percent under N-1 7

line outage conditions. The operating date is June 2015 with a total project cost of $4.262 million.86 8

SCE has identified one alternative to this project–to construct a new 10 9

mile long, 66 kV subtransmission line from Springville Substation to Strathmore Substation. The total 10

estimated cost of this alternative is $47,630 million. The proposed project was selected as the least cost 11

alternative. 12

(12) Vestal-Columbine-Delano-Earlimart 66 kV Reconductor (Project 13

#07508) 14

The Vestal-Columbine-Delano-Earlimart 66 kV Subtransmission Line 15

serves Columbine Substation in the city of Delano, Delano Substation in the city of Delano, and 16

Earlimart Substation in Earlimart. In 2015, loading on the Earlimart leg of the Vestal-Columbine-17

Delano-Earlimart 66 kV Subtransmission Line is projected to exceed its capacity limit due to continuing 18

load growth in the area. The project scope is to replace 4.0 miles of 4/0 aluminum conductor in the 19

Earlimart leg of the Vestal-Columbine-Delano-Earlimart 66 kV Subtransmission Line with higher 20

capacity rated 954 SAC conductor. Without this project, the loading on the Vestal-Columbine-Delano-21

Earlimart 66 kV Subtransmission Line is projected to reach 104.2 percent of its capacity by 2015 under 22

N-1 line outage conditions. The operating date is June 2015 with a total project cost of $4.544 million.87 23


mile long, 66 kV subtransmission line from Vestal Substation to Earlimart Substation. The total 25


alternative. 27

86 Refer to workpaper entitled “Springville-Strathmore 66 kV Reconductor (Project #07507).”

87 Refer to workpaper entitled “Vestal-Columbine-Delano-Earlimart 66 kV Reconductor (Project #07508).”

57

(13) Vestal-Delano-Browning 66 kV Reconductor (Project #07512) 1

The Vestal- Delano-Browning 66 kV Subtransmission Line serves Delano 2

Substation in the city of Delano and Browning Substation in the city of Delano. By 2015, the Delano 3

leg of the Vestal-Delano-Browning 66 kV Subtransmission Line is projected to exceed it capacity limit 4

due to continuing load growth in the area. The project scope is to replace 2.1 miles of 2/0 copper 5

conductor on the Delano leg of the Vestal-Delano-Browning 66 kV Subtransmission Line with higher 6

capacity rated 954 SAC conductor. Without this project, loading on the Delano leg of the Vestal-7

Delano-Browing 66 kV Subtransmission Line is projected to reach 115.8 percent of its capacity by 2015 8

under N-1 line outage conditions. The operating date is June 2015 with a total project cost of $1.245 9

million.88 10


mile long, 66 kV subtransmission line from Vestal Substation to Delano Substation. The total estimated 12

cost of this alternative is $19.027 million. The proposed project was selected as the least cost 13

alternative. 14

(14) Arrowhead Reconfiguration Project (Project #04891) 15

Arrowhead 115/33 kV Substation is located in the city of Arrowhead and 16

is currently provided with preferred/emergency service from two 115 kV source lines. During an outage 17

of the preferred line that serves the station, customers in the Lake Arrowhead area served by Arrowhead 18

Substation experience several seconds or more of service interruption until automatic controls switch the 19

substation to its emergency feed. By converting Arrowhead Substation to looped 115 kV service, these 20

momentary service interruptions can be eliminated. The project scope is to rearrange the 115 kV lines 21

serving Arrowhead Substation and install protective relaying circuits as necessary to convert Arrowhead 22

Substation from preferred/emergency 115 kV service to two line loop 115 kV service. The operating 23

date is December 2015 with a total project cost of $4.753 million.89 This project was included in SCE’s 24

2012 GRC filing with a December 2012 operating date but was subsequently moved to December 2015 25

due to project prioritization. 26


mile long, 115 kV subtransmission line from Shandin Substation to Arrowhead Substation. The total 28

88 Refer to workpaper entitled “Vestal-Delano-Browning 66 kV Reconductor (Project #07512).”

89 Refer to workpaper entitled “Arrowhead Reconfiguration Project (Project #04891).”

58


alternative. 2

(15) Valley-Ivyglen 115 kV Line (Project #06030) 3

The Valley-Elsinore-Fogarty 115 kV line serves Elsinore Substation in the 4

city of Elsinore and Fogarty Substation in the city of Lake Elsinore. By 2015, loading on the Valley leg 5

of the Valley-Elsinore-Fogarty 115 kV line is projected to exceed its capacity limit due to continuing 6

load growth in the area. The project scope is to construct a new 26 mile long, 115 kV line from Valley 7

Substation to Ivyglen Substation. Without this project, loading on the Valley leg of the Valley-Elsinore-8

Fogarty 115 kV is projected to reach 110.5 percent of its capacity by 2015 under N-1 line outage 9

conditions. This project is separated into two phases. Phase 1 includes constructing 13 miles of 115 kV 10

line and has an operating date of December 2014. Phase 2 includes constructing the remaining 13 miles 11

of 115 kV subtransmission line and has and operating date of December 2015. The total project cost is 12

$111.821 million.90 This project was included in SCE’s 2012 GRC filing with a June 2012 operating 13

date but was subsequently moved to December 2014 (Phase I) and December 2015 (Phase 2) due to 14

delays in acquiring the necessary permits to construct the project. 15

SCE has identified one alternative to this project–to convert Ivyglen 16

115/12 kV Substation to a 66/12 kV substation and construct three new approximately 10 mile 66 kV 17

subtransmission lines. The alternative analysis was included in the PEA (Application A.07-01-031, filed 18

February 16, 2007 and A.07-04-028 filed April 30, 2007). The total estimated cost of this alternative is 19

$125.864 million. The proposed project was selected as the least cost alternative. 20

(16) Santa Barbara County Reliability Project (Project #04518) 21

The Goleta-Santa Clara No.1 and No.2 220 kV transmission lines feed 22

Goleta 220/66 kV Substation, which serves approximately 83,000 metered customers in the city of Santa 23

Barbara and surrounding communities. The Goleta-Santa Clara No. 1 and No. 2 220 kV Transmission 24

Lines are approximately 49 miles long, run on a common steel tower over hilly terrain subject to 25

mudslides during rainy conditions, and are the sole feed to Goleta 220/66 kV Substation. The project 26

scope is to rebuild approximately 32.8 miles of existing 2/0 copper conductor 66 kV subtransmission 27

line connecting the Goleta 66 kV system and the Santa Clara 66 kV system with higher capacity rated 28

954 Aluminum Conductor Steel Reinforced conductor. Rebuilding this 66 kV subtransmission line will 29

90 Refer to workpaper entitled “Valley-Ivy Glen 115 kV Line (Project #06030).”

59

allow approximately two-thirds of the load served by Goleta 220/66 kV Substation to be safely and 1

reliably transferred to the neighboring Santa Clara 220/66 kV Substation during an outage of the Goleta-2

Santa Clara No.1 and No.2 220 kV Transmission Lines. The operating date is June 2016 with a total 3

project cost of $67.328 million.91 This project was included in SCE’s 2012 GRC filing with a June 2012 4

operating date but was subsequently moved to June 2016 due to the CPUC requesting that the project go 5

through licensing. 6

SCE identified one alternative to this project–to construct a new 50 mile 7

220 kV transmission line from Santa Clara 220/66 kV Substation to Goleta 220/66 kV Substation. The 8

alternative analysis can be found in the PEA (Application A.12-10-018 filed October 26, 2012). The 9

total estimated cost of this alternative is $145.036 million. The proposed project was selected as the 10

least cost alternative. 11

(17) Moorpark-Newbury 66 kV Line (Project #05329) 12

Newbury 66/12 kV Substation is located in city of Thousand Oaks. By 13

2020, the 66 kV bus voltage at Newbury is projected to fall below the minimum acceptable level of 95 14

percent of nominal voltage due to continuing load growth in the area. The project scope is to construct a 15

new 9.4 mile, 66 kV subtransmission line from Moorpark Substation to Newbury Substation. Without 16

this project, the 66 kV bus voltage at Newbury Substation is projected to drop 5.2 percent below its 17

nominal level by 2020 under “high case”, N-1 line outage conditions. 18

By way of background, in 2005, Southern California Edison Company 19

(SCE) initiated the Moorpark-Newbury 66 kV Subtransmission Line Project. This Project was first 20

identified to address forecasted overloads on the section of the existing Moorpark-Newbury-Pharmacy 21

66 kV Subtransmission Line (a.k.a. Moorpark-Newbury tap). In addition, the Project also would 22

enhance reliability and operational flexibility. 23

On October 2, 2008, SCE filed Advice Letter 2272-E, notifying the 24

California Public Utilities Commission (CPUC) of the proposed construction of the Moorpark-Newbury 25

66 kV Subtransmission Line Project. Advice Letter 2272-E explained that the Project would be exempt 26

from Permit to Construct requirements pursuant to General Order 131-D (GO 131-D), Section III, 27

Subsection B.1.g. (“Exemption G.”). In response to protests to the Advice Letter, the CPUC in February 28

91 Refer to workpaper entitled “Santa Barbara County Reliability Project (Project #04518).”

60

2009 issued Executive Director’s Action Resolution E-4225, finding that SCE’s Moorpark-Newbury 66 1

kV Subtransmission Line Project qualified for Exemption g and dismissed the protests. 2

Thereafter, the Executive Director’s issuance of Resolution E-4225 was 3

appealed and the CPUC prepared Commission Resolution E-4243 for consideration at the June 18, 2009 4

Commission Business Meeting. As originally drafted, Resolution E-4243 would have affirmed 5

Resolution E-4225. However, in response to a subsequent request from a local official, the CPUC 6

removed Resolution E-4243 from the June 18, 2009 Commission Business Meeting agenda, and in 7

September 2009, held a public participation hearing where comments from the public were received. In 8

addition, SCE participated in a series of meetings with interested stakeholders and a local official during 9

2009 and 2010. Following these additional meetings, Resolution E-4243 (updated to reflect the 10

meetings and hearing which took place during 2009 and 2010) was heard and approved by the 11

Commission at a Business Meeting in March 2010. As approved, Resolution E-4243 affirmed the 12

findings of the previously issued Resolution E-4225, found that SCE’s Moorpark-Newbury 66 kV 13

Subtransmission Line Project qualified for Exemption g, and dismissed the protests. In dismissing the 14

protests, Resolution E-4243 stated that the protests “…did not allege facts that would trigger the 15

Exception Criteria contained within GO 131-D, Section III, Subsection B.2.a.-c.” By its own terms, 16

Resolution E-4243 went into effect on the day it was approved. 17

However, in April 2010, several individuals filed an Application for a 18

Rehearing of the Commission’s approval of Resolution E-4243. Because that Application for Rehearing 19

did not request a stay of construction, and because the CPUC did not issue a stay of construction, SCE 20

informed the CPUC Energy Division that it planned to start construction of the Project in fall 2010. 21

Consistent with that communication, construction of the Project commenced in October 2010, with a 22

planned operational date of June 2012. However, in November 2011, all construction activity was 23

halted due to the issuance of CPUC Decision 11-11-019 (D.11-11-019). This Decision ordered SCE to 24

cease construction activity, provide certain specified information and file a Permit to Construct (PTC) 25

Application if it wishes to build the Project. 26

Approximately 60 percent of this new line has been constructed. It is 27

expected that SCE will complete the construction of this project by June 2016. The operating date for 28

this project is June 2016 with a total project cost of $23.058 million.92 29

92 Refer to workpaper entitled “Moorpark-Newbury 66 kV Line (Project #05329).”

61

SCE has identified one alternative to this project– to replace 7.3 miles of 1

existing conductor with higher capacity rated 954 SAC conductor on the Moorpark-Newbury-Pharmacy 2

Subtransmission Line and replace 12.6 miles of existing conductor with higher capacity rated 954 SAC 3

conductor in the Newbury-Thousand Oaks 66 kV Subtransmission Line. The cost for the work that has 4

been completed for the proposed Moorpark-Newbury 66 kV Subtransmission Line has been included. 5

The total estimated cost of this alternative is $27.899 million. The proposed project was selected as the 6

least cost alternative. 7

(18) Yucca 115/12 kV Substation Loop-In (Project #07382) 8

Yucca 115/12 kV Substation is located in the town of Yucca Valley and is 9

currently provided with preferred/emergency service from two 115 kV source lines. During an outage 10

of the preferred line that serves the station, all of the approximately 11,400 metered customers in the 11

Yucca Valley area served by Yucca Substation experience several seconds or more of service 12

interruption until automatic controls switch the substation to its emergency feed. Additionally, in the 13

event of a fault on the Hi Desert switchrack all of the customers served by Hi Desert, Leatherneck, and 14

Carodean will experience a prolonged service interruption. By converting Yucca Substation to looped 15

115 kV service and rearranging subtransmission lines to tap Hi Desert Substation, all these interruptions 16

can be eliminated. The project scope is to rearrange the Devers-Hi Desert-Yucca 115 kV line and the Hi 17

Desert-Leatherneck line to form the Devers-Yucca line and the Yucca-Hi Desert-Leatherneck line. This 18

will convert Yucca Substation from preferred/emergency 115 kV service to two line loop 115 kV 19

service. The operating date is June 2016 with a total project cost of $3.754 million.93 20

SCE has identified one alternative to this project - to build a new 20 mile 21

115 kV subtransmission line from Devers Substation to Yucca Substation. The total estimated cost of 22

this alternative is $18.472 million. The proposed project was selected as the least cost alternative. 23

