2015 General Rate Case · SCE-04: Customer Service Volume 02 – Customer Service Operations Table Of Contents Section Page Witness -i- I. OVERVIEW OF CUSTOMER SERVICE OPERATIONS

Application No.: Exhibit No.: SCE-04, Vol. 02 Witnesses: D. Bernaudo

T. Felix C. Hu S. Kiner J. Lim L. Miller L. Oliva C. Prescott A. Terki-Hassaine

(U 338-E)

2015 General Rate Case

Customer Service Volume 2 –Customer Service Operations

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SCE-04: Customer Service Volume 02 – Customer Service Operations

Table Of Contents

Section Page Witness

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I. OVERVIEW OF CUSTOMER SERVICE OPERATIONS ..............................1 A. Terki-Hassaine

A. Impact of a Fully Deployed ESC Program on Customer Service Operations .................................................................................2

B. CSOD Support of SCE’s Customer Engagement Strategy ....................3

C. Productivity and Operational Excellence ...............................................5

D. Service Guarantees .................................................................................7

1. Historical Perspective ................................................................8

2. Service Guarantee Credits Included in 2015 Test-Year Forecast .............................................................................9

II. SUMMARY OF REQUEST FOR CUSTOMER SERVICE OPERATIONS .................................................................................................10

III. METER SERVICES ORGANIZATION (MSO) ............................................12 L. Oliva

A. Meter Services Organization Functions ...............................................13

1. Meter Reading Operations [FERC Account 902] ....................13

a) Description of Meter Reading Function ......................13

(1) Automated Meter Reading – ESC Operations Center (SOC) .................................13

(2) Manual Meter Reading Function .....................14

(3) Real-Time Energy Meter Function ..................15

b) Operating Results .........................................................15

c) Analysis of Historical Data – Meter Reading FERC Account 902 ......................................................17

(1) Removal of Non-Recurring Legacy Meter Reading Costs ........................................17

(2) Addition of Ongoing Steady-State Automated Meter Reading Costs .....................18


Table Of Contents (Continued)


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(3) Historical Year-to-Year Variances ..................19

d) Test Year Operation Expectations FERC Account 902 .................................................................19

(1) Determination of Test Year Estimating Method ...........................................20

(2) Test Year Adjustments .....................................20

2. Test, Inspect and Repair Meters [FERC Account 586.400] ...................................................................................23 D. Bernaudo

a) Description of the Test, Inspect and Repair Meters Function ...........................................................23

(1) Description of the Electrical Metering Services (EMS) Function .................23

(2) Description of the Engineering and Meter Shop Functions ......................................24

(3) Description of Field Maintenance and Repair of Electric Meters ..........................25


(1) Operating Results - EMS .................................26

(2) Operating Results - Engineering and Meter Shop .......................................................28

c) Analysis of Historical Data ..........................................29

d) Test Year Operating Expectations FERC Account 586.400 ..........................................................30



3. Turn-On and Turn-Off Services [FERC 586.100] ...................33




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a) Description of Turn-On and Turn-Off Services ........................................................................33

b) Operating Results - Turn-On and Turn-Off Services ........................................................................34


d) Test Year Operating Expectations FERC Account 586.100 ..........................................................37



4. Customer Installation and Energy Theft Expense [FERC Account 587] ...............................................................39

a) Description of the Customer Installation and Energy Theft Expense ..................................................39

(1) Customer Installation .......................................39

(2) Energy Theft ....................................................42

(3) Field Services Management and Supervision ......................................................45


(1) Customer Installation Expense Operating Results .............................................45

(2) Energy Theft Operating Results .......................46

(3) Field Services Management and Supervision - Operating Results ......................47


d) Test Year Operating Expectations FERC Account 587 .................................................................49




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5. Meter Services Operations and Management [FERC 580] ..........................................................................................51

a) Description of Meter Services Operations and Management Support ............................................51

(1) CS Safety .........................................................51

(2) Management Support .......................................53


(1) CS Safety .........................................................54

(2) Operations and Management Support ..............55


(1) Customer Service Safety ..................................56

(2) Management Support .......................................56

d) Test Year Operating Expectations FERC Account 580 .................................................................57



B. Meter Services Organization Capital ...................................................60

1. Overview ..................................................................................60

2. Metering Capital Requirements (CCS-00-CM-CO-RB-00001, CCS-00-CM-CO-RB-00003, CCS-00-CM-CO-RB-00004, CCS-00-CM-CO-RB-00005, CCS-00-CM-CO-RB-00006, CCS-00-CM-CO-NR-00001, CCS-00-CM-CO-NR-00002) .......................................60




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a) Meter Capital Forecast .................................................60

(1) New Growth Meter Installations (Residential, Commercial, and Agricultural) .....................................................60

(2) Replacement Meter Capital (Residential, Commercial, & Agricultural) .....................................................61

(3) Legacy Meters (including Opt-Out Program) ..........................................................61

(4) Real Time Energy Meters (RTEM) Meters ..............................................................61

b) Historical Expenditures ................................................62

c) Growth Meter Forecast ................................................62

d) Replacement Meter Forecast ........................................63

e) Forecast Requirements .................................................64

(1) Routine Work ...................................................65

(2) Non-Routine Work...........................................65

3. Specialized Equipment (CCS-00-SE-CO-MS-00001, CCS-00-SE-CO-MS-00004, CCS-00-SE-CO-MS-00005) ........................................................................66

a) Hand-Held Meter Interrogation Devices .....................66

b) Tool Kits ......................................................................67

c) Temperature Cycle Chambers......................................67

4. Structures and Improvements (CCS-00-SI-CO-MS-00001) ......................................................................................67

a) Meter Shop ...................................................................67

IV. REVENUE SERVICES ORGANIZATION (RSO) ........................................69 C. Hu




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A. Description of the Revenue Services Organization Functions ..............................................................................................69

1. Billing Services [FERC Account 903.500] ..............................70

a) Description of Billing Function ...................................70

(1) Energy Usage and Billing Process Oversight ..........................................................70

(2) Billing Exception Processing ...........................71

(3) Program Services .............................................73

(4) Project Management ........................................74

(5) Policy Adjustments ..........................................74

b) 2012 Operating Results - Billing .................................74

(1) Billing Performance Measures .........................74

(2) Meter Data Management System (MDMS) ...........................................................77

(3) Complex Rates and the Manual Billing Process .................................................79

c) Analysis of Historical Data – Billing FERC Account 903.500 ..........................................................81

(1) Billing – Without Policy Adjustments .....................................................81

(2) Recorded and Adjusted Policy Adjustments .....................................................83

d) Test Year Operating Expectations –FERC Account 903.500 ..........................................................84






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(3) Customer Growth .............................................89

(4) Program Changes .............................................89

(5) Productivity Operational Excellence ...............91

(6) Forecast Method...............................................91

2. Credit and Payment Services [FERC Account 903.200] ...................................................................................92

a) Description of the Credit Functions .............................92

(1) Credit Risk Assessment ...................................93

(2) Collection Activities ........................................93

(3) Residential Disconnection OIR Impact on SCE’s Uncollectible Expense ............................................................96

b) 2012 Operating Results – Credit ..................................97

(1) Recovery of Interim Disconnect OIR Cost in the Residential Service Disconnection Memorandum Account (RSDMA) ..........................................99

c) Description of the Payment Services Functions ....................................................................101

(1) Electronic Payment Options ..........................101

(2) Mail-In Payments ...........................................102

(3) In-Person Services .........................................102

d) 2012 Operating Results - Payment Services ..............103

(1) Payment Services Performance Measures ........................................................103

(2) American Disability Act (ADA) Compliance ....................................................104




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(3) Electronic Payment Options ..........................106

(4) Mail-In Payments ...........................................106

(5) In-Person Services .........................................107

e) Analysis of Historical Data – Credit and Payment Services - FERC Account 903.200 .............107

(1) 2012 Base Year Adjustment for Nonrecurring Cost ..........................................110

f) Test Year Operating Expectations – FERC 903.200.......................................................................111

(1) Determination of Test Year Estimating Method .........................................111

(2) Test Year Adjustments ...................................112

g) SCE Prepayment Program .........................................114

(1) Eligibility .......................................................115

(2) Enrollment......................................................116

(3) Deposits..........................................................116

(4) Rates and Payments .......................................116

(5) Bad Debt ........................................................116

(6) Bill Statements ...............................................116

(7) Customer Alerts .............................................117

(8) Disconnection and Reconnection ...................117

(9) Capital Project ................................................117

(10) Energy Conservation Benefit .........................117

(11) O&M Costs and Benefits ...............................118

3. Postage [FERC Account 903.100] .........................................119




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a) Description of the Postage Function ..........................119

b) 2012 Operating Results ..............................................119

c) Analysis of Historical Data ........................................119

d) Test Year Operating Expectations FERC Account 903.100 ........................................................121

(1) Test Year Adjustments ...................................123

4. Uncollectible Expenses [FERC Account 904] .......................125

a) Description of Uncollectible Expense .......................125

b) Accounting for Uncollectible Expense ......................125

c) Uncollectible Expense Operating Results ..................126

(1) Disconnect OIR Impact on Uncollectible Expense in 2012 ......................127

(2) Three-Year Impact of the Disconnect OIR on Uncollectible Expense 2010 – 2012.............................................................129

(3) Residential Disconnection Memorandum Account ..................................130

(4) Residual Impact of the Disconnect OIR Provisions Beyond 2012 ........................131

(5) Analysis of Historical Data ............................131

d) Uncollectible Expense Financial Analysis and Forecast - FERC Account 904 ............................132

(1) Test Year Operating Expectations – FERC 904.......................................................133

(2) Adjustments to Historical Average ................136




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(3) Recorded Uncollectible Expense for 2005 and 2006 Should Not be Used to Predict Future Levels. ................................139

V. CUSTOMER CONTACT CENTER (CCC) ..................................................141 T. Felix

A. Customer Contact Center Functions ..................................................142

1. Description of Customer Contact Center Functions ..............142

2. Operating Results ...................................................................144

a) Functions and Activity Levels ...................................144

(1) Inbound Calls .................................................144

(2) Outbound Calls ..............................................145

(3) Other Channels and Operations Support ...........................................................145

b) Performance Metrics ..................................................146

3. Analysis of Historical Data ....................................................148

a) Year to Year Variances – 2008 through 2012............................................................................148

b) ESC Costs and Benefits .............................................149

4. Test Year Operating Expectations .........................................149

5. Determination of Test Year Estimated Method .....................150

6. Test Year Adjustments ...........................................................151

a) Incremental ESC Costs ..............................................151

(1) Impacts of ESC to Average Handle Time ...............................................................152

(2) Impacts of ESC on Increased Telephone Bills Due to Increased Call Volumes and AHT .................................159




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b) Customer Growth .......................................................159

c) Program Changes .......................................................159

(1) Impacts of Evolving Customer Expectations on Other Contact Channels .........................................................159

(2) The Expanded Energy Advisory Role for CSRs Requires Fair Compensation ................................................160

(3) Productivity - Operational Excellence ......................................................162

VI. PROGRAM MANAGEMENT ORGANIZATION (PMO) ..........................164 L. Miller

A. Description of Program Management Organization Function .............................................................................................164

B. Operating Results ...............................................................................164

C. Analysis of Historical Data (FERC Account 907.700) ......................165

D. Test Year Expectations (FERC Account 907.700) ............................166

1. Determination of Test Year Estimating Method ....................166


a) Data Management ......................................................167

b) Portfolio Oversight Staffing .......................................168

c) O&M Related to Capital Programs ............................168

VII. CONSUMER AFFAIRS AND CUSTOMER SATISFACTION ..................169 J. Lim

A. Consumer Affairs Function................................................................169

1. Description of the Consumer Affairs Function ......................169

2. Consumer Affairs Base Year Operating Results ...................169

a) Customer Inquiry and Complaint Handling ...............169




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b) Outreach Programs.....................................................171

3. Consumer Affairs Test Year Expectations ............................173

B. Customer Satisfaction Function .........................................................174

1. Description of Customer Satisfaction Function .....................174

2. Customer Satisfaction Base Year Operating Results .............174

a) Improving Outage Management Communications ........................................................174

(1) Accessing Outage Information Via Mobile Devices ..............................................175

(2) Reaching our MBL customers during an outage ........................................................176

(3) More Timely Outage Notifications ................176

b) Proactively Addressing High Bill Inquiries / Questions About the Bill ............................................177

3. Customer Satisfaction Test Year Expectations ......................178

C. Analysis of Historic Data (FERC Account 905.800).........................179




VIII. MARKETING, COMMUNICATIONS AND DIGITAL DELIVERY OF CUSTOMER SERVICES ...................................................182 J. Lim

A. Marketing and Communications Function .........................................182

1. Description of the Marketing and Communications Function .................................................................................182

2. Marketing and Communications Base Year Results .............182




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a) Comprehensive Annual Summer Conservation Campaign .............................................183

b) Program Specific Outreach ........................................184

(1) Enabling Customers to Utilize Energy Usage Information .............................184

(2) Informing PEV Consumers of Charging and Rate Options ............................185

(3) Rate Communications ....................................185

3. Marketing and Communications Test Year Expectations ...........................................................................186

a) Evolving Marketing and Communications through Intelligent Delivery .......................................186