(19) Santiago-Irvine No. 2 66 kV Recable (Project #07384) 24

The Santiago-Irvine No.2 66 kV Subtransmission Line serves Irvine 25

Substation in the city of Irvine. By 2016, loading on the Santiago-Irvine No.2 66 kV Subtransmission 26

Line is projected to exceed its capacity limit due to continuing load growth in the area. The project 27

scope is to replace 1.0 mile of 1750 kcmil aluminum underground cable in the Santiago-Irvine No. 2 66 28

kV Subtransmission Line with 3000 copper underground cable. Without this project, loading on the 29

93 Refer to workpaper entitled “Yucca 115/12 kV Substation Loop-In (Project #07382).”

62

Santiago-Irvine No. 2 66 kV Subtransmission Line is projected to reach 103.8 percent of its capacity by 1

2016 under N-1 line outage conditions. The operating date is Jun 2016 with a total project cost of $2.119 2

million.94 3

SCE has identified one alternative to this project–To construct a new 10.6 4

mile long, 66 kV subtransmission line from Santiago Substation to Las Lomas Substation. The total 5


alternative. 7

3. Subtransmission VAR Plan 8

Capacitor banks are installed throughout our system to supply needed reactive power 9

(VAR)95 and help maintain adequate voltage as shown below in Figure I-7. We review requirements for 10

66 kV and 115 kV substation capacitor banks over a ten-year planning horizon. Without a 11

comprehensive Subtransmission VAR Plan, we would run the risk of reactive power deficiency on the 12

subtransmission system as the demand for electricity continues to increase in our service territory. 13

Inadequate subtransmission reactive power supply could compromise our ability to provide adequate 14

voltage to our end-use customers and, in a worst-case scenario, result in cascading outages and 15

widespread blackouts after disturbances on our high voltage transmission grid. 16

The objective of the Subtransmission VAR Plan is to fully supply the reactive power 17

needs of each of our 66 kV and 115 kV subtransmission networks (including A-banks) under a heat 18

storm condition. In practical terms, this means maintaining zero VAR flow at the high voltage side of 19

our A-banks, at the interface between our transmission system and our subtransmission system. We 20

compare reactive power supplies (primarily 66 kV and 115 kV capacitor banks) in each of our 21

subtransmission networks versus the projected reactive power needs of our A-banks, subtransmission 22

lines, and any large customers we serve at the subtransmission voltage level. When we forecast that a 23

subtransmission network will have a VAR deficiency within our ten-year planning horizon, we sponsor 24

94 Refer to workpaper entitled “Santiago-Irvine No. 2 66 kV Recable (Project #07384).”

95 VAR is an acronym for Voltage Ampere Reactive (see www.ibiblio.org/obp/electricCircuits/AC/AC_11.html for a description of Voltage Ampere Reactive).

63

a capital project to install a 66 kV or 115 kV substation capacitor bank. These capacitor banks are 1

typically installed at the low voltage side of our A-substations.96 2

Figure I-7 Subtransmission VAR Plan

We have identified one project with costs >$1 million. Our forecast for that project is 3

shown in Table I-13 below. 4

96 If there are physical space constraints that prohibit us from installing a needed capacitor bank at an A-substation, we will

instead consider installing the capacitor bank at the high voltage side of one of the downstream B-substations served by the A-substation.

64

Table I-13 Subtransmission VAR Plan Capital Expenditure Summary

(Total Company Nominal $000) Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 06822 Bunker 115 kV Cap Bank Addition Jun 2013 1,965 111 - - - - 2,076

(1) Bunker 115 kV Cap Bank Addition (Project #06822) 1

Bunker Substation is located in the city of Perris. This project is needed to 2

correct a VAR deficiency of 57.6 MVAR in the Valley 115 kV system in 2013. The scope of this 3

project is to add a 46.8 MVAR, 115 kV switched capacitor bank. The total cost is $2.076 million with 4

an operating date of June 2013. No cost-effective alternatives are available for projects required to add 5

reactive compensation. The operating date is June 2013 with a total project cost of $2.076 million.97 6


subsequently moved to June 2013 due to delays in acquiring the necessary permits to construct the 8

project. 9

4. Distribution Substation Plan (DSP) 10

As discussed earlier, B-banks are step-down transformers located at our B-substations 11

that reduce our system voltage from the subtransmission level (66 kV or 115 kV) to the distribution 12

level (typically 4 kV, 12 kV, or 16 kV). As also discussed earlier, distribution circuits (typically 13

operating at 4 kV, 12 kV, or 16 kV) deliver electricity from the low voltage side of our B-substations to 14

service transformers located near our customers premises. In the Distribution Substation Plan (DSP), we 15

annually review requirements for our B-banks and distribution circuits over a ten-year planning horizon. 16

Without a comprehensive DSP, we would run the risk of loading our B-banks and/or distribution circuits 17

beyond their capabilities as the demand for electricity continues to increase in our service territory. This 18

could ultimately result in B-bank and/or circuit equipment failures and service interruptions to thousands 19

of customers in localized geographic areas. 20

The objective of the DSP, as shown in Figure I-8 below, is to provide for adequate B-21

bank capacity and distribution circuit capacity to serve forecast peak loads under a one-in-ten year heat 22

storm condition. We evaluate the ability of each B-bank and distribution circuit to operate within its 23

97 Refer to workpaper entitled “Bunker 115 kV Cap Bank Addition (Project #06822).”

65

established loading limits under normal conditions with all facilities in service (“base case”), and also 1

under contingency conditions when critical equipment is out of service (“N-1”). When we forecast that 2

a B-bank or distribution circuit will become overloaded during our ten-year planning horizon, we are 3

often able to relieve the overload by rearranging our existing distribution circuitry and transferring load 4

to an adjacent B-bank or distribution circuit with available capacity. If these load transfers are 5

insufficient to relieve the overload, we sponsor a capital project to expand, upgrade, or reinforce our 6

distribution system. Typical projects in the DSP include installing new B-banks at existing B-7

substations, replacing existing B-banks with higher capacity rated B-banks, developing new 66/12 kV, 8

66/16 kV, or 115/12 kV B-substations, and constructing new 12 kV or 16 kV distribution circuits. 9

Figure I-8 Distribution Substation Plan (DSP)

Table I-14 below provides Distribution Substation Plan costs we have already incurred 10

(i.e., expenditures made in 2012 or prior years for projects that will be completed in the 2013-2017 11

period) and forecast costs for projects planned to be completed through 2014. 12

66

Table I-14 Distribution Substation Plan Capital Expenditure Summary

(100% CPUC-Jurisdictional Nominal $000)

Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 04422 Las Lomas 66/12 kV Substation Nov 2012 44,817 3,000 - - - - 47,817 2 05396 Mascot 66/12 kV Substation Dec 2012 27,104 325 - - - - 27,429 3 05353 Triton 115/12 kV Substation Apr 2013 29,146 2,470 - - - - 31,616 4 04458 Pepper 115/12 kV Substation Jun 2013 3,666 5,519 - - - - 9,185 5 05023 El Sobrante 33/12 kV Substation Jun 2013 5,163 3,363 - - - - 8,526 6 05432 Roadway 115/12 kV Substation Jun 2013 4,497 7,304 - - - - 11,800 7 06093 Bloomington 66/12 kV Substation Jun 2013 684 2,958 - - - - 3,642 8 06220 Fillmore 66/16 kV Substation Jun 2013 3,006 1,085 - - - - 4,091 9 06577 Devers 115/12 kV Substation Jun 2013 8,485 8,249 - - - - 16,734

10 06605 La Habra Project 66/12 kV Substation Jun 2013 3,740 10,938 - - - - 14,677 11 06870 Estrella 66/12 kV Substation Jun 2013 1,456 3,317 - - - - 4,773 12 06948 Carodean 115/12 kV Substation Jun 2013 2,904 3,034 - - - - 5,938 13 07160 Delano 66/12kV Substation Jun 2013 6,008 5,599 - - - - 11,607 14 04445 Glen Avon 66/12 kV Substation Jun 2013 2,103 499 - - - - 2,603 15 06292 Lampson 66/12 kV Substation Jun 2014 0 1,557 2,390 - - - 3,947 16 06691 Downs 115/12 kV Substation Jun 2014 2,163 10,777 19,315 - - - 32,256 17 06958 Pebbly Beach 12/2.4 kV Substation Jun 2014 783 614 315 - - - 1,712 18 07216 Del Amo Jr 66/12 kV Substation Jun 2014 661 1,491 24,626 - - - 26,778 19 07263 La Palma 66/12 kV Substation Jun 2014 48 7,842 5,922 - - - 13,812 20 07391 Lark Ellen 66/12 kV Substation Jun 2014 175 2,448 1,763 - - - 4,385 21 05403 Colonia 66/16 kV Substation Jun 2015 129 320 2,878 3,686 - - 7,014 22 06301 Canyon 66/12 kV Substation Jun 2015 220 2,259 1,349 809 - - 4,637 23 07307 San Dimas 66/12 kV Substation Jun 2015 - - 671 672 - - 1,343 24 07480 Orange 66/12 kV Substation Jun 2015 - 142 7,280 7,286 - - 14,708 25 05411 Lakeview 115/12 kV Substation Jun 2016 3,072 4,605 27,838 22,945 6,550 - 65,011 26 06067 Yokohl 66/12 kV Substation Jun 2016 95 4,140 10,060 30,329 43,410 - 88,034 27 06619 Banducci 66/12 kV Substation Jun 2016 2,252 2,830 5,353 21,257 10,413 - 42,105 28 06836 Greenhorn 66/2.4 kV Substation Jun 2016 - - 500 2,053 1,555 - 4,108 29 07293 Mainframe 66/4.16 kV Substation Jun 2016 - 2,223 2,279 12,675 7,519 - 24,696 30 07516 Safari 33/12 kV Substation Jun 2016 - - 6,587 23,103 17,097 - 46,787 31 06575 Circle City 66/12 kV Substation - Phase 1 Jun 2016 - 724 5,687 14,140 4,647 - 25,198 32 05397 Falcon Ridge 66/12 kV Substation Dec 2016 3,316 2,698 8,809 24,255 44,475 - 83,554 33 Total Distribution Substation Plan 155,694 102,329 133,621 163,212 135,666 - 690,522

The capital cost shown for each project in the table above is for work required inside the 1

substation (e.g., the addition of a B-bank transformer), new distribution circuits associated with a B-2

bank transformer addition, and any telecommunications or right of way and land components of the 3

project. The costs for the distribution circuits that are not associated B-bank transformer addition 4

projects are aggregated and budgeted as a separate item entitled “DSP Circuits” and are included in this 5

portion of my testimony for reference and justification purposes only. These circuit costs are discussed 6

separately in the System Improvement/Reinforcements Program portion of my testimony. 7

We have identified 32 DSP projects with project costs equal to or greater than $1 million. 8

A description and justification for each of these projects is provided below. The total cost for these 32 9

projects is $690.5 million of which $534.8 million is CPUC-jurisdictional cost forecast from 2013 to 10

2017. 11

67

(1) Las Lomas 66/12 kV Substation (Project #04422) 1

Las Lomas 66/12 kV Substation is a new planned substation to be located 2

in the city of Irvine. As of 2012, Bryan 66/12 kV Substation, Irvine 66/12 kV Substation, and Modena 3

66/12kV Substation (serving a combined total of approximately 66,100 metered customers) are 4

projected to approach their respective capacity limits due to continuing load growth in the Irvine area 5

and the development of the decommissioned El Toro MCAS base. The project scope is to construct a 6

new substation consisting of two 28 MVA, 66/12 kV transformer banks and five new 12 kV circuits. 7

The substation, subtransmission, and telecommunications cost is $39.099 million. The operating date 8

was November 2012; however, minor residual work is required in 2013 prior to closing this project. 9

The estimated total project cost is $47.817 million.98 10

SCE identified one alternative to this project–to replace an existing 22.4 11

MVA transformer bank at Irvine 66/12 kV Substation with a new 28 MVA transformer bank and 12

construct four new 12 kV distribution circuits. This alternative does not eliminate the need for Las 13

Lomas 66/12 kV Substation, but instead would have only defers the need by five years (from 2012 to 14

2017). This alternative does not adequately meet long-term projected electrical load requirements in the 15

Irvine area, and for this reason the proposed project was selected as the preferred alternative. 16

(2) Mascot 66/12 kV Substation (Project #05396) 17

Mascot 66/12 kV Substation99 is a new planned substation to be located in 18

the city of Hanford. By the end of 2013, Hanford 66/12 kV Substation (serving approximately 23,600 19

metered customers) is projected to approach its capacity limit due to continuing load growth in the 20

Hanford area. The project scope is to construct a new substation consisting of two 28 MVA, 66/12 kV 21

transformer banks and four new 12 kV distribution circuits. Without the project, the loading at Hanford 22

66/12 kV Substation is projected to reach 97.8 percent of the substation’s capacity limit by the end of 23

2013 under normal operating conditions. This project was included in SCE’s 2012 GRC filing with a 24

June 2012 operating date but was subsequently moved to June 2013 due to delays in acquiring the 25

necessary permits to construct the project. The operating date was December 2012; however, minor 26

98 Refer to workpaper entitled “Las Lomas 66/12 kV Substation (Project #04422).”

99 See Application A.09-11-020 (Proponent’s Environmental Assessment–Mascot Substation Project) for a detailed discussion of the purpose and need for this project.

68

residual work is required in 2013 prior to closing this project. The estimated total project cost is 1

$27.429 million.100 2

There are no alternatives to this project that would reliably add long-term 3

capacity to the Hanford area. The proposed project is the only viable technical solution. 4

(3) Triton 115/12 kV Substation (Project #05353) 5

Triton 115/12 kV Substation101 is a new planned substation to be located 6

in the city of Temecula. By the end of 2013, Auld 115/33/12 kV Substation, Canine 33/12 kV 7

Substation, and Moraga 115/12 kV Substation (serving a combined total of approximately 45,100 8

metered customers) are projected to exceed their respective capacity limits due to continuing load 9

growth in the Temecula and Murrieta areas. The project scope is to construct a new substation 10

consisting of two 28 MVA, 115/12 kV transformer banks and six new 12 kV distribution circuits. This 11

project was included in SCE’s 2012 GRC filing with a June 2011 operating date but was subsequently 12

moved to June 2013 due to delays in acquiring the necessary permits to construct the project. The 13

operating date was April 2013 with a total project cost of $31.616 million.102 14


MVA, 33/12 kV substation in the Temecula area with four new 12kV distribution circuits and three new 16

33 kV underground distribution lines (each approximately seven miles long) to feed the new substation. 17

The alternative analysis is included in the PEA (Application A.08-11-019, filed November 21, 2008, 18

Decision 10-09-025). The total estimated cost or this alternative is $31.469 million. The proposed 19

project does not eliminate the need for Triton115/12 kV Substation, but instead would have only 20

deferred the need by 7 years (from 2013 to 2020). 21

(4) Pepper 115/12 kV Substation (Project #04458) 22

Pepper 115/12 kV Substation is located in the city of Rialto and serves 23

approximately 12,200 metered customers. By the end of 2013, Pepper 115/12 kV Substation is 24


add a new 28 MVA transformer bank (thereby increasing total transformer capacity from 48 MVA to 76 26

100 Refer to workpaper entitled “Mascot 66/12 kV Substation (Project #05396).”

101 See Application A.08-11-019 (Proponent’s Environmental Assessment–Triton Substation Project) for a detailed discussion of the purpose and need for this project.

102 Refer to workpaper entitled “Triton 115/12 kV Substation (Project #05353).”

69

MVA at the station), add one 4.8 MVAR capacitor, and construct one new 12 kV distribution circuit. 1

Without the project, the loading at Pepper 115/12 kV Substation is projected to reach 107.2 percent of 2

the substation’s capacity limit by 2013 under normal operating conditions. The operating date was June 3

2013 with a total project cost of $9.185 million.103 4

SCE has identified one alternative to this project–to replace an existing 5

10.5 MVA transformer bank at Rialto 33/12 kV Substation with two new 14 MVA transformer banks, 6

rebuild the 33 kV and 12 kV switchracks, and construct two new 12 kV distribution circuits. The total 7


alternative. 9

(5) El Sobrante 33/12 kV Substation (Project #05023) 10

El Sobrante 33/12 kV Substation is located in the city of Riverside and 11

serves approximately 3,500 metered customers. By the end of 2013, El Sobrante 33/12 kV Substation is 12


replace three existing 5.2 MVA transformer banks with two new 14 MVA transformer banks, thereby 14

increasing total transformer capacity from 15.6 MVA to 28 MVA at the station. Without the project, the 15

loading at El Sobrante 33/12 kV Substation is projected to reach 114.8 percent of the substation’s 16

capacity limit by the end of 2013 under normal operating conditions. The operating date was April 2013 17

with a total project cost of $8.526 million.104 This project was included in SCE’s 2012 GRC filing with 18

a June 2012 operating date but was subsequently moved to June 2013 due to project prioritization. 19

SCE has identified one alternative to this project–to convert El Sobrante 20

33/12 kV Substation to a 66/12 kV substation, which requires construction of approximately 21 miles of 21

new 66 kV subtransmission line. The total estimated cost of this alternative is $24.222 million. The 22


(6) Roadway 115/12 kV Substation (Project #05432) 24

Roadway 115/12 kV Substation is located in the city of Adelanto and 25

serves approximately 5,900 metered customers. By the end of 2013, Roadway 115/12 kV Substation is 26


add a new 28 MVA transformer bank (thereby increasing total transformer capacity from 28 MVA to 56 28

103 Refer to workpaper entitled “Pepper 115/12 kV Substation (Project #04458).”

104 Refer to workpaper entitled “El Sobrante 33/12 kV Substation (Project #05023).”

70

MVA at the station) and construct two new 12 kV distribution circuits. Without the project, the loading 1

at Roadway 115/12 kV Substation is projected to reach 102.0 percent of the substation’s capacity limit 2

by the end of 2013 under normal operating conditions. The operating date was June 2013 with a total 3



transformer bank and construct two new, lengthy 12 kV distribution circuits out of Aqueduct 115/12 kV 6

Substation, construct one new 12 kV distribution circuit out of Victor 115/12 kV Substation and 7

construct one new, lengthy 12 kV distribution circuit out of Phelan 115/12 kV. The total estimated cost 8


(7) Bloomington 66/12 kV Substation (Project #06093) 10

Bloomington 66/12 kV Substation is located in Bloomington and serves 11

approximately 16,900 metered customers. By the end of 2013, the Manning 12 kV and the Sanber 12 12

kV circuits out of the nearby Declez Substation are projected to approach their capacity limit due to 13

continuing load growth in the area. The project scope is to construct a new 12 kV distribution circuit 14

and extend the north and south 12 kV switchrack at Bloomington 66/12 kV Substation. Without the 15

project, the loading on the Manning 12 kV and the Sanber 12 kV is projected to reach 93.7 percent and 16

95.9 percent of the circuits’ respective capacity limits by 2013 under normal operating conditions. The 17

operating date was June 2013 with a total project cost of $3.642 million dollars.106 18

SCE has identified one alternative to this project–to replace two 22.4 19

MVA transformer banks with two 28 MVA transformer banks at Declez 66/12 kV Substation and 20

construct a new 12 kV distribution circuit out of Declez 66/12 kV Substation. The total estimated cost 21

for this alternative is $4.444 million. The proposed project was selected as the least cost alternative. 22

(8) Fillmore 66/16 kV Substation (Project #06220) 23

Fillmore 66/16 kV Substation is located in the city of Fillmore and serves 24

approximately 6,500 metered customers. By the end of 2013, Fillmore 66/16 kV Substation is projected 25

to approach its capacity limit due to continuing load growth in the area. The project scope is to replace a 26

15 MVA transformer bank with a new 28 MVA transformer bank, thereby increasing total transformer 27

capacity from 37.4 MVA to 50.4 MVA at the station. Without the project, the loading at Fillmore 66/16 28

105 Refer to workpaper entitled “Roadway 115/12 kV Substation (Project #05432).”

106 Refer to workpaper entitled “Bloomington 66/12 kV Substation (Project #06093).”

71

kV Substation is projected to reach 86.7 percent of the substation’s capacity limit by the end of 2013 1

under normal operating conditions. The operating date was June 2013 with a total project cost of $4.091 2

million.107 3

SCE has identified one alternative to this project–to construct one new, 4

lengthy 16 kV distribution circuit out of Wakefield 66/16 kV Substation to offload Fillmore 66/16 kV 5

Substation. The total estimated cost of this alternative is $6.884 million. The proposed project was 6


(9) Devers 115/12 kV Substation (Project #06577) 8

Coffee 33/12 kV Substation is located in the city of Desert Hot Springs 9

and approximately 12,000 metered customers, and is unable to be expanded. By the end of 2013, Coffee 10

33/12 kV Substation is projected to exceed its capacity limit due to continuing load growth in the area. 11

The project scope is to add a new 28 MVA transformer bank (thereby increasing total transformer 12

capacity from 28 MVA to 56 MVA at the station) and construct one new 12 kV distribution circuit at 13

nearby Devers 115/12 kV Substation. Without the project, the loading at Coffee 33/12 kV Substation is 14

projected to reach 105.5 percent of the substation’s capacity limit by the end of 2013 under normal 15

operating conditions. The addition of a second transformer bank at the station will also allow 16

maintenance to be performed on the existing transformer bank without dropping load. The operating 17

date is June 2013 with a total project cost of $16.734 million.108 18

SCE has identified one alternative to this project–to replace the existing 19

10.5 MVA transformer bank at Garnet 33/12 kV Substation with two new 14 MVA transformer banks, 20

rebuild the 12 kV switchrack and construct one new, lengthy 12 kV distribution circuit. The total 21

estimated cost of this alternative is $14.550 million. The proposed project was selected due to the 22

greater operating flexibility and enhancement to the reliability of the area. 23

(10) La Habra 66/12 kV Substation (Project #06605) 24

La Habra 66/12 kV Substation is located in the city of La Habra and 25

serves approximately 16,500 metered customers. By the end of 2013, La Habra 66/12 kV Substation is 26


to replace two existing 20 MVA transformer banks with two new 28 MVA transformer banks (thereby 28

107 Refer to workpaper entitled “Fillmore 66/16 kV Substation (Project #06220).”

108 Refer to workpaper entitled “Devers 115/12 kV Substation (Project #06577).”

72

increasing total transformer capacity from 84.8 MVA to 100.8 MVA at the station) and construct two 1

new 12 kV distribution circuits, bringing the total number of circuits to 14. Without the project, the 2

loading at La Habra 66/12 kV Substation is projected to reach 98.3 percent of the substation’s capacity 3

limit by the end of 2013 under normal operating conditions. The operating date was June 2013 with a 4

total project cost of $14.677 million.109 5


transformer bank at Olinda 66/12 kV Substation and construct two new, lengthy 12 kV distribution 7

circuits. The total estimated cost of this alternative is $19.203 million. The proposed project was 8


(11) Estrella 66/12 kV Substation (Project #06870) 10

Estrella 66/12 kV Substation is located in the city of Irvine and serves 11

approximately 11,100 metered customers. By the end of 2013, Estrella 66/12 kV Substation is projected 12

to approach its capacity limit due to continuing load growth in the area. The project scope is to replace 13

two existing 22.4 MVA transformer banks with two 28 MVA transformers (from 100.8 MVA to 112.0 14

MVA). Without the project, the loading at Estrella 66/12 kV Substation is projected to reach 95.4 15

percent of the substation's capacity limit by 2013 under normal operating conditions. The operating date 16

was May 2013 with a total project cost of $4.773 million.110 17


lengthy distribution circuit out of Santiago Substation. The total estimated cost of this alternative is 19


(12) Carodean 115/12 kV Substation (Project #06948) 21

Twenty-Nine Palms 33/12 kV Substation is located in the city of Twenty-22

Nine Palms, serves approximately 3,200 metered customers, and is unable to be expanded. By the end 23

of 2013, Twenty-Nine Palms 33/12 kV Substation is projected to approach its capacity limit due to 24

continuing load growth in the area. The project scope is to add a new 28 MVA transformer bank at 25

nearby Carodean 115/12 kV Substation (thereby increasing total transformer capacity from 14 MVA to 26

42 MVA at the station) and construct one new 12 kV distribution circuit. Without the project, the 27

loading at Twenty-Nine Palms 33/12 kV Substation is projected to reach 108.5 percent of the 28

109 Refer to workpaper entitled “La Habra 66/12 kV Substation (Project #06605).”

110 Refer to workpaper entitled “Estrella 66/12 kV Substation (Project #06870).”

73

substation’s capacity limit by the end of 2013 under normal operating conditions. This project was 1

included in SCE’s 2012 GRC filing with a June 2012 operating date but was subsequently moved to 2

June 2013 due to project prioritization. The operating date is July 2013 with a total project cost of 3

$5.938 million.111 4

SCE has identified one alternative to this project–to replace a 14 MVA 5

transformer bank with a 28 MVA transformer bank at Twenty-Nine Palms 33/12 kV Substation, rebuild 6

the existing 4.8 kV, 12 kV, and 33 kV switchracks. The total estimated cost of this alternative is $6.692 7


(13) Delano 66/12 kV Substation (Project #07160) 9

Delano 66/12 kV Substation is located in the city of Delano and serves 10

approximately 10,900 metered customers. By the end of 2013, Delano 66/12 kV Substation is projected 11

to exceed its capacity limit due to continuing load growth in the area. The project scope is to add a new 12

28 MVA transformer bank (increasing the capacity from 56 to 84 MVA). Construct one 12 kV circuit. 13

Rebuild the existing 12 kV bus and construct a new Mechanical Electrical Equipment Room (MEER). 14

Without the project, the loading at Delano 66/12 kV Substation is projected to reach 111.9 percent of the 15

substation's capacity limit by the end of 2013 under normal operating conditions. The operating date 16

was June 2013 with a total project cost of $11.607 million.112 17

SCE has identified one alternative to this project–to increase the 18

transformer capacity at Browning 66/12 kV Substation from 13 MVA to 56 MVA, rebuild the 12 kV 19

switchrack and construct one new 12 kV distribution circuits. The scope of this alternative requires 20

Browning Substation to be rebuilt. The total estimated cost of this alternative is $12.468 million. The 21


(14) Glen Avon 66/12 kV Substation (Project #04445) 23

Glen Avon 66/12 kV Substation is located in city of Jurupa Valley and 24

serves approximately 10,000 metered customers. By the end of 2013, Glen Avon 66/12 kV Substation 25

is projected to exceed its capacity limit due to continuing load growth in the area. The project scope is 26

to add a new 28 MVA transformer bank (thereby increasing total transformer capacity from 50.4 MVA 27

to 78.4 MVA at the station). Without the project, the loading at Glen Avon 66/12 kV Substation is 28