B. Digital Delivery of Customer Services Function ...............................188 S. Kiner

1. Description of Digital Delivery of Customer Services ..................................................................................188

2. Digital Delivery of Customer Services Base Year Operating Results ...................................................................189

a) Improved content and information on SCE.com ....................................................................192

b) Improved access for non-English speaking, low-income, and special needs customers .................192

c) Improved Data Security and Customer Privacy .......................................................................192

d) Added New Functionality for Self-Service................193

3. Digital Delivery of Customer Services Test Year Expectations ...........................................................................193

a) Evolving Digital Channels through Intelligent Delivery ....................................................193




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b) Evolve Billing, Payment, and Energy Information Access ....................................................194

c) Optimize, Maintain and Deliver Web Accessible and In Language Services ........................194

d) Increased Digital Notifications to Support Self Service Transactions and Engagement ...............195

C. Analysis of Historical Data (FERC Account 905.900) ......................195




IX. OPERATING UNIT MANAGEMENT AND SUPPORT ............................199 C. Prescott

A. Description of Operating Unit Management and Support .................199

1. Finance and Administration ...................................................199

a) Description of Finance and Administration Functions ....................................................................199

(1) Planning and Performance Reporting ............199

(2) Regulatory Finance and Long-Term Planning .........................................................200

(3) Internal Controls ............................................200

(4) Timekeeping ..................................................200

(5) Payment Processing .......................................201

2. Business Planning ..................................................................201

a) Description of the Business Planning Function .....................................................................201

3. Customer Service Regulatory and Tariff Program Support ...................................................................................202




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a) Description of the DSM and Customer Service Regulatory and Tariff Support Function .....................................................................202

4. Training ..................................................................................202

a) Description of the Training Function .........................202

B. Base Year Operating Results .............................................................203

1. Summary of Recorded Costs (FERC Account 901) ..............203

2. Analysis of Historic Data (FERC Account 901)....................203

C. Test Year Expectations (FERC Account 901) ...................................204

1. Determination of Test Year Estimating Methodology ..........................................................................205


a) Customer Growth .......................................................206

b) Productivity / Operational Excellence .......................206

X. OTHER OPERATING REVENUES (OOR).................................................207 C. Hu

A. Introduction ........................................................................................207

B. Estimating Method for OOR ..............................................................208

1. Estimating Process .................................................................208

C. Residential Service Charges ..............................................................209

1. FERC Account 450.150 – Residential Late Payment Charge (LPC) .........................................................................209

2. FERC Account 451.300 – Residential Service Connection Charge.................................................................210

3. FERC Account 451.820 – Opt-Out Program Fee ..................212 L. Oliva

D. Non-Residential Service Charges ......................................................214 C. Hu




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1. FERC Account 450.100 – Non-Residential Late Payment Charge .....................................................................214

2. FERC Account 451.310 – Non-Residential Service Connection Charge.................................................................215

E. Other Service Charges .......................................................................217

1. FERC Account 451.110 – Returned Check Charge...............217

2. FERC Account 451.320 – At-Pole Service Connection Charge.................................................................219

F. Direct Access (DA) and Community Choice Aggregation (CCA) Fees ........................................................................................221

1. FERC Account 456.401 – Direct Access Service Fees ........................................................................................221

2. FERC Account 456.412 – Community Choice Aggregation (CCA) Service Fees ..........................................224

G. Other - Miscellaneous OOR Accounts ..............................................226

1. FERC Account 456.415 – Manufactured Home Billing Service .......................................................................226

2. FERC Account 456.948 – Optimal Billing Period ................227

3. FERC Account 451.780 – Misc. Revenues-Recovered for Unauthorized Use / Non-Energy ....................229

4. Demand Response Provider Service Fees..............................230

H. Fees to Eliminate................................................................................231

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

Appendix B SCE’s Efforts to Work with CBOs in all Aspects of Customer Education and Outreach ....................................................................................... J. Lim


List Of Figures

Figure Page

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Figure I-1 SCE’s New Customer Service Model .........................................................................................3

Figure II-2 Summary of O&M Forecast for Customer Service Operations (Excluding

Uncollectibles) (Constant 2012 $000s) ................................................................................................11

Figure III-3 Meter Reading FERC Account 902 (Constant 2012 $000s) ..................................................20

Figure III-4 Meter Reading Comparison of 2012 Base Year to 2015 Test Year FERC

Account 902 (Constant 2012 $000s)....................................................................................................21

Figure III-5 Test, Inspect and Repair Meters FERC Account 586.400 (Constant 2012

$000s) ...................................................................................................................................................31

Figure III-6 Test, Inspect and Repair Meters Comparison of 2012 Base Year to 2015 Test

Year FERC Account 586.400 (Constant 2012 $000s) .........................................................................32

Figure III-7 Turn-On and Turn-Off Services FERC Account 586.100 (Constant 2012

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

Figure III-8 Turn-On and Turn-Off Services Comparison of 2012 Base Year to 2015 Test

Year FERC Account 586.100 (Constant 2012 $000s) ........................................................................38

Figure III-9 Customer Installation and Energy Theft FERC Account 587 (Constant 2012

$000s) ...................................................................................................................................................49

Figure III-10 Customer Installation and Energy Theft Comparison of 2012 Base Year to

2015 Test Year FERC Account 587 (Constant 2012 $000s) ...............................................................50

Figure III-11 Meter Services Operations and Management FERC Account 580 (Constant

2012-$000s) .........................................................................................................................................57

Figure III-12 Meter Services Operations and Management Comparison of 2012 Base

Year to 2015 Test Year (Constant 2012 $000s) ...................................................................................59

Figure IV-13 ESC Meters Exceptions vs. ESC Meters Installed ...............................................................79

Figure IV-14 Billing FERC Account 903.500 2008 – 2015 Adjusted / Recorded and

Forecast Expenses (Constant 2012 $000s) ..........................................................................................85

Figure IV-15 Billing Comparison of 2012 Base Year to 2015 Test Year FERC Account

903.500 (Constant 2012 $000s) ...........................................................................................................88

Figure IV-16 Uncollectible Expense vs. Number of Credit Disconnections 2008-2012 .........................98


List Of Figures (Continued)

Figure Page

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Figure IV-17 Credit and Payment Services FERC Account 903.200 (Constant 2012

$000s) .................................................................................................................................................111

Figure IV-18 Credit and Payment Services Comparison of 2012 Base Year to 2015 Test

Year FERC Account 903.200 (Constant 2012 $000s) .......................................................................113

Figure IV-19 Postage FERC Account 903.100 (Constant 2012 $000s) ..................................................122