111 Refer to workpaper entitled “Carodean 115/12 kV Substation (Project #06948).”

112 Refer to workpaper entitled “Delano 66/12kV Substation (Project #07160).”

74

projected to reach 102.0 percent of the substation’s capacity limit by the end of 2013 under normal 1

operating conditions. The operating date was June 2013 with a total project cost of $2.603 million.113 2




transformer bank at Bain 66/12 kV Substation and construct two new 12 kV distribution circuits. The 6

total estimated cost of this alternative is $6.344 million. The proposed project was selected as the least 7

cost alternative and due to its proximity to the load center in the Glen Avon area. 8

(15) Lampson 66/12 kV Substation (Project #06292) 9

Lampson 66/12 kV Substation is located in the city of Garden Grove and 10

serves approximately 9,400 metered customers. By 2014, the Pontiac 12 kV distribution circuit out of 11

Vera 66/12 kV Substation and the Bison 12 kV distribution circuit out of Lampson 66/12 kV Substation 12

are projected to exceed their capacity limits due to continuing load growth in the area. The project 13

scope is to construct a new 12 kV distribution circuit and extend the 12 kV switchrack at Lampson 66/12 14

kV Substation. Without the project, the loading on the Pontiac 12 kV and the Bison 12 kV is projected 15

to reach 119.8 percent and 100.5 percent of the circuits’ respective capacity limit by 2014 under normal 16

operating conditions. The operating date is June 2014 with a total project cost of $3.947 million 17

dollars.114 18


transform bank at Vera 66/12 kV Substation and construct one new 12 kV distribution circuit. The total 20

estimated cost for this project is $4.540 million. The proposed project was selected as the least cost 21

alternative. 22

(16) Downs 115/12 kV Substation (Project #06691) 23

Downs 33/12 kV Substation is located in the city of Ridgecrest in Kern 24

County and serves approximately 12,900 metered customers. By 2014, Downs 33/12 kV Substation is 25


to convert the existing 44.8 MVA, 33/12 kV substation to a new 56 MVA, 115/12 kV substation. 27

Without the project, the loading at Downs 33/12 kV Substation is projected to reach 88.6 percent of the 28

113 Refer to workpaper entitled “Glen Avon 66/12 kV Substation (Project #04445).”

114 Refer to workpaper entitled “Lampson 66/12 kV Substation (Project #06292).”

75

substation’s capacity limit by 2014 under normal operating conditions. The operating date is June 2014 1

with a total project cost of $32.256 million.115 2


transformer bank at Inyokern 115/33 kV Substation, construct two new 33 kV circuit from Inyokern 4

Substation to Downs Substation (approximately 17 miles total), and rebuild the 115 kV, 33 kV, and 12 5

kV switchracks at Inyokern Substation. The alternative analysis was included in the PEA (Application 6

A.10-12-016) filed December 29, 2010. The total estimated cost of this alternative is $38.451 million. 7

The proposed project was selected as the least cost alternative. 8

(17) Pebbly Beach 12/2.4 kV Substation (Project #06958) 9

Pebbly Beach 12/2.4 kV Substation is located in the city of Avalon and 10

serves approximately 2,300 metered customers on Santa Catalina Island via six diesel generators. By 11

2014, these existing generators are projected to be insufficient to meet the electrical needs of the island. 12

To supplement the diesel generation, approximately 1.5 MW of micro-turbine generators are currently 13

being installed and will be interconnected in the last available position in the Pebbly Beach 12 kV 14

switchrack. This position currently serves as a spare position to interconnect portable generation on a 15

temporary basis during either forced or planned maintenance outages of the existing diesel generators. 16

To preserve a spare position once the micro-turbine generators are installed, the Pebbly Beach 12 kV 17

switchrack must be expanded. The project scope is to install a new 5 position Metal Clad Switchgear 18

and replace one existing 1200 Amp rated transformer bank circuit breaker with one 2000 Amp rated 19

transformer bank circuit breaker. The operating date is June 2014 with a total project cost of $1.712 20

million.116 21

SCE has identified one alternative to this project–to install distributed 22

wind generators throughout the island in lieu of centralized micro-turbine generators at the Pebbly 23

Beach Generating Station, therefore eliminating the need to expand the existing 12 kV switchrack. 24

However, studies have shown that the wind resource on Santa Catalina Island is insufficient to support 25

the amount of wind generation needed to reliably serve the forecast electrical needs of the island. The 26

proposed project is the only viable technical solution. 27

115 Refer to workpaper entitled “Downs 115/12 kV Substation (Project #06691).”

116 Refer to workpaper entitled “Pebbly Beach 12/2.4 kV Substation (Project #06958).”

76

(18) Del Amo Jr 66/12 kV Substation (Project # 07216) 1

Del Amo Jr 66/12 kV Substation is a new planned substation to be located 2

in the city of Cerritos. The proposed Project will provide needed capacity to serve new load growth 3

around the old Boeing property in Long Beach. By 2014, Lucas 66/12 kV Substation and Sunnyside 4

66/12 kV Substation (serving a combined total of approximately 22,800 metered customers) are 5

projected to exceed and approach their respective capacity limits due to continuing load growth in the 6

Lakewood and Long Beach areas. The project scope is to construct a new substation consisting of two 7

28 MVA transformers and three new distribution circuits. Without the project, the loadings at Lucas 8

66/12 kV Substation and Sunnyside 66/12 kV Substation are projected to reach 102.3 percent and 92.4 9

percent of the substations’ respective capacity limits by the end of 2013 under normal operating 10

conditions. The operating date of the project is June 2014 with a total project cost of $26.778 million.117 11

This project replaces Douglas Park 66/12 kV Substation Project (Project #5034) that was included in 12

SCE’s 2012 GRC filing. The Douglas Park 66/12 Substation project has been cancelled and replaced 13

with the proposed project because the Douglas Park 66/12 kV Substation project’s site was deemed not 14

constructible. 15

SCE has identified one alternative to this project. The alternative consists 16

of three projects at three separate substations. (1) Replace the existing transformer bank circuit breakers 17

with 2000 Amp rated transformer bank circuit breakers to gain full capacity of the existing transformer 18

banks at Cornuta 66/12 kV Substation. The estimated cost for this project is $0.337 million. (2) Install 19

one new 28 MVA 66/12 kV transformer bank at Cypress 66/12 kV Substation and construct four new, 20

lengthy 12 kV distribution circuits. The estimated cost for this project is $22.998 million. (3) Construct 21

one new 12 kV distribution circuit out of Hathaway 66/12 kV Substation. The total estimated cost for 22

this project is $3.585 million. The total estimated cost for this alternative is $26.921 million. Although 23

the alternatives are comparable in cost, the proposed project was selected because it offers greater 24

operational flexibility. 25

(19) La Palma 66/16 kV Substation (Project #07263) 26

La Palma 66/12 kV Substation is located in the city of Buena Park in north 27

Orange County and serves approximately 10,300 customers. By 2014, the nearby Gilbert 66/12 kV, 28

Barre 66/12 kV, and Fullerton 66/12 kV Substations are projected to approach their capacity limits due 29

117 Refer to workpaper entitled “Del Amo Jr 66/12 kV Substation (Project #07216).”

77

to continuing load growth in the north Orange County region. The project scope is to replace the 1

existing 15 MVA transformer bank with two 28 MVA transformers (increasing the transformer capacity 2

to 78.4 MVA) and construct one new 12 kV distribution circuit. Without the project, the loading at 3

Gilbert 66/12 kV Substation and Fullerton 66/12 kV Substation is projected to reach 96.7 percent and 4

96.9 percent of the substations' respective capacity limit by 2014 under normal operating conditions. 5

The operating date is June 2014 with a total project cost of $13.812 million.118 6


transformer bank at Fullerton 66/12 kV Substation and construct one new 12 kV distribution circuits. 8

The total estimated cost of this alternative is $12.767 million. This alternative does not eliminate the 9

need for La Palma 66/16 capacity increase, but instead only defers the need by four years (from 2014 to 10

2018). This alternative does not adequately meet long-term projected electrical load requirements in the 11

north Orange County region. For this reason, the proposed project was selected as the preferred 12

alternative. 13

(20) Lark Ellen 66/12 kV Substation (Project #07391) 14

Lark Ellen 66/12 kV Substation is located in the city of Covina and serves 15

approximately 7,800 metered customers in communities in the Covina, West Covina, and Irwindale 16

area. By 2014, Merced 66/12 kV Substation and Lark Ellen 66/12 kV Substation are projected to 17

approach and exceed their respective capacity limits due to continuing load growth in the Covina area. 18

The project scope is to add a new 28 MVA transformer bank (increasing the capacity from 56 to 84 19

MVA). Without the project, the loading at Merced 66/12 kV Substation and Lark Ellen 66/12 kV 20

Substation are projected to reach 99.8 percent and 101.5 percent of the respective substation's capacity 21

limit by 2014 under normal operating conditions. The operating date of the project is June 2014 with a 22

total project cost of $4.385 million.119 23


transformer bank at Merced 66/12 kV Substation and construct two new 12 kV distribution circuits. The 25



118 Refer to workpaper entitled “La Palma 66/16 kV Substation (Project #07263).”

119 Refer to workpaper entitled “Lark Ellen 66/12 kV Substation (Project #07391).”

78

(21) Colonia 66/16 kV Substation (Project #05403) 1

Colonia 66/16 kV Substation is located in the city of Oxnard and serves 2

approximately 9,100 metered customers. By 2015, Colonia 66/16 kV Substation is projected to exceed 3

its capacity limit due to continuing load growth in the area. The project scope is to add a new 28 MVA 4

transformer bank (thereby increasing total transformer capacity from 56 MVA to 84 MVA at the station) 5

and construct one new 16 kV distribution circuit. Without the project, the loading at Colonia 66/16 kV 6

Substation is projected to reach 106.9 percent of the substation’s capacity limit by 2015 under normal 7

operating conditions. The operating date is June 2015 with a total project cost of $7.014 million.120 8




transformer bank at Camarillo 66/16 kV Substation and construct one new 16 kV distribution circuit. 12

The total estimated cost of this alternative is $6.089 million. Although the alternatives are comparable 13

in cost, the proposed project was selected due to increased operational flexibility and due to its 14

proximity to the load center in the Oxnard area. 15

(22) Canyon 66/12 kV Substation (Project #06301) 16

Canyon 66/12 kV Substation is located in the City of Yorba Linda in 17

Orange County and serves approximately 7,700 metered customers. Canyon Substation has no available 18

ties to the North, East, or South and would be unable to serve load in the event of a transformer outage 19

(N-1). The project scope is to add a new 28 MVA transformer bank, increasing the transformer capacity 20

from 44.8 to 72.8 MVA. The operating date is June 2015 with a total project cost of $4.637 million.121 21

SCE has identified one alternative to this project–to construct one new 12 22

kV distribution circuit out of Yorba Linda 66/12 kV Substation which crosses the 91 Freeway and the 23

Santa Ana River. The total estimated cost of this alternative is $7.569 million. The proposed project 24

was selected as the least cost alternative. 25

(23) San Dimas 66/12 kV Substation (Project #07307) 26

San Dimas 66/12 kV Substation is located in the city of San Dimas and 27

serves approximately 11,600 metered customers. By 2015, San Dimas 66/12 kV Substation is projected 28

120 Refer to workpaper entitled “Colonia 66/16 kV Substation (Project #05403).”

121 Refer to workpaper entitled “Canyon 66/12 kV Substation (Project #06301).”

79

to exceed its capacity limit due to continuing load growth in the area. The project scope is to add one 28 1

MVA transformer, increasing the transformer capacity from 67.2 to 95.2 MVA. Without the project, the 2

loading at San Dimas 66/12 kV Substation is projected to reach 111.4 percent of the substation's 3

capacity limit by 2015 under normal operating conditions. The operating date is June 2015 with a total 4



transformer bank at Layfair 66/12 kV Substation and construct two new 12 kV distribution circuits. The 7


cost alternative. 9

(24) Orange 66/12 kV Substation (Project #07480) 10

Orange 66/12 kV Substation is located in the city of Orange and serves 11

approximately 11,300 metered customers. By 2015, Orange 66/12 kV Substation is projected to exceed 12

its capacity limit due to continuing load growth in the area. The project scope is to construct a new 13

switchrack and upgrade the existing 12 kV Bus to 3.5 inch IPS. Without the project, the loading at 14

Orange 66/12 kV Substation is projected to reach 100.4 of the substation's capacity limit by 2015 under 15


million.123 17


lengthy 12 kV distribution circuit out of La Veta Substation. The total cost of this alternative is $5.696 19

million. This alternative does not eliminate the need for the Orange 66/12 kV Substation Project, but 20

instead only defers the need by four years (from 2015 to 2019). This alternative does not adequately 21

meet long-term projected electrical load requirements in the Orange area, and for this reason the 22

proposed project was selected as the preferred alternative. 23

(25) Lakeview 115/12 kV Substation (Project #05411) 24

Lakeview 115/12 kV Substation is a new planned substation to be located 25

in the developing areas of Nuevo and Lakeview in the city of San Jacinto. By 2016, Nuevo 33/12 kV 26

Substation is projected to exceed its capacity limit due to continuing load growth in the Nuevo and 27

122 Refer to workpaper entitled “San Dimas 66/12 kV Substation (Project #07307)."

123 Refer to workpaper entitled “Orange 66/12 kV Substation (Project #07480).”

80

Lakeview areas. The temporary Model Pole-Top 33/12 kV Substation124 is projected to provide 1

capacity to serve the load which is in excess of the capacity of Nuevo substation until Lakeview 2