Figure IV-20 Postage Comparison of 2012 Base Year to 2015 Test Year FERC Account

903.100 (Constant 2012 $000s) .........................................................................................................124

Figure IV-21 History of Service Disconnects and Uncollectible Expense 2008 – 2012 .........................129

Figure IV-22 History of Uncollectible Factor and Test Year Factor Through 2012 ...............................132

Figure IV-23 Uncollectible Factor Forecast Historical Trend 2008 – 2017 ............................................134

Figure IV-24 Uncollectible Factor Five-Year Average 2008 through 2017 ...........................................136

Figure V-25 Customer Contact Center FERC Account 903.800 (Constant 2012 $000s) .......................150

Figure V-26 Comparison of 2012 Base Year to 2015 Forecast FERC Account 903.800

(Constant 2012 $000s) .......................................................................................................................151

Figure V-27 2009 to 2017 Average Handle Time ...................................................................................157

Figure VI-28 Program Management Organization FERC Account 907.700 (Constant

2012 $000s) ........................................................................................................................................166

Figure VI-29 Program Management Organization Comparison of 2012 Base Year to

2015 Test Year FERC Account 907.700 (Constant 2012 $000s) ......................................................167

Figure VII-30 Consumer Affairs and Customer Satisfaction FERC Account 905.800

(Constant 2012 $000s) .......................................................................................................................180

Figure VII-31 Consumer Affair and Customer Satisfaction Comparison of 2012 Base

Year to 2015 Test Year FERC Account 905.800 (Constant 2012 $000s) .........................................181

Figure VIII-32 Marketing, Communications, and Digital Customer Services FERC

Account 905.900 (Constant 2012 $000s)...........................................................................................197

Figure VIII-33 Marketing, Communications, and Digital Customer Services Comparison

of 2012 Base Year to 2015 Test Year FERC Account 905.900 (Constant 2012 $000s) ...................198

Figure IX-34 Operating Unit Management and Support FERC Account 901.........................................205


List Of Figures (Continued)

Figure Page

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Figure IX-35 Operating Unit Management and Support Comparison of 2012 Base Year to

2015 Test Year FERC Account 901 (Constant 2012 $000s) .............................................................206

Figure X-36 FERC Account 450.150 Residential Late Payment Charge Revenue Forecast

(Nominal $000s) ................................................................................................................................210

Figure X-37 FERC Account 451.300 Residential Service Connection Charge Revenue

Forecast (Nominal $000s) ..................................................................................................................211

Figure X-38 FERC Account 450.100 Non-Residential Late Payment Charge (Nominal

$000s) .................................................................................................................................................215

Figure X-39 FERC Account 451.310 Non-Residential Service Connection Charge

(Nominal $000) ..................................................................................................................................216

Figure X-40 FERC Account 451.110 Returned Check Charge Revenue (Nominal $000s) ....................218

Figure X-41 FERC Account 451.320 At-Pole Service Connection Charge (Nominal

$000s) .................................................................................................................................................221

Figure X-42 FERC 456.401 DA Service Fee Revenues (Nominal $000s) ..............................................224

Figure X-43 FERC Account 456.412 CCA Service Fee Revenue (Nominal $000s) ..............................225

Figure X-44 FERC Account 456.415 Manufactured Home Billing Service (Nominal

$000s) .................................................................................................................................................227

Figure X-45 FERC Account 456.948 Optimal Billing Period (Nominal $000s) ....................................229

Figure X-46 FERC 451.780 Miscellaneous Revenue from Unauthorized Use/Non-Energy

(Nominal $000s) ................................................................................................................................230


List Of Tables

Table Page

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Table I-1 Productivity Initiatives Impact to 2015 Test Year Forecast ($ millions) .....................................6

Table I-2 SCE’s Service Guarantee Program 2012 Results Nominal $s ....................................................7

Table I-3 Service Guarantee Credits – Five Year Average Nominal $s ......................................................9

Table II-4 Summary of O&M For Customer Service Operations (Excluding

Uncollectibles) (Constant 2012 $000s) ................................................................................................10

Table III-5 Meter Reading Cost Per Read Prior to and Post ESC (2008-2015) (Constant

2012 $000s) ..........................................................................................................................................16

Table III-6 Meter Reading 2008-2012 Recorded and Adjusted Expenses FERC Account

902 (Constant 2012 $000) ....................................................................................................................17

Table III-7 Percent of Automated Meter Reading Operations 2008 – 2012 ..............................................18

Table III-8 Meter Test and Inspection 2008–2012 ....................................................................................26

Table III-9 Forecast Meter Test and Inspection 2013-2015 ......................................................................27

Table III-10 Meter Shop Tests 2008 – 2015 ..............................................................................................29

Table III-11 Test, Inspect and Repair Meters 2008-2012 Recorded and Adjusted

Expenses FERC Account 586.400 (Constant 2012 $000s) .................................................................29

Table III-12 Completed Turn-On and Off Orders 2008–2012 ..................................................................35

Table III-13 Turn-On and Turn-Off Services 2008-2012 Recorded and Adjusted

Expenses FERC 586.100 (Constant 2012 $000s) ................................................................................36

Table III-14 Field Service Pick-up Reads and Exception Orders 2008-2015 ...........................................40

Table III-15 Missed Appointment Service Guarantee Credits 2008-2012 Nominal $s .............................41

Table III-16 ESC Energy Theft Field Inspection Samples 2011 and 2012 (Constant 2012

$s) 44

Table III-17 Customer Installation Field Orders 2008-2012 .....................................................................46

Table III-18 Energy Theft and Billing Exception Cases in 2008-2012 (Constant 2012

$000) ....................................................................................................................................................46

Table III-19 Customer Installation and Energy Theft Expenses 2008-2012 Recorded and

Adjusted Expenses FERC Accounts 587 (Constant 2012 $000s) .......................................................47

Table III-20 Customer Service Operations DART Rate (2008-2012) .......................................................55


List Of Tables (Continued)

Table Page

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Table III-21 Meter Services Operations and Management 2008-2012 Recorded and

Adjusted Expenses FERC Account 580 (Constant 2012 $000s) .........................................................56

Table III-22 Capital Requirements (Nominal $ Millions) .........................................................................60

Table III-23 Metering Equipment Recorded 2008 – 2012 and Forecast 2013-2017

(Nominal $ Millions) ...........................................................................................................................62

Table III-24 Growth Meter Recorded and Forecast Volumes ...................................................................63

Table III-25 Replacement Meter Capital Volume Forecast .......................................................................64

Table III-26 Meter Capital Expenditure Forecast (Nominal $ Millions) ...................................................64

Table III-27 MSO Specialized Equipment Recorded 2008-2012 and Forecast 2013-2017

(Nominal $ 000s) .................................................................................................................................66

Table III-28 Structures and Improvements Expenditure Forecast (Nominal $000) ..................................68

Table IV-29 Program Services Historical Enrollment Volume 2008 – 2012 ...........................................73

Table IV-30 Billing Performance Measures 2008 – 2012 .........................................................................75

Table IV-31 Billing Exceptions 2008 – 2012 (Amounts in 000s) .............................................................77

Table IV-32 Usage Exceptions 2011 – 2012 (Amounts in 000’s) .............................................................78

Table IV-33 ESC Meters Cut-Over to Operations (COTO) Quarterly December 2011 –

December 2012 ....................................................................................................................................78

Table IV-34 Number of Customers on Complex Rates Requiring Manual Billing 2008 –

2012......................................................................................................................................................80

Table IV-35 Billing (Without Policy Adjustment Expense) 2008 – 2012 Recorded and

Adjusted Expenses FERC Account 903.500 (Constant 2012 $000s) ..................................................81

Table IV-36 Policy Adjustments (Without Billing Expenses) 2008 – 2012 Recorded and

Adjusted Expenses (Constant 2012 $000s) ..........................................................................................84

Table IV-37 Timely and Accurate First Bill – Service Guarantee 2008 – 2012 .......................................87

Table IV-38 Program Services Projected Enrollment Volumes 2013-2017 ..............................................90

Table IV-39 RSDMA O&M Costs August 2010-July 2013 (Nominal $000) .........................................100

Table IV-40 Payment Posting Volume in 2008-2012 (In 000s) ..............................................................103

Table IV-41 Average Cost-Per Payment for Payment Services in 2008-2012 ........................................104



Table Page

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Table IV-42 Payment Posting Timeliness 2008-2012 .............................................................................104

Table IV-43 2012 APA / ADA Compliance Results ...............................................................................105

Table IV-44 Electronic Payment Options and Volumes 2008-2012 (In 000s) ........................................106

Table IV-45 Credit and Payment Services – FERC Account 903.200 2008-2012

Recorded and Adjusted Expenses (Constant 2012 $000s) ................................................................108

Table IV-46 Credit and Payment Services –FERC Account 903.200 2008 – 2012

Recorded and Adjusted Expenses (Constant 2012 $000) ..................................................................111

Table IV-47 Costs and Benefits – Prepay Program 2015 through 2017 (Constant 2012

$000s) .................................................................................................................................................118

Table IV-48 Postage 2008-2012 Recorded and Adjusted Expenses FERC Account

903.100 (Constant 2012 $000s) .........................................................................................................120

Table IV-49 Mailings Per Customer ........................................................................................................120

Table IV-50 Postal Rates and Total Expense by Type of Mailing .........................................................123

Table IV-51 Uncollectible Factor and Expense 2012 Authorized Vs. 2012 Recorded

(Nominal $ Millions) .........................................................................................................................126

Table IV-52 Disconnect OIR Impact on Uncollectible Expense in 2012 (Nominal

Dollars) ..............................................................................................................................................127

Table IV-53 OIR Impact on Uncollectible Expense in 2010 – 2012 .......................................................131

Table IV-54 Calculation of Uncollectible Factor ....................................................................................137

Table IV-55 Statistical Probabilities that Recorded 2005 and 2006 Uncollectible Levels

Will Be Repeated in the Future ..........................................................................................................140

Table V-56 Functions and Activity Levels for the CCC 2008 – 2012 ....................................................144

Table V-57 CCC Performance Metrics 2008 – 2012 ...............................................................................147

Table V-58 Customer Contact Center 2008-20012 Recorded and Adjusted Expenses

FERC Account 903.800 (Constant 2012 $000s)................................................................................148

Table V-59 CCC Average Hourly Rate ...................................................................................................161

Table VI-60 Program Management Organization 2008-2012 Recorded and Adjusted

Expenses FERC Account 907.700 (Constant 2012 $000) .................................................................165



Table Page

-xxiii-

Table VII-61 Inquiries and Complaints Resolved by Consumer Affairs ...............................................170

Table VII-62 Consumer Affairs Average Complaint Resolution Time ...................................................170

Table VII-63 Historical Medical Baseline Participants by Type .............................................................172

Table VII-64 Medical Baseline Outage Communication Summary (2011-2012) ..................................176

Table VII-65 Consumer Affairs and Customer Satisfaction Recorded/Adjusted Expenses

(2008-2012) FERC Account 905.800 (Constant 2012 $000) ............................................................179

Table VIII-66 Key SCE Online Usage Trends in 2008-2012 ..................................................................189

Table VIII-67 Customer’s Preferred Method of Interaction with Electricity Provider ...........................191

Table VIII-68 Marketing, Education and Communications Recorded/Adjusted Expenses

(2008-2012) FERC Account 905.900 (Constant 2012 $000) ............................................................196

Table IX-69 Operating Unit Management and Support Recorded / Adjusted Expenses

(2008-2012) FERC Account 901 (Constant 2012 $000) ...................................................................204

Table X-70 Other Operating Revenue – Customer Service Operations Recorded 2008 –

2012 and Forecast 2013 – 2015 (Nominal $000s) .............................................................................208

Table X-71 Other Operating Revenue Service Fee Summary 2015 Proposed Fees

(Nominal $s) ......................................................................................................................................209

Table X-72 FERC Account 451.300 Residential Service Connection Charge Cost Study

(Nominal $s) ......................................................................................................................................212

Table X-73 FERC Account 451-820 Opt-Out Program Fee Comparison (Nominal $s) .........................213

Table X-74 FERC Account 451.310 Non-Residential Service Connection Charge Cost

Study (Nominal $s) ............................................................................................................................217

Table X-75 FERC 451.110 Cost Study-Returned Check Charge (Nominal $s) ......................................219

Table X-76 FERC Account 451.320 At-Pole Service Connection Charge Cost Study

(Nominal $s) ......................................................................................................................................220

Table X-77 DA Service Fees (Nominal $s) ............................................................................................222

Table X-78 DA Service Fee Revenues (Nominal $s) ..............................................................................223

Table X-79 CCA Service Fees (Nominal $s) ..........................................................................................226

1

I. 1

OVERVIEW OF CUSTOMER SERVICE OPERATIONS 2

Volume 2 of this Exhibit addresses the activities of the Customer Service Operations Division 3

(CSOD) of the Customer Service (CS) Operating Unit, which includes the Meter Services Organization 4

(MSO), Revenue Services Organization (RSO), and Customer Contact Center (CCC). Additional 5

sections of this Volume describe the customer education and outreach efforts related to Consumer 6

Affairs and Customer Satisfaction, and Marketing, Communications and Digital Delivery of Customer 7

Services. This Volume also describes the Operating Unit Management and Support (OUMS) 8