Substation is complete. Upon completion of the Lakeview Substation project, both Nuevo and Model 3

P.T. Substations would be decommissioned. Lakeview Substation will provide capacity to serve the 4

existing demand, as well as capacity to serve future developments, and provide enhanced reliability and 5

operational flexibility to the Electrical Needs Area. The project scope is to construct a new substation 6

consisting of two 28 MVA, 115/12 kV transformer banks and four new 12 kV distribution circuits. 7

Without the project, the loadings at Nuevo 33/12 kV Substation is projected to reach 101.2 percent of 8

the substation’s capacity limit by 2016 under normal operating conditions. The operating date is June 9

2016 with a total project cost of $65.011 million.125 This project was included in SCE’s 2012 GRC 10

filing with a June 2013 operating date but was subsequently moved to June 2016 due to licensing delays. 11

SCE has identified one alternative to this project– to construct a new 56 12

MVA, 33/12 kV substation in the Nuevo and Lakeview areas with four new 12 kV distribution circuits 13

and three new 33 kV distribution lines to feed the new substation. The alternative analysis was included 14

in the PEA (Application A. 10-09-016) filed September 17, 2010. The proposed project was selected 15

because it satisfies all of the project objectives. The total estimated cost of this alternative is $52.961 16

million. This alternative does not eliminate the need for Lakeview 115/12 kV Substation, but instead 17

only defers the need by 17 years (from 2016 to 2033). This alternative does not adequately meet long-18

term projected electrical load requirements in the Nuevo and Lakeview areas. In addition, this 19

alternative would result in reduced operating flexibility and reliability for the area as compared to the 20

proposed project due to the considerably longer source lines needed to serve the substation 21

(approximately twenty-five miles of 33 kV lines to feed the 33/12 kV substation versus approximately 22

three miles of 115 kV lines to feed Lakeview 115/12 kV Substation). For these reasons, the proposed 23

project was selected as the preferred alternative. 24

(26) Yokohl 66/12 kV Substation (Project #06067) 25

Yokohl 66/12 kV Substation is a new planned substation to be located in 26

the Yokohl Ranch area of the San Jacinto Valley. Yokohl Substation is planned to meet future load of 27

124 Model Pole-Top 33/12 kV Substation is a temporary facility constructed as an interim measure to meet the immediate

capacity needs in the Nuevo and Lakeview areas.

125 Refer to workpaper entitled “Lakeview 115/12 kV Substation (Project #05411).”

81

approximately 10,000 homes in a Master Planned community. The scope of the project is to construct a 1

new 56 MVA substation and construct four new 12 kV distribution circuits. The operating date is June 2

2016 with a total project cost of $88.034 million.126 3

There are no alternatives to this project. The proposed project is the only 4

viable technical solution due to the remote location. 5

(27) Banducci 66/12 kV Substation (Project #06619) 6

Banducci 66/12 kV Substation is a new planned substation to be located in 7

Cummings Valley, Kern County. This planned substation upgrade project will serve the Cummings 8

Valley area of Kern County and adjacent areas. The proposed project will improve system reliability 9

and enhance operational flexibility. By 2016, Cummings 66/12 kV Substation (serving approximately 10

7,300 metered customers) is projected to exceed its capacity limit due to continuing load growth in the 11

Cummings Valley area. The project scope is to construct a new substation consisting of two 28 MVA, 12

66/12 kV transformer banks, 4.8 MVAR of capacitors, and three new 12 kV distribution circuits. 13

Without the project, the loading at Cummings 66/12 kV Substation is projected to reach 105.2 percent of 14

the substation’s capacity limit by 2016 under normal operating conditions. The operating date is June 15

2016 with a total project cost of $42.105 million.127 This project was included in SCE’s 2012 GRC 16

filing with a June 2013 operating date but was subsequently moved to June 2016 due to a revised load 17

forecast. 18

SCE has identified one alternative to this project–to expand the existing 19

Cummings 66/12 kV Substation property and rebuild the station to a new 56 MVA, 66/12 kV substation 20

with three new, lengthy 12 kV distribution circuits. The alternative analysis is included in the PEA 21

(Application A.12-11-011, filed November 19, 2012). The total estimated cost of this alternative is 22

$60.405 million. The proposed project was selected as the least costs alternative. 23

(28) Greenhorn 66/2.4 kV Substation (Project #06836) 24

The Greenhorn Substation is located in Wofford Heights and serves 25

approximately 400 metered customers. By 2016, Greenhorn 66/2.4 kV Substation is projected to exceed 26

its capacity limit. The project scope is to replace three existing .3 MVA transformer banks with three 27

0.5 MVA transformer banks increasing the substation capacity from 0.9 to 1.5 MVA. Without the 28

126 Refer to workpaper entitled “Yokohl 66/12 kV Substation (Project #06067).”

127 Refer to workpaper entitled “Banducci 66/12 kV Substation (Project #06619).”

82

project, Greenhorn 66/2.4 kV Substation is projected to reach 100.3 percent of its capacity limit by 2016 1

under normal operating conditions. The operating date is June 2016 with a total project cost of $4.108 2

million.128 3

SCE has identified one alternative to this project—to extend an existing 12 4

kV distribution circuit from Isabella 66/12 kV Substation. The cost for this alternative is estimated to be 5


(29) Mainframe 66/4.16 kV Substation (Project #07293) 7

Mainframe 66/4.16 kV Substation is a new planned substation to be 8

located in the city of Alhambra. Mainframe 66/4.16 kV Substation will serve a SCE owned and 9

operated data center that holds vital customer and internal information necessary to providing reliable 10

service. An unplanned outage would adversely impact the computer equipment. The proposed project 11

will allow SCE to provide reliable service to the datacenter. The scope of the project is to construct a 12

new substation consisting of two 14 MVA 66/4.16 kV transformers and 2 dedicated circuits. The 13

operating date is June 2016 with a total project cost of $24.696 million.129 14

SCE has identified one alternative to this project. The alternative includes 15

work at Rosemead substation to replace the No. 3 transformer bank with 28 MVA transformers (remove 16

two 22.4 MVA transformers and replace with two 28 MVA.) The alternative also includes upgrading 17

the existing No. 2 bank by removing one 22.4 MVA transformer and replacing it with a 28 MVA 18

transformer. SCE would also have to reconductor 12 positions on the 16 kV switch rack, upgrade 16 kV 19

circuit breakers, extend the 16 kV switch rack by three positions, equip two new positions with circuit 20

breakers, and install one new 16 kV capacitor. The alternative also includes a new 4.0 mile circuit from 21

Rosemead substation. In addition, the alternative requires work at Newmark substation. SCE would 22

have to replace two existing 14 MVA transformers with two 28 MVA transformers, equip one 16 kV 23

position with a circuit breaker, add a new 4.4 mile circuit (including extensive civil construction). SCE 24

would also need to install four 5 MVA transformers a the data center site. The total estimated cost for 25

this alternative is $19.922 million. The proposed project was selected as the most feasible alternative 26

that meets all of the project objectives. 27

128 Refer to workpaper entitled “Greenhorn 66/2.4 kV Substation (Project #06836).”

129 Refer to workpaper entitled “Mainframe 66/4.16 kV Substation (Project #07293).”

83

(30) Safari 33/12 kV Substation (Project #07516) 1

Safari 33/12 kV Substation is a new planned substation to be located in the 2

city of Irvine. By 2016, circuits out of Santiago 66/12 kV substation are projected to exceed capacity. 3

In addition, by 2019 Santiago 66/12 kV substation approaches its capacity limit and is unable to be 4

expanded. The scope of the project is to construct a new substation consisting of two 28 MVA 33/12 kV 5

transformers and three 12 kV distributions circuits. The project scope includes adding two 28 MVA 6

66/33 kV transformers at Santiago Substation and construct two 33 kV circuits from Santiago 66/33 kV 7

to Safari 33/12 kV. Without the project, the loading at Santiago is projected to reach 91.8 percent of the 8

substation’s capacity limit by 2016 and 103.7 percent of the substations capacity limit by 2019 under 9


million.130 11

SCE has identified one alternative to this project–to construct a new 12 kV 12

distribution circuit out of Santiago Substation in 2016, and then to construct a new 66/12 kV substation 13

and three new 12 kV distribution circuits in 2019. The total estimated cost of this alternative is $49.735 14


(31) Circle City 66/12 kV Substation - Phase 1 (Project #06575) 16

Circle City 220/66 kV Substation is a new planned substation to be located 17

in the city of Corona. By 2019, the nearby Chase 66/12 KV Substation, Corona 66/12 kV Substation, 18

and Jefferson 66/12 kV Substation are expected to exceed their capacity limit due to continuing load 19

growth in the area. By 2016, the Mira Loma-Corona-Jefferson 66 kV subtransmission line is projected 20

to exceed its capacity limit due to continuing load growth in the area. This project is separated into two 21

phases. The scope of Phase 1 is to construct a new approximately 10 mile 66 kV subtransmission line 22

from Mira Loma Substation to Jefferson Substation. Without Phase 1, the loading on the Mira Loma-23

Corona-Jefferson 66 kV subtransmission line is projected to reach 104 percent of its capacity by 2016 24

under N-1 line outage conditions. The scope of Phase 2 is to construct a new 66/12 kV substation 25

consisting of two 28 MVA, 66/12 kV transformer banks and four new 12 kV distribution circuits. The 26

operating date of Phase 1 is June 2016 with a cost of $25.198 million.131 The operating date of Phase 2 27

is June 2019. Because the operating date of Phase 2 is outside of the 2015 rate case window, the cost of 28

130 Refer to workpaper entitled “Safari 33/12 kV Substation (Project #07516).”

131 Refer to workpaper entitled “Circle City 66/12 kV Substation - Phase 1 (Project #06575).”

84

Phase 2 will not be included in this General Rate Case. SCE also needs to purchase property for the new 1

66/12 kV substation, which is discussed later in this testimony in Section I.F.5. This project was 2

included in SCE’s 2012 GRC filing with a June 2014 operating date but was subsequently moved to 3

June 2016 (Phase 1) and June 2019 (Phase 2) due to lower than anticipated load growth in the area. 4

There are no alternatives to this project. The proposed project is the only 5

viable technical solution. 6

(32) Falcon Ridge 66/12 kV Substation (Project #05397) 7

Falcon Ridge 66/12 kV Substation is a new planned substation to be 8

located in the city of Devore. By 2014, Alder 66/12 kV Substation and Randall 66/12 kV Substation 9

(serving a combined total of approximately 46,000 metered customers) are projected to exceed their 10

respective capacity limits due to continuing load growth in the Fontana and Rialto areas. The project 11

scope is to construct a new substation consisting of two 28 MVA, 66/12 kV transformer banks and four 12

new 12 kV distribution circuits. Without the project, the loadings at Alder 66/12 kV Substation and 13

Randall 66/12 kV Substation are projected to reach 105.2 percent and 101.7 percent of the substations’ 14

respective capacity limits by 2014 under “high case” load forecast conditions. The operating date is 15

December 2016 with a total project cost of $83.554 million.132 16


MVA, 115/12 kV substation with four new 12 kV distribution circuits in the Devore area. The 18

alternative analysis was included in the PEA (Application A.10-12-017) filed December 29, 2010. The 19

total estimated cost for this project is $96.592 million. The proposed project was selected as the least 20


5. Land Held for Future Use 22

There are two projects with operating dates beyond 2017 that require land to be 23

purchased prior to 2017. Since this land will be purchased for future use during this rate case cycle, we 24

have included these forecasts herein. The total cost of land is $17.3 million as shown in Table I-15 25

below.133 26

132 Refer to workpaper entitled “Falcon Ridge 66/12 kV Substation (Project #05397).”

133 Refer to workpaper entitled “Land Held for Future Use Forecast.”

85

Table I-15 Land Held for Future Use Capital Expenditure Summary

(100% CPUC-Jurisdictional Nominal $000)

Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 05346 Valley South Jun 2016 - - - 4,835 3,296 - 8,131 2 06575 Circle City Substation Jun 2016 - - - 8,416 748 - 9,164 3 Total Other Transmission Planning Projects - - - 13,251 4,044 - 17,295

G. System Improvement/Reinforcement Programs 1

The System Improvement/Reinforcement Programs include six categories in which projects are 2

identified and cost forecasts are developed. Descriptions of these categories and forecasts are included 3

below. 4

1. Substation Equipment Replacement Program (SERP)–Blanket Budget Item, WBS 5

Element CET-ET-LG-SU 6

The Substation Equipment Replacement Program (SERP) evaluates the adequacy of 7

substation terminal equipment and system protection equipment. Specifically, the SERP identifies 8

substations where short-circuit duty levels exceed equipment ratings as well as system ground source 9

requirements essential to the provision of safe, reliable service. Typical SERP projects include the 10

replacement of circuit breakers with higher short-circuit duty rated units,134 projects to reduce short 11

circuit duty levels at substations, or the addition of ground banks for proper grounding under normal and 12

contingency conditions. SERP projects are necessary for safe operation and to avoid equipment damage 13

during normal, contingency, or faulted conditions. Figure I-9 below, shows 2008–2012 recorded and 14

2013-2017 forecast expenditures for SERP. 15

134 Short-Circuit Duty–Abnormal current levels an electrical system will experience during faulted conditions, producing

considerable thermal and mechanical stresses in electrical equipment.