Organization that provides the finance, business planning, and regulatory support functions for CS, as 9

well as the Program Management Organization (PMO), which is responsible for managing the CS 10

project and technology portfolio. Additionally, this Volume includes the proposed service fees to reflect 11

the current cost of providing services that are recovered through Other Operating Revenues (OOR). 12

The CSOD functions comprise the Customer Accounts category of FERC Accounts 902 through 13

905, Program Management Organization expense in FERC Account 907.700 and portions of various 14

Distribution FERC Accounts in the 580 series. These CSOD functions and their Test Year forecasts are 15

described in Chapters III-VI. Consumer Affairs and Customer Satisfaction are described in Chapter VII 16

and will record to FERC Account 905.800. Marketing, Communications, and Digital Delivery Services 17

are described in Chapter VIII and record to FERC Account 905.900. The OUMS functions record to 18

FERC Account 901 and are described in Chapter IX. Finally, the OOR functions record to FERC 19

Accounts in the 450 series and are described in Chapter X. 20

The primary functions of CSOD include: 21

Meter Services Organization (MSO). MSO is responsible for the metering system and all meter-22

related activities including meter reading, meter testing, meter installation and removal, Edison 23

SmartConnect® (ESC) meter communication and operations, and field related customer services. These 24

services include turning electric service on and off, disconnecting electric service for nonpayment, 25

reconnecting service, negotiating access to customer premises, responding to billing and energy 26

consumption inquiries, installing new and replacing existing meter equipment, collecting exception 27

meter reads, and conducting service investigations for unmetered consumption (i.e., revenue protection). 28

Revenue Services Organization (RSO). RSO is responsible for all billing, payment, credit, 29

collection activities and various other programs. RSO activities include postage cost responsibilities for 30

over 53 million billing statements, notices, reminders, and correspondence that are issued each year to 31

2

customers. RSO is responsible for the operations of the Meter Data Management System (MDMS), 1

which manages the routine validation and exception processing of metered interval usage data being 2

accessed daily from nearly five million ESC meters. RSO activities also include operational oversight 3

for bills sent to all customers, exception billing for all residential and non-residential customers, credit 4

and collection management for all billed revenue, management of various customer-facing programs and 5

responsibility for operationalizing regulatory initiatives and activities that impact the routine billing 6

process. 7

Customer Contact Center (CCC). The CCC handles all inbound and outbound telephone 8

communications, communication through other channels, and operations support. The CCC responds to 9

customer requests and inquiries 24 hours a day, seven days a week in six different languages internally 10

and over 180 languages using a translation services vendor. Such support includes handling over 15 11

million inbound customer contacts per year and using Interactive Voice Response (IVR) and advanced 12

call routing technologies to effectively distribute calls to appropriately skilled Customer Service 13

Representatives (CSRs). 14

A. Impact of a Fully Deployed ESC Program on Customer Service Operations 15

In 2012, SCE was deploying ESC meters and enabling customer participation in ESC-enabled 16

programs and services. As such, in 2012, CSOD focused on integrating the ESC program into the 17

technology-enabled Customer Service Model. In December 2012, the four-year ESC deployment 18

program was completed. As a result, during 2013-2014, CSOD will focus on stabilizing its core 19

operations that were affected by the ESC program. 20

In its 2015 GRC, CSOD’s Test Year forecast reflects its ongoing, steady-state, post-ESC 21

deployment operations. The impacts of a fully deployed ESC program on customer service operations 22

are significant. For example, SCE will eliminate 99 percent of manual meter reading and will save 23

approximately $31.3 million annually through automated meter reading (Table I-1 provides summary 24

information on these productivity initiatives which are described in more detail in Chapter III). In 25

addition, MSO integrated the ESC Operations Center (SOC) that handles automated meter reading into 26

its operations and includes such operations in its 2015 forecast. Also, within MSO, the Remote Service 27

Switch (RSS) capabilities will now be used for turn-on/off for both eligible residential and commercial 28

customers (see Chapter III in this Volume). RSO’s Billing operations has fully integrated the Meter 29

Data Management System (MDMS) which provides customer interval usage validation and exception 30

processing of interval energy usage data retrieved from nearly five million ESC meters. (see Chapter IV 31

3

of this Volume). Interval data will also support the new demand response programs offered by SCE. 1

Within the CCC, our Customer Service Representatives (CSRs) will provide support for more complex 2

transactions that are enabled by the ESC meter (see Chapter V of this Volume). 3

B. CSOD Support of SCE’s Customer Engagement Strategy 4

As described in Volume 1 of this Exhibit, in this GRC period, SCE’s new Customer Service 5

Model includes five key interrelated components for engaging customers: Energy Solutions, Intelligent 6

Delivery and Energy Advisory Services, Effective and Enabling Interactions, Technology, and 7

Empowered Employees. Figure I-1 below illustrates these key elements of CS’s New Customer Service 8

Model. 9

Figure I-1 SCE’s New Customer Service Model

CSOD is one of the key organizations in CS responsible for delivering the Customer Service 10

Model and putting the processes in place to deliver customer programs and services. As described 11

below, CSOD delivers the key elements of SCE’s Customer Engagement Strategy. 12

SCE’s Energy Advisory Services will be provided by our CSRs in the CCC who will be 13

empowered and knowledgeable to deliver these services. The CSRs will use customer data, information 14

4

about our energy solutions, and industry expertise to advise customers on energy solutions. Energy 1

management is becoming more complex for customers due to the increasing amount of information 2

available, and the emerging technical solutions available to customers about managing their energy 3

consumption. As such, the CSRs will help customers understand these complexities and guide our 4

customers to the right mix of solutions for them. To provide Energy Advisory Services, CSRs will need 5

to expand their utility industry knowledge in order to provide customer education for expanded 6

programs and services, and SCE must empower its employees to offer and support our customers’ more 7

complex energy solutions. Accordingly, CSOD will equip our CSRs with the skills, systems, and 8

information necessary to enable them to advise our customers on energy solutions. Chapter V of this 9

Volume provides more information about empowering our CSRs to effectively deliver Energy Advisory 10

Services. 11

In addition to support through the traditional phone center and self-service channels, Intelligent 12

Delivery customer contact options will include emerging channels, such as click-to-chat and social 13

media. CSOD will extend its reach to our customers by providing customer service through other 14

contact channels, such as online, mobile, and other emerging channels. As described in Exhibit SCE-05, 15

Volume 2, SCE’s self-service customer service approach will enable such services. This is also 16

described in Chapter V of this Volume. Additionally, to support the Intelligent Delivery component of 17

the Customer Service Model, the ESC Operations Center (SOC) will provide advanced monitoring and 18

troubleshooting support for the ESC meter system, as well as advanced Home Area Network 19

troubleshooting performed to avoid manual troubleshooting at the customer’s premises. Chapter III of 20

this Volume provides more information about the SOC and advanced monitoring support. 21