86

Figure I-9 Substation Equipment Replacement Program (SERP) Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-ET-LG-SU

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

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 1,441 4,775 7,024 5,990 8,992 6,416 12,458 12,653 13,897 15,381

Constant 2012 $ 1,651 5,351 7,552 6,184 8,992 6,279 11,897 11,831 12,710 13,697

$-

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

$16,000

$18,000

Nominal $ Constant 2012 $

Forecast

From 2008–2012, our SERP expenditures averaged $5.9 million per year (in constant 1

2012 dollars). In 2011 and 2012, we performed analysis of short circuit duties at existing substations 2

that expanded on analysis performed in previous years. This recent analysis emphasized identification 3

and prioritization of circuit breaker replacements for safety considerations. The result of this analysis 4

was the development of a plan to address 399 overstressed breakers in years 2013–2017 as shown in 5

Table I-16. The forecast expenditures reflect SCE’s plan to replace 369 circuit breakers from 2013–6

2017 and reduce the short circuit duty at 30 breakers, as shown below in Table I-16. The total cost for 7

the SERP over the forecast period is $60.8 million (in nominal dollars), or an average of $11.3 million 8

per year (in constant 2012 dollars) in the 2013–2017 period.135 9

135 Refer to workpaper entitled “SERP Quantity and Cost Estimate.”

87

Table I-16 Substation Equipment Replacement Program Capital Expenditure Forecast

WBS Element CET-ET-LG-SU (100% CPUC-Jurisdictional Nominal $000)

2013 2014 2015 2016 201766 kV Circuit Breakers to Replace 32 34 32 32 36Unit Cost $200 $207 $212 $216 $222Subtotal $6,416 $7,043 $6,770 $6,921 $7,996

4 kV, 12 kV, 16 kV CBs to Replace 0 47 50 54 52Unit Cost $112 $115 $118 $120 $124Subtotal $0 $5,415 $5,883 $6,496 $6,424

Overduty Mitigation $0 $0 $0 $480 $960

Total $6,416 $12,458 $12,653 $13,897 $15,381

2. DSP Circuit Work–Blanket Budget Item, WBS Elements CET-ET-LG-PF and 1

CET-ET-LG-CI 2

This category includes three sub-categories: (1) New DSP circuits, (2) Miscellaneous 3

Non-Circuit Projects, and (3) the Circuit Load Reduction Program (CLRP.) A description of each 4

category is included below. Table I-17 below shows the total forecast for DSP Circuits Work and is the 5

sum of the three sub-categories.136 As discussed previously, two Operational Excellence initiatives have 6

resulted in fewer circuit additions and more miscellaneous work on distribution circuits. As shown 7

below in Table I-17, new circuit work is decreasing significantly, while non-circuit and CLRP work is 8

increasing modestly. In total, we forecast this work to decrease from 2013 to 2017. 9

136 In order to make the forecast years comparable to the historical years, we have included our capital forecasts for circuits

build with new substations and capacity increases in this graph. Our capital request for those new circuits, however, is included with each related project.

88

Table I-17 DSP Circuit Work Capital Expenditures

WBS Elements CET-ET-LG-PF and CET-ET-LG-CI (100% CPUC-Jurisdictional Nominal $000)

2 0 0 8 2 0 0 9 2 0 1 0 2 0 1 1 2 0 1 2 2 0 1 3 2 0 1 4 2 0 1 5 2 0 1 6 2 0 1 7D SP C ircu it s $ 9 3 ,7 3 2 $ 1 1 3 ,1 4 8 $ 1 0 6 ,2 4 5 $ 9 6 ,8 4 0 $ 8 6 ,4 6 4 $ 7 0 ,5 8 1 $ 5 8 ,5 1 6 $ 5 6 ,6 2 7 $ 4 9 ,0 7 4 $ 2 2 ,1 1 4M is c . N o n -C ircu it 8 ,9 3 9 1 3 ,0 1 0 8 ,2 4 7 2 1 ,2 1 7 1 8 ,9 7 1 2 9 ,2 3 4 2 9 ,4 9 4 3 1 ,2 1 3 2 8 ,3 5 3 3 0 ,4 2 0C irc . L o ad R ed u c t io n 4 ,5 1 5 8 ,0 2 7 8 ,7 1 4 1 2 ,2 7 5 1 7 ,3 3 6 1 9 ,4 3 7 1 9 ,7 8 2 2 1 ,7 8 5 1 8 ,6 7 9 2 1 ,0 3 1T o t al $ 1 0 7 ,1 8 6 $ 1 3 4 ,1 8 5 $ 1 2 3 ,2 0 6 $ 1 3 0 ,3 3 1 $ 1 2 2 ,7 7 0 $ 1 1 9 ,2 5 2 $ 1 0 7 ,7 9 2 $ 1 0 9 ,6 2 6 $ 9 6 ,1 0 6 $ 7 3 ,5 6 6

R eco rd ed F o recas t

a) New DSP Circuits 1

SCE builds new distribution circuits as part of three types of projects: (1) new 2

substation projects, (2) substation capacity increase projects, and (3) as standalone projects. New 3

circuits are planned based on our load growth forecast and are necessary to serve growing load. Figure 4

I-10 shows this historical and forecasts costs for all three categories of new distribution circuit. 5

89

Figure I-10 New DSP Circuit Capital Expenditure

Recorded 2008-2012/Forecast 2013-2017 WBS Elements CET-ET-LG-PF and CET-ET-LG-CI


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 93,732 113,148 106,245 96,840 86,464 70,581 58,516 56,627 49,074 22,114

Constant 2012 $ 107,417 126,788 114,225 99,977 86,464 69,077 55,877 52,952 44,884 19,694

$-

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000


Forecast

In past rate cases, we have presented the costs for all new distribution circuits as 1

one forecast. However, in this filing, we are including circuits built with new substations and substation 2

capacity upgrades with the cost forecasts for those projects.137 Therefore, our capital request in this sub-3

category includes only those circuits we plan to build on a standalone basis.138 The breakdown of these 4

costs is shown below in Table I-18. Our forecast for circuits from 2013–2017 totals $256.9 million. 5

137 These projects are discussed in the Load Growth section of this chapter. For a summary of all distribution circuits, see

workpaper entitled "DSP Circuit Work."

138 The distribution work associated with substation work is included in the cost forecast of the substation project as a whole. Organizing our capital expenditures this way more closely links costs forecasts with drivers of work.

90

Table I-18 New Distribution Circuit Capital Expenditures

WBS Elements CET-ET-LG-PF and CET-ET-LG-CI (100% CPUC-Jurisdictional Nominal $000)

2013 2014 2015 2016 2017

Standalone Circuit Projects 23 11 10 2 14

Circuits Installed with Substation Capacity Increases 19 9 1 16 0

Total Distribution Circuits 42 20 11 18 14

Costs for Standalone Circuits $41,690 $26,556 $18,071 $15,544 $20,472

Costs for Circuits with Substation Projects 28,891 31,960 38,557 33,531 1,643

Total Circuit Cost Forecast $70,581 $58,516 $56,627 $49,074 $22,114

Two factors contribute to lower capital expenditure in the forecast period 1

compared to prior years. First, the forecast period only includes circuits we expect to put in service by 2

2017. Because we begin work on circuits two years in advance of the need, we expect to incur capital 3

expenditures in 2016 and 2017 for circuits that will not be ready for service until 2018 or later. The 4

forecast in Table I-18 above does not include this capital expenditure since we are not requesting it as 5

part of this rate case cycle. Second, the operational changes to our planning process discussed in 6

Section I.C have reduced the amount of capital expenditure we forecast for 2013–2017 for new circuits. 7

This is partially offset by a need to perform more miscellaneous non-circuit work and circuit load 8

reduction program work. 9

For new circuits, our forecast reflects the timing of designing and constructing 10

new distribution circuits. This is becoming increasingly complex due to environmental concerns and 11

permitting requirements of local jurisdictional agencies. To allow sufficient lead time to complete a new 12

circuit, we begin this process two years in advance of the need date for the circuit. On average, we plan 13

to spend 7 percent of the cost of a new circuit on early planning work two years prior to the operating 14

date of the circuit, another 34 percent on early construction activities the year prior to the operating date, 15

and the remaining 59 percent to complete construction in the year that the circuit becomes operational. 16

The forecast in Table I-18 above reflects this timing. 17

Costs to build a new circuit vary depending on several factors such as whether it's 18

an overhead or underground circuit, the length of circuit, and geographic location. To forecast the costs 19

in this work category, we utilized historical circuit costs. 20

91

b) Miscellaneous Non-Circuit 1

The Miscellaneous Non-Circuit sub-category covers forecast expenditures for 2

work required to facilitate the load transfers identified in the DSP and is performed to reduce load on 3

substations that are forecast to exceed loading criteria. When substations are forecast to exceed 4

established loading criteria, SCE installs the necessary facilities to transfer load to less loaded 5

substations in the same geographic region. Year-by-year expenditures in this sub-category are driven by 6

DSP load growth as well as planned DSP circuit additions, both of which are indicators of the need to 7

construct miscellaneous projects to upgrade our distribution system. Typical work in this category 8

includes installing new switches, upgrading cable, upgrading conductor, or installing new conductor to 9

create circuit ties to facilitate load transfers between substations. 10

Figure I-11 below, summarizes recorded costs for the 2008–2012 period for the 11

Miscellaneous Non-Circuit sub-category, as well as forecast expenditures for the 2013–2017 period. 12

From 2008–2012, our expenditures averaged approximately $14.1 million per year with recorded costs 13

of $18.971 million in 2012. We forecast capital expenditures to increase by approximately $10.0 14

million per year (in constant 2012 dollars) in order to better utilize existing distribution assets as 15

discussed in Section I.C and to address existing 4 kV criteria violations. The additional work in this 16

subcategory allows us to build fewer new circuits and contributes to the overall forecast cost decrease 17

for DSP circuit work. The total forecast cost for the 2013–2017 period is $148.7 million (in nominal 18

dollars), or an average of $27.8 million per year (in constant 2012 dollars.) 19

92

Figure I-11 Miscellaneous Non-Circuit Capital Expenditures



2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 8,939 13,010 8,247 21,217 18,971 29,234 29,494 31,213 28,353 30,420

Constant 2012 $ 10,244 14,578 8,866 21,904 18,971 28,611 28,164 29,187 25,932 27,090

$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000


c) Circuit Load Reduction Program (CLRP) 1

The Circuit Load Reduction Program (CLRP) sub-category covers forecast 2

expenditures for work (other than new distribution circuits) required to relieve loading on heavily loaded 3

distribution circuits. When circuits are forecast to exceed established loading criteria, SCE installs the 4

necessary facilities to transfer load to less loaded circuits in the same geographic region. Similar to 5

miscellaneous non-circuit work, CLRP work includes installing new switches, upgrading cable, 6

upgrading conductor, or installing new conductor to create circuit ties to facilitate load transfers between 7

circuits. This also includes rearranging duct bank getaways139 at substations to reduce underground 8

cable temperatures or installing automatic reclosers to increase the loading capability of distribution 9

circuits. Year-by-year expenditures in this sub-category are driven by DSP load growth and planned 10

139 Duct bank getaways are underground conduit systems used to route multiple distribution circuits from the low voltage

switchrack inside the substation to underground vaults outside of the substation.

93

DSP circuit additions, both of which are indicators of the need to construct projects to reduce loading on 1

our distribution circuits. 2

Figure I-12 below, summarizes recorded costs for the 2008–2012 period for the 3

CLRP sub-category, as well as forecast expenditures for the 2013–2017 period. As new distribution 4

circuits have become increasingly complex and costly to design and construct, we have focused more 5

and more on CLRP projects in recent years to relieve heavily loaded circuits on our system. The 6

forecast for 2013 is $19.4 million (in nominal dollars) and the 2014–2017 forecast is adjusted based on 7

(1) forecast DSP load growth and (2) planned DSP circuit additions. The total forecast cost for the 8

2013–2017 period is $100.7 million (in nominal dollars), or an average of $18.8 million per year (in 9

constant 2012 dollars). 10

94

Figure I-12 Circuit Load Reduction Program Capital Expenditures



2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 4,515 8,027 8,714 12,275 17,336 19,437 19,782 21,785 18,679 21,031

Constant 2012 $ 5,174 8,995 9,368 12,672 17,336 19,023 18,890 20,371 17,084 18,729

$-

$5,000

$10,000

$15,000

$20,000

$25,000


Forecast

3. Distribution Plant Betterment–Blanket Budget Item, WBS Element CET-PD-LG-1

PB 2

The Distribution Plant Betterment forecast includes work associated with upgrading and 3

reinforcing the distribution system to accommodate anticipated load growth. Specifically, this category 4

includes increasing the size of existing overhead conductors or underground cables to increase 5

distribution circuit capacity or improve distribution circuit voltage profiles. It also includes installing 6

neutral conductors, or “fourth wires,” on existing three-wire distribution circuits to serve new residential 7

loads. These distribution system upgrade and reinforcement projects are required to efficiently 8

distribute power to customers while maintaining reliable service and preventing failures due to 9

overloads of existing overhead or underground equipment. 10

Figure I-13 below, shows 2008–2012 recorded and 2013–2017 forecast expenditures for 11

the Distribution Plant Betterment. In 2012 constant dollars, average expenditures over the historical 12

period were $10.7 million. However, in 2010 SCE recorded expenditures higher than typical years. 13

95

Therefore, we have excluded those years from our historical average for the purposes for forecasting. 1

This results in a historical average of $7.8 million. Since we expect slightly less work in this category 2

during the forecast period, we have adjusted this down to $7.4 million and use that as our forecast. 3

Figure I-13 Distribution Plant Betterment Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-PD-LG-PB


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 5,421 9,181 18,304 9,046 7,939 7,600 7,789 7,955 8,132 8,352

Constant 2012 $ 6,212 10,288 19,679 9,339 7,939 7,438 7,438 7,438 7,438 7,438

$-

$5,000

$10,000

$15,000

$20,000

$25,000


Forecast

4. Distribution VAR Plan, WBS Element CET-PD-LG-NC 4

As discussed earlier, capacitor banks are installed throughout our system to supply 5

needed reactive power and help maintain adequate voltage. In the Distribution VAR Plan, we review 6

requirements for capacitor banks on our distribution circuits for the upcoming year. Without a 7

comprehensive Distribution VAR Plan, we would run the risk of undersupplying the reactive power 8

needs of our distribution system as the demand for electricity continues to increase in our service 9

territory. With inadequate distribution VAR supplies, the reactive power needed for our distribution 10

system would need to come from either our subtransmission system or our transmission system. This 11

could compromise our ability to provide adequate voltage to our end-use customers and, in a worst-case 12

96

scenario, result in cascading outages and widespread blackouts after disturbances on our high voltage 1

transmission grid. 2

The objective of the Distribution VAR Plan is to fully supply the peak reactive power 3

needs of each of our distribution circuits under normal weather conditions. In practical terms, this 4

means maintaining zero VAR flow at the point where our distribution circuits exit our B-substations. 5

We compare the reactive power supplied by existing capacitor banks on each of our distribution circuits 6

versus the projected reactive power needs of these circuits. These reactive power needs increase as load 7

is added to our distribution circuits. When we forecast that a distribution circuit will have a VAR 8

deficiency, we sponsor a capital project to install either an overhead or pad mounted capacitor bank on 9

the circuit, depending on the circuit configuration. Generally, we add 550 kVAR worth of capacitor 10

banks for every 1,000 kW of increased load on our circuits in order to maintain unity power factor140 in 11

accordance with SCE’s Distribution Design Standards. In addition to supplying the reactive power 12

needs of our distribution system, we also install capacitor banks to correct identified low voltage 13

problems on our distribution circuits. 14

Our forecast expenditures for 2013–2017 , as shown in Figure I-14 below, are based on 15

estimated growth in kVAR demand on our distribution system (as a function of our load growth forecast 16

in our DSP) and our unit cost per kVAR for distribution circuit capacitor bank installations. In addition 17

to capacitor bank additions required to serve new load growth, we also plan to add incremental capacitor 18

banks starting in 2013 to begin reducing an existing VAR deficit of approximately 700 MVAR on our 19

distribution system.141 These incremental capacitor bank additions will be completed by 2016 such that 20

the entire 700 MVAR deficit will be corrected and our distribution system as a whole will be operating 21

at unity power factor.142 22

140 Power factor (pf) is defined as the real power (P) over the apparent power (VI) or pf = P/VI.

141 The recorded VAR deficit on SCE’s distribution system was actually 694 MVAR at the time of SCE’s system peak demand on August 13, 2012. See workpaper entitled “MVAR Flow Data for August 13, 2012 at 1500 Hrs.”

142 Refer to workpaper entitled “Distribution VAR Plan Estimate.”

97

Figure I-14 Distribution VAR Plan Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-PD-LG-NC


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 1,990 2,606 5,550 6,378 6,620 4,724 8,414 7,071 6,569 6,854

Constant 2012 $ 2,281 2,920 5,967 6,584 6,620 4,623 8,035 6,612 6,008 6,104

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000


Forecast

5. Capacitor Automation Program, WBS Element CET-PD-LG-CV 1

SCE’s Capacitor Automation program automates existing manual capacitor controls and 2

upgrades obsolete, first-generation automation equipment.143 Capacitor controls are used to remotely 3

operate switched capacitor banks installed on the distribution system to provide voltage and VAR 4

support.144 Without capacitor banks, the voltage supplied to SCE customers would drop to levels that 5

can damage the customers’ equipment or appliances, and present safety hazards. Automating the control 6

of these capacitor banks allows SCE to remotely monitor and control the operation of these devices, 7

rather than sending a person to operate the device manually in the field. 8

143 Capacitors are devices used to maintain proper system voltages.

144 Volt-ampere reactive power (VAR) is the unit used to measure reactive power in alternating current electric systems. Because alternating current systems have varying voltage, these systems must vary the current with the voltage to maintain stability. VARs measure the lead or lag between synchronization of voltage and current.

98

There are approximately 13,300 capacitor banks in SCE’s distribution system. Of these 1

13,300 banks, approximately 10,500 banks have radio-equipped programmable capacitor controls 2

installed. The plan for the Capacitor Automation program is to replace failed Programmable Capacitor 3

Controls (PCC) and PCCs nearing the end of their lifecycle. SCE expects to replace 575 PCCs in 2013 4

and then 280 PCCs per year at an average cost of $5,100 each (constant 2012 $) as shown in Figure I-15 5

below. 6

Figure I-15 Capacitor Automation Program Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-PD-LG-CV


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 1,028 1,206 (76) 614 935 3,000 1,500 1,538 1,576 1,616

Constant 2012 $ 1,178 1,351 (81) 634 935 2,936 1,432 1,438 1,441 1,439

$(500)

$-

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500


Forecast

6. Circuit Automation Program–Blanket Budget Item, WBS Element CET-PD-OT-CI 7

The primary purpose of SCE’s Circuit Automation Program is to automatically restore 8

power to customers after an unplanned outage. The equipment installed as part of this program also 9

helps isolate faults which helps us restore power more quickly and reduce the number of customer 10

impacted by an outage. To further reduce the duration of customer interruptions, additional fault 11

locating devices are deployed on circuits to provide more refined information about the location of 12

99

faults. This additional information allows us dispatch crew more effectively reducing the length of 1

outages. 2

In addition, the Circuit Automation program will install specialized devices that enable 3

SCE to detect and isolate faults on longer circuits. On longer circuits, substation breakers may not be 4

able to detect faults far from the substation. These devices help keep SCE’s protection schemes working 5

properly. 6

SCE expects to automate, approximately 160 switches per year between 2013 and 2017. 7

The cost of switch automation ranges from approximately $28,000 to $57,000 depending on whether the 8

switch is overhead or underground.145 Figure I-16 below shows the historical and forecast budget for 9

the Circuit Automation program. 10

145 Refer to workpaper entitled “Circuit Automation Quantity and Cost Estimate” for additional detail.

100

Figure I-16 Circuit Automation Program Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-PD-OT-CI


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 5,348 6,720 11,680 4,336 3,475 10,000 6,912 7,058 7,216 7,411

Constant 2012 $ 6,129 7,531 12,557 4,477 3,475 9,787 6,600 6,600 6,600 6,600

$-

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000


Forecast

7. Substation Load Information Monitor Program, WBS CET-OT-OT-AT 1

The Substation Load Information Monitor (SLIM) Program includes the work related to 2

installation of equipment for substation load monitoring. This program will provide SCE with data to 3

aid in circuit and substation transformer planning as well as improve real-time grid operations for 4

substations that do not currently have substation automation systems. In 2013 we plan to add load 5

monitoring to ten substations and twenty per year thereafter through 2017. 6

Figure I-17 below, shows 2013-2017 forecast expenditures for the SLIM Program. In 7

2012 constant dollars, average forecast expenditures over the 2013-2017 period are $1.045 million per 8

year. 146 9

146 Refer to workpaper entitled “Substation Load Information Monitoring Workpaper” for additional detail.

101

Figure I-17 Substation Load Information Monitor Program Capital Expenditures

Recorded 2008-2012/Forecast 2013-2017 WBS Element CET-OT-OT-AT


2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Nominal $ 562 1,127 1,151 1,177 1,209

Constant 2012 $ 0 0 0 0 0 552 1,083 1,081 1,082 1,089

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400


Forecast

H. Generator Interconnection Program 1

The Generation Interconnection program includes projects required to interconnect new 2

generating plants to our electrical system. These expenditures are driven by requests from generation 3

project developers who choose to have SCE construct the facilities necessary to interconnect their 4

projects to the SCE grid.147 SCE charges the generation project developers an annual carrying charge 5

for the capital expenditures we incur for these projects. The revenue we receive is assigned as Other 6

Operating Revenue and is credited against our overall cost of service.148 7

The Generator Interconnection Program includes 19 specific projects with operating dates in the 8

2013–2017 period for which SCE has entered into Interconnection Facility Agreements with the 9

147 Interconnection requests are made pursuant to SCE’s Wholesale Distribution Access Tariff (WDAT) for connections to

the CPUC-jurisdictional distribution system or SCE’s Transmission Owner (TO) Tariff for connections to the FERC-jurisdictional transmission system.

102

requesting parties.149 None of the projects in this category have SCE cost responsibility under CPUC 1

jurisdiction greater than $1 million. Therefore, consistent with our approach in the other sections of this 2

chapter, we have not included individual discussions of these projects. We have also included a blanket 3

budget with forecast expenditures for potential, but as yet uncommitted, interconnection facilities driven 4

by potential future interconnection requests. 5

I. Added Facilities Projects 6

SCE’s Tariff Rule 2, Section H, and Rule 21 define Added Facilities and Interconnection 7

Facilities as follows: 8

1. Facilities requested by an applicant which are in addition to or in substitution for standard 9

facilities which would normally be provided by SCE for delivery of service at one point, 10

through one meter, at one voltage class under its tariff schedules, or 11

2. A pro rata portion of the facilities requested by an applicant, allocated for the sole use of such 12

applicant, which would not normally be allocated for such sole use. 13

At the customer’s request, we provide added facilities materials and equipment for additional 14

reliability enhancements, beyond the meter services, requests for service at higher voltage levels and to 15

interconnect customer owned generation to our distribution system. Typical added facilities projects for 16

the distribution system include: 17

Subtransmission metered service; 18

Primary metered service–Distribution; and 19

Automatic Preferred Emergency (PE) services. 20

We charge a monthly fee for Added Facilities based on the total installed cost of the equipment 21

multiplied by the applicable monthly rate. Added Facilities can be financed by the customer, or, with 22

our approval, can be financed by the Company. The CPUC Authorized Added Facilities Options and 23

Rates Components are set forth in Rule 2.H of our tariffs. When the Added Facilities project is 24

customer financed, the equipment is deeded to SCE, and the customer pays the applicable federal and 25

state taxes for the contributions in aid of construction. For both financing options, the impact to the 26

Continued from the previous page 148 Other Operating Revenue is discussed by Ms. Reeves in her Other Cost and OOR Testimony. Exhibit SCE-03, Volume

10.

103

capital budget is identical. Revenues from these projects are treated as “Other Operating Revenue” and 1

recorded in sub-accounts 454.300 and 456.700, as discussed in Ms. Reeves Other Costs and Other 2

Operating Revenue testimony in Exhibit SCE-03, Volume 10. 3

Table I-19 Added Facilities Projects Capital Expenditure Summary

(Total Company Nominal $000) Line No.


DatePrior 2013 2014 2015 2016 2017 Total

1 06490 Port of Long Beach 66/12 kV Pier G May 2013 27,065 3,847 - - - - 30,912 2 06944 Ship 66/12 kV Substation Nov 2012 13,092 50 - - - - 13,142 3 07442 Ship 66/12 kV Substation 3rd Transformer May 2013 - 3,060 - - - - 3,060 4 06752 Leatherneck 115/33 kV Substation Jul 2013 33,504 26,096 - - - - 59,600 5 07299 Breitburn Energy Partners Nov 2013 412 3,977 - - - - 4,389 6 07458 OXY Long Beach Aug 2014 - 3,437 1,473 - - - 4,910 7 07253 Natural 66/12 kV Substation Dec 2015 989 6,077 27,291 20,936 14 - 55,307 8 Subtotal of Added Facilities Projects 75,063 46,544 28,764 20,936 14 - 171,320 9 Projects with CPUC-jurisdictional SCE cost <$1M 16,193 5,883 3,703 3,354 18,513 18,216 65,862

10 Total Added Facilities Projects 91,255 52,426 32,466 24,290 18,527 18,216 237,182

We have identified 7 projects with project costs equal to or greater than $1 million as shown in 4

Table I-19 above.150 A description and justification for each of these projects is provided below. The 5

total cost for these 7 projects is $237.2 million of which $96.2 million is CPUC-jurisdictional cost 6

forecast from 2013 to 2017. 7

1. Port of Long Beach 66/12 Pier G (Project #06490) 8

The Port of Long Beach (POLB) requested SCE serve new and existing loads at Pier G, 9

located in the city of Long Beach, California. The POLB estimated their initial new load would be 10

approximately 31 MVA, which would increase to an ultimate load of 64 MVA upon on construction of 11

all future projects including the South Slip fill and South and South West Wharf projects. SCE proposes 12

to construct two, 66/12 kV SCE-owned, customer dedicated substations to serve the initial Pier G 13

anticipated load. The new substations will be served by constructing looped 66 kV subtransmission 14

lines from the existing SCE Hinson 66kV subtransmission system. In anticipation of the POLB future 15

loads, which are expected to materialize in multiple phases, SCE has designed the substation facilities in 16

Continued from the previous page 149 Forecasts for these projects are included in the workpapers entitled “Generator Interconnection Projects Under $1

Million.”

150 Forecasts for projects less than $1 million are included in the workpapers entitled “Added Facilities Projects Under $1 Million.”