The customer call to the CCC has traditionally served as the primary customer service interaction 22

point. Some of our customers will continue to use this traditional service without further interaction 23

with SCE. However, for those customers who want other engagement with SCE regarding their energy 24

solutions, SCE will provide enhanced engagement through Effective and Enabling Interactions to meet 25

their needs. Such enhanced engagement includes providing services through self-service channels, such 26

as online billing and payments, account information provided via the internet or mobile, automated 27

program and rate enrollments via the internet or mobile, and other emerging channels, such as click-to-28

chat. SCE’s Digital Experience capital software project will provide the foundation and functionalities 29

to provide such capabilities consistent with the Technology component of SCE’s Customer Service 30

Model. Capital software projects will be a foundational part of SCE’s solution to providing Energy 31

5

Solutions to its customers which are supported through CSOD’s operations. Details about the Digital 1

Experience capital software project, can be found in Exhibit SCE-05, Volume 2. 2

C. Productivity and Operational Excellence 3

In Exhibit SCE-10, Volume 2, SCE defines productivity as simply doing more while using 4

proportionately less.1 Productivity initiatives should meet at least one of the following two objectives: 5

(1) improve the level of service without adding cost; or (2) reduce cost with no adverse effect on service 6

levels. Projects meeting both objectives receive higher priority for implementation. 7

Using this definition, CSOD’s forecasts reflect operational improvements that are either 8

underway now or will be implemented by 2015 Test Year. The largest productivity initiative underway 9

for CSOD is the company-wide Operational Excellence program.2 The details of the cost savings that 10

result from implementation of the Operational Excellence program are addressed in each of the 11

operational areas in which the savings are realized. The CSOD Operational Excellence benefits are 12

summarized in Table I-1 below. The table lists the estimated Operations and Maintenance (O&M) 13

savings associated with each proposed initiative and the reference to the proposed initiatives’ 14

descriptions in testimony. To the extent these productivity initiatives delivered benefits in 2012 and/or 15

are forecast to deliver benefits in the 2015 Test Year, those benefits are reflected in our O&M forecast in 16

the respective FERC Account. 17

Table I-1 also lists the most significant performance improvement initiatives introduced in the 18

five-year historical period leading up to the recorded cost in the 2012 Base Year. Each of these 19

historical initiatives was described in direct testimony in our 2012 GRC.3 20

1 See Exhibit SCE-10, Chapter IV, Section A.

2 See SCE-10, Volume 2, Part 7 for more information about SCE’s Operational Excellence program.

3 See A.10-11-015, Exhibit SCE-04, Volume 2, p. 9.

6

Table I-1 Productivity Initiatives

Impact to 2015 Test Year Forecast ($ millions)

LineNo. Program Years

Estimated Cost Savings

Text Reference

FERC Acct

1 Historical 2 CCC - Phone Bill Contract Rates 2007-2008 $0.3 CH. V 903.8003

CCC- Contract Call Center (for credit-related calls) 2005-2009 $0.8 CH. V 903.8004 CCC- Phone Bill Contract Rates 2005-2009 $0.2 CH. V 903.8005 On-Line Billing - reduced postage costs 2007-2009 $0.8 CH. IV-A3 903.1006 Meter Reader Entry Level Wage 2007-2009 $0.1 CH. III-A1 902.0007 GPS Based Order Dispatching Technology 2006-2011 $0.2 n/a Various8 Enterprise Resource Planning (ERP) 2008-2011 $1.7 n/a Various9 On-Line Billing - reduced postage costs 2010-2013 $1.5 CH. IV-A3 903.100

10 CCC- Call Deflection 2012-2013 $1.8 CH. V 903.80011 CCC- Phone Bill Contract Rates 2012-2013 $0.4 CH. V 903.80012 Subtotal $7.913 Edison SmartConnect

Benefits

14 Turn On and Off Service 2012 $8.3 CH.III-A3 586.10015 Customer Installation Expense 2012 $2.6 CH.III-A4 587.00016 Meter Reading 2012 $23.7 CH.III-A1 902.00017 Credit 2012 $4.6 CH. IV-A2 903.20018 Billing - Accurate Bills 2012 $1.0 CH. IV-A1 903.50019 Call Center 2012 $1.0 CH. V 903.80020 Subtotal: Edison SmartConnect Benefits $41.221 Historical Total 2005-2013 $49.122 Future (Constant 2012 $)

23 Operational Excellence24 Meter Services Operations and Management 2015 $2.3 CH. III-A5 580.00025 Turn On and Off Service 2015 $0.4 CH. III-A3 586.10026 Test/Inspect/Repair Meters 2015 $1.2 CH. III-A2 586.40027 CS Customer Installation Expense 2015 $0.4 CH. III-A4 587.00028 Operating Unit Management & Support 2015 $0.6 CH. IX 901.00029 Meter Reading Operations 2015 $1.1 CH. III-A1 902.00030 Postage 2015 $0.8 CH. IV-A3 903.10031 Credit and Payment Services 2015 $1.1 CH. IV-A2 903.20032 Billing 2015 $2.6 CH. IV-A1 903.50033 CCC and Phone Bills 2015 $3.7 CH. V 903.80034 Marketing, Education and Communication 2015 $1.2 CH. VIII 905.900

35 Operating Unit Management and Support (Centralized) 2015 $2.3

CH. IX901.000

36 Subtotal: Operational Excellence $17.637 Other Productivity38 On-Line Billing - reduced postage costs 2015 $1.7 CH. IV-A3 903.10039 Budget Assistant Enrollment 2015 $0.2 CH. IV-A1 903.50040 Subtotal: Other Productivity $1.941 Future Total $19.5

7

D. Service Guarantees 1

SCE’s Service Guarantee Program was originally ordered by the Commission in SCE’s 2003 2

GRC.4 The program includes four separate service guarantee standards: (1) Missed Appointments, (2) 3

Service Restoration (within 24 hours), (3) Planned Outage Notification, and (4) Timely and Accurate 4

First Bill.5 SCE pays a $30 credit for each occurrence when these standards are not met. These credits 5

are currently shareholder-funded. A service guarantee claim may be made by a customer, but most 6

occurrences are identified through SCE’s own internal processes, procedures, and systems. In 2012, 7

SCE “self-reported” approximately 96 percent of the claims paid. Two of the service guarantees, 8

“Missed Appointments” and “Timely and Accurate First Bill,” are addressed by the Customer Service 9

Operations Division and are described in Chapters III and IV of this Volume. The remaining two 10

standards are addressed by the Transmission and Distribution Operating Unit and are discussed in 11

Exhibit SCE-03, Volume 7. The 2012 recorded results for this program are shown in Table I-2 below. 12

Table I-2 SCE’s Service Guarantee Program

2012 Results Nominal $s

Line No.

StandardNumber of Activities

for each StandardClaims Paid

Performance Level

Dollars Paid

1 Missed Appointments 4,707 163 96.5% 4,890$ 2 Service Restoration (Within 24 Hrs.) 343,579 8,660 97.5% 259,800$ 3 Notification of Planned Outages 1,554,462 7,531 99.5% 225,930$ 4 Timely and Accurate 1st bill 1,131,601 5,887 99.5% 176,610$ 5 Totals 3,034,349 22,241 99.3% 667,230$

As shown in Table I-2 above, in 2012, SCE’s shareholders paid $0.67 million in service 13

guarantee claims, even though SCE’s performance in all four areas combined achieved a standard of 14

performance of 99.3 percent. The 22,241 claims that were paid represent less than one percent of the 15

more than three million service opportunities that would be eligible for payment if the standards were 16

not met. Because it is unreasonable to expect 100 percent success in the four service standards, the 17

service guarantee expense should be a normal operating expense when an extremely high quality 18

standard of performance is otherwise being met. 19

4 D.04-07-022, Ordering Paragraph No. 12, p. 346.

5 See Service Guarantee Program guidelines in D.04-07-022.

8

SCE has refined it service guarantee processes to minimize error, but the processes would be 1

unreasonably expensive if they were operated to be 100 percent without error. The Commission has, in 2

the past, stated its belief that service guarantees benefit all customers by providing SCE with the 3

incentive to meet its commitments to its customers.6 SCE agrees with this Commission conclusion. 4

Because all customers benefit from this added incentive, it is reasonable that a baseline level of the 5

service guarantee credits should be funded by all ratepayers as a normal cost of business, not by SCE’s 6

shareholders. 7

1. Historical Perspective 8

In adopting SCE’s Service Guarantee Program in the 2003 GRC, the Commission stated, 9

“Although we believe that SCE is currently providing satisfactory customer service overall, we feel that 10

customer service is a core element of utility service and thus wish to ensure there is no degradation to 11

SCE's current level of customer service.”7 In all GRC proceedings since that decision, SCE has 12

expressed its concerns about the program and the fact that the Commission expects the credits paid to 13

the customers must be charged to SCE’s shareholders, even though the Commission acknowledges that 14

SCE is providing an overall satisfactory level of customer service. Based on the level of Service 15

Guarantee credits over the last five years, SCE’s level of service remains high and has not deteriorated at 16

all since the program was initiated in 2004. 17

Despite being receptive to the concept of establishing a “baseline” level to be funded in 18

rates, the Commission found in SCE’s 2006 GRC that “[s]etting a baseline is difficult. It should be set 19

at a level that sets a reasonable stretch target for the company to meet….the record in this proceeding, 20

however, is insufficient to develop such a target.”8 At that time, SCE had only two partial years of 21

recorded data for use in establishing a reasonable baseline level. SCE now has nine years of recorded 22

results of the Service Guarantee Standards upon which to establish a reasonable baseline level of credits 23

to be included in rates. The program is fully operational and established as part of SCE’s “business as 24

usual operations.” 25

A base level of service credits funded through rates would still provide incentive for SCE 26

to meet or exceed the base level target because any amount paid above the base level would be paid by 27

6 D.06-05-016, Section 14.1. Service Guarantee Program, p. 122.

7 D.04-07-022, Section 4.5, pp. 163-164.

8 D.06-05-016, Section 14.1. Service Guarantee Program, p. 122.

9

shareholders. SCE proposes a baseline level of Service Guarantee Credits of $662,000 equal to the most 1

recent five-year average of credits paid for Service Guarantee standards for Missed Appointment and 2

Timely and Accurate First Bill combined with the Last Recorded Year amounts for Service Restoration 3

and Notification of Planned Outage as shown in Table I-3 below. 4

Table I-3 Service Guarantee Credits – Five Year Average

Nominal $s Five year Average

Line No.

ServiceStandard

Claims Paid

Dollars PaidClaims

PaidDollars

PaidClaims

PaidDollars Paid

Claims Paid

Dollars PaidClaims

PaidDollars Paid

Avg Claims

Avg Payments

1 Missed Appointment 388 11,640$ 336 10,080$ 277 8,310$ 235 7,050$ 163 4,890$ 280 8,400$

2Timely & Accurate First Bill 5,933 177,990$ 5,439 163,170$ 4,995 149,850$ 5,150 154,500$ 5,887 176,610$ 5,481 164,424$

324 Hour Service Restoration 3,834 115,020$ 14,714 441,420$ 8,263 247,890$ 8,071 242,130$ 8,660 259,800$ 8,708 261,240$

4Notification of Planned Outage 17,090 512,700$ 19,158 574,740$ 11,896 356,880$ 9,289 278,670$ 7,531 225,930$ 12,993 389,790$

5 Total 27,245 817,350$ 39,647 1,189,410$ 25,431 762,930$ 22,745 682,350$ 22,241 667,230$ 27,462 823,854$

2008 2009 2010 2011 2012

This baseline is a reasonable target in light of the significant increase in planned outages 5

to meet newly established distribution circuit maintenance standards and the fact that the last two 6

recorded year’s results were achieved in relatively mild weather conditions. 7

2. Service Guarantee Credits Included in 2015 Test-Year Forecast 8

SCE forecasts $662,000 for credits for the four types of service guarantee standards to be 9

funded in rates. Two of the Service Guarantees (Missed Appointments and Timely and Accurate First 10

Bill) are discussed further in Chapters III and IV of this Volume as a Policy Adjustment, and the five-11

year average cost of the credits paid for these two guarantees ($173,000) is included in FERC Account 12

903.500. The forecast is contained in Chapter IV of this Volume. The remaining two service guarantees 13

(Service Restoration (within 24 hours) and Planned Outage Notification) are discussed in Exhibit SCE-14

03 Volume 7, and the Last Recorded Year cost of the credits paid for those two guarantees ($486,000) 15

are included the FERC Account 587.170 forecast. 16

10

II. 1

SUMMARY OF REQUEST FOR CUSTOMER SERVICE OPERATIONS 2

This section describes the operating requirements of the Customer Service Operations function. 3

In 2012, SCE incurred $185.544 million of O&M expenses for this function. CSO is forecasting a total 4

2015 Test Year funding level of $195.534 million, which is summarized by FERC Account in Table II-4 5

below. The 2015 Test Year estimate is an increase of $9.990 million compared to 2012 recorded costs. 