104

a manner that will allow for additional transformation capacity to be installed with minimum disruption 1

to the POLB service. SCE will also provide the 12 kV distribution system from the new customer 2

substation to serve the new future loads as well as existing load currently served by 12 kV circuits out of 3

SCE Pico 66/12 kV distribution substation. 4

The two new customer substations are named Stevedore 66/12 kV and Pier 66/12 kV 5

with an in service date of May 2013. Stevedore 66/12 kV is located along Harbor Scenic Dr., north of 6

Pier J, serving Pier G East Terminal. Pier 66/12 kV is located along Pier G Avenue North, south of 7

Harbor Plaza, serving Pier G West Terminal. 8

Each substation will initially consist of two 28 MVA 66/12 kV transformers and two (2) 9

12 kV distribution lines. Ultimate capacity of Stevedore 66/12 kV will be 56 MVA. Ultimate capacity 10

of Pier 66/12 kV substation will be 84 MVA. The 66 kV source lines will consist of one new Pico-11

Stevedore 66 kV Subtransmission Line, one new Stevedore-Pier 66 kV Subtransmission Line, and one 12

tap into existing Pico-Seabright 66 kV Subtransmission Line. The associated supportive elements 13

include installation of new MEER with necessary protection and telemetry equipment, installation of 14

revenue metering cabinets as well as installation of telecommunication facilities. The operating date for 15

the project is May 2013 and the total estimated cost of this project is $30.912 million.151 16

SCE reviewed the possibility of serving the POLB projected future load from existing 17

distribution system served from Pico 66/12kV substation. This option was determined not to be the 18

preferred option due to magnitude of the anticipated load, the geographical space limitation, and other 19

constraints which make the construction of additional 12 kV distribution circuits difficult if not 20

impossible. The proposed project was selected as the most feasible and reliable option to serve the 21

POLB projected loads. 22

2. Port of Long Beach Pier E Ship 66/12 kV Substation and 3rd Transformer (Projects 23

#06944, #07442) 24

POLB requested SCE to install a new customer substation to support the expansion of the 25

Middle Harbor Terminal Redevelopment project. The POLB has developed a master plan to execute the 26

Middle Harbor development project over a course of multiple years through the year 2018. SCE had 27

completed a MOS study which evaluated several distribution options to serve the POLB anticipated load 28

including the installation of new SCE distribution substations. SCE determined the installation of a new 29

151 Refer to workpaper entitled “Port of Long Beach 66/12 kV Pier G (Project #06490).”

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customer substation with an ultimate build out capacity of four 28MVA transformers and four 1

distribution circuits was the most cost effective and reliable option to support the anticipated ultimate 2

load demand after the construction of the Middle Harbor Expansion Project is completed. The project 3

consists of a new customer dedicated substation named Ship 66/12kV including two 28MVA 4

transformer banks and two 12kV distribution circuits. The operating date for Ship 66/12kV was 5

November 2012; however, minor residual work is required in 2013 prior to closing this project. The 6

total estimated cost for this project is $13.142 million.152 7

POLB provided authorization to SCE to install the third 28 MVA transformer and 12kV 8

circuit in the first quarter of 2013 which would increase current Ship Substation capacity from 56 MVA 9

to 84 MVA with a total of three 12kV circuits. The additional capacity is required to support the third 10

and fourth phases of POLB’s Middle Harbor expansion project. Major components of the project 11

include one 66/12 kV transformer bank bus structure, one new 28 MVA transformer, expansion of a 66 12

kV dead-end switchrack, and one 28.8 MVAR capacitor bank. The operating date for the third 13

transformer is May 2013 and the total estimated cost of this project is $3.060 million.153 14

3. Leatherneck 115/33 kV Substation (Project #06752) 15

This project is the construction of a customer dedicated 115/33 kV substation that is 16

required to serve the increasing load at the Marine Corps Air Ground Combat Center (MCAGCC) at 29 17

Palms Marine Base.154 The base load is presently 20 MVA and is expected to grow to 30 MVA over the 18

next five years. We anticipate load will reach a maximum of 35 MVA within ten years. The new 19

115/33 kV substation will consist of a four-element ring bus configuration served by two overhead 20

incoming 115 kV subtransmission lines originating from existing SCE Carodean and Hi Desert 21

Substations. The new substation will consist of two 115/33 kV transformer banks. One is a 56 MVA 22

transformer bank (two 28 MVA units side-by-side) serving two 33 kV circuits and the other is a 28 23

MVA transformer bank that will serve one 33 kV circuit. The scope includes new construction of 24

115kV subtransmission lines from two existing SCE substations (Carodean and Hi Desert) to the new 25

customer dedicated substation. The scope also includes installation of fiber optic lines on existing 26

152 Refer to workpaper entitled “Ship 66/12 kV Substation (Project #06944).”

153 Refer to workpaper entitled “Ship 66/12 kV Substation 3rd Transformer (Project #07442).”

154 See Application A. 11-05-029. (Application of Southern California Edison Company (U 338-E) For a Permit To Construct Electrical Facilities: Leatherneck Substation Project) for a detailed discussion of the purpose and need for this project.

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electrical poles between the Devers and Carodean Substations and modification to SCE’s existing 1

telecommunications system to meet protection requirements for the new customer dedicated 115/33 kV 2

substation. The operation date of the project is July 2013 and the total estimated cost of this project is 3

$59.600 million.155 4

4. Breitburn Energy Partners (Project # 07299) 5

To meet customer increase in load demand, an existing customer dedicated substation 6

(Nietos Substation) will need to be expanded. The major project components include; expanding Nietos 7

Substation to accommodate a new 66 kV switchrack equipped with two 66 kV source lines, installing 8

three Circuit Breakers in a modified ring bus configuration to accommodate the looping of the existing 9

Center-Pioneer-Santa Fe Springs 66 kV Subtransmission Line and installation of a 66 kV underground 10

feeder to a new Transformer 18 MVA transformer. The associated supportive elements include; 11

converting the existing tap configuration to a looped configuration, installation and upgrade of 12

protective equipment, Remote Terminal Unit (RTU), and installation of new fiber optic cable and 13

supportive telemetry components. The operating date is November 2013, and the total estimated cost of 14

this project is $4.389 million.156 SCE did not identify alternatives for the project. The proposed project 15

is the only viable technical solution. 16

5. OXY Long Beach (Project # 07458) 17

SCE was requested to serve a customer’s existing and future load from the SCE 66 kV 18

sub transmission system with a total demand of 16.5 MVA. SCE has determined that a new 66/12 kV, 19

28.8 MVA substation and one 12 kV distribution circuit would be required to serve the Oxy ultimate 20

load. The new customer substation named Process 66/12 kV will be served by looping the future Pier-21

Wharf 66 kV subtransmission line forming Process-Pier and Process-Wharf 66 kV subtransmission 22

lines. Associated supportive elements will include; installation and upgrade of protective equipment, 23

Remote Terminal Unit (RTU), installation of new fiber optic cable and supportive telemetry 24

components. The operating date is August 2014, and the total estimated cost of this project is estimated 25

to be $4.910 million.157 26

155 Refer to workpaper entitled “Leatherneck 115/33 kV Substation (Project #06752).”

156 Refer to workpaper entitled “Breitburn Energy Partners (Project #07299).”

157 Refer to workpaper entitled “OXY Long Beach (Project #07458).”

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SCE evaluated several options to serve the customer’s existing and future new load from 1

existing distribution system served mostly from SCE Pico 66/12 kV distribution substation. The result 2

of the MOS study showed that it was most cost effective and reliable to serve the customer current and 3

future anticipated load from SCE’s 66kV subtransmission system. 4

6. Natural 66/12 kV Substation (Project #07253) 5

This project involves the construction of a customer-dedicated substation to serve load at 6

a site near the area of Aliso Canyon.158 The customer’s base load is 890 kW with approximately 3 MW 7

of potential standby to back up its onsite generation. The customer has requested two 28 MVA 8

transformer banks. As part of this project, we will install a new 66/12 kV substation adjacent to the 9

customer property with two transformers, a six position 66 kV operation/transfer bus, two positions for 10

the transformer banks, two 66 kV capacitors and an eight position 12 kV operating/transfer bus to feed 11

four 12 kV circuits to the customer. In addition, SCE will need to upgrade two existing SCE 66 kV 12

subtransmission lines, known as the Chatsworth-MacNeil-Newhall-San Fernando line and the MacNeil-13

Newhall-San Fernando line. The operating date is December 2015 and the total estimated cost of this 14

project is $55.307 million.159 15

J. Vote Solar Settlement 16

As part of its 2012 GRC proceeding, SCE entered into a settlement agreement with the Vote 17

Solar Initiative concerning distributed generation on SCE’s system.160 18

The settlement required that SCE, beginning in 2012, track retail and wholesale distributed 19

generation projects and installations, both existing and planned, and incorporate this data into its peak 20

demand forecasts. As discussed above in Section I.D.4, SCE considers distributed generation in its 21

planning process and has studied how much of it can be relied upon to meet peak load. SCE’s peak load 22

and capacity forecasts are adjusted to account for installed distributed generation. In addition, SCE 23

forecasts future installations of distributed generation based on historical installations. This allows SCE 24

to include distributed generation in its 10 year load growth plan.161 25

158 See Application A. 09-09-020. (Proponent’s Environmental Assessment – Southern California Gas Company Aliso

Canyon Turbine Replacement Project) for a detailed discussion of the purpose and need for this project.

159 Refer to workpaper entitled “Natural 66/12 kV Substation (Project #07253).”

160 The Commission accepted this settlement in its decision. D.12-11-051, p. 889.

161 SCE currently only includes solar distributed generation in its forecast.

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The agreement also required that, beginning in 2012, SCE conduct screening studies of planned 1

distribution upgrade projects to determine the viability of distributed generation as an alternative to these 2

planned distribution upgrades. The agreement required that SCE document the results of its screening in 3

its DSP.162 SCE has met these requirements, and has begun screening DSP projects. The results of this 4

screening will be included in SCE’s next DSP publication covering 2013 to 2022. 5

We agreed to calculate the amount of dependable generation connected to the distributed system 6

based on actual operating history during peak load periods and incorporate that calculation into 7

distribution substation and circuit load forecasts. This requirement applied only where “metered 8

generator output data is readily available to facilitate the 'dependable generation' calculation.”163 9

Although distributed generation PV projects over 1 MW have readily available data, we do not have 10

enough historical metered data to calculate dependable capacity for an individual distributed generator. 11

We do, however, consider a portion of all PV generation to be dependable and incorporate this 12

calculation in our load forecast. This is discussed in Section I.D.4. 13

The settlement agreement required SCE to explain in this rate case any difference between its 14

dependable generation calculation and the Commission’s adopted counting rules for the resource 15

adequacy capacity of wholesale generation using the same technologies as the distributed generation 16

units. The Commission’s counting rules for wind and solar resource adequacy are based on a 36 month 17

history. As discussed above, there is not enough readily available DG data for projects to produce a 36 18

month history as required in the resource adequacy calculation. SCE currently does not apply these 19

adopted counting rules for resource adequacy capacity due to the lack of data to determine if the 20

calculation accurately reflects dependable generation on the peak load day. Developing load growth 21

plans without data to accurately forecast dependable generation during peak loading can jeopardize 22

service reliability. 23

SCE agreed to test the market with one pilot request for proposal (RFP) during the 2012 GRC 24

cycle in an effort to identify viable distributed generation alternatives to traditional distribution system 25

upgrades. The agreement stated that at least one month prior to issuing the RFP, SCE will send an email 26

162 The agreement stated “To conduct these studies, SCE will employ the process described in ‘Southern California Edison

Company’s Methodology for Evaluating Distributor [sic] Generation as a Distribution Alternative,’ filed May 13, 2003 in compliance with Ordering Paragraph 2 of D.03-02-068.”

163 VSI Settlement, p. 2, D.12-11-051, Ordering Paragraph 42.

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notification regarding the upcoming RFP to parties on certain Commission service lists.164 We plan to 1

issue the RFP during the fourth quarter of 2013. In addition, in accordance with the settlement 2

agreement, SCE will report the results to the Commission by 2014.3

164 A.10-11-015 (SCE 2012 GRC), R.11-05-005 (RPS), R.08- 08-009 (RAM), and A.08-03-015 (SCE Utility Owned PV).

Appendix A

Witness Qualification

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF ROBERT G. WOODS 3

Q. Please state your name and business address for the record. 4

A. My name is Robert G. Woods, and my business address is Three Innovation Way, Pomona, 5

California, 91768. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Director of Electric System Planning for the Engineering and Technical Service (E&TS) 8

within Southern California Edison Company’s Engineering and Technical Service (ET&S) 9

organization. Electric System Planning is responsible for transmission, distribution, substation 10

subtransmission planning, interconnection studies and customer support. 11

Q. Briefly describe your educational and professional background. 12

A. I hold a Bachelor of Science degree in Electrical Engineering from California State University of 13

Long Beach. I joined Southern California Edison in 1985 and have held a variety of planning, 14

engineering, and management positions since. I have been in my current position since July, 15

2010. 16

Q. What is the purpose of your testimony in this proceeding? 17

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-03, Volume 3, 18

entitled Transmission and Distribution - System Planning Capital Projects as identified in the 19

Table of Contents thereto. 20

Q. Was this material prepared by you or under your supervision? 21

A. Yes, it was. 22

Q. Insofar as this material is factual in nature, do you believe it to be correct? 23

A. Yes, I do. 24

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 25

judgment? 26

A. Yes, it does. 27

Q. Does this conclude your qualifications and prepared testimony? 28

A. Yes, it does. 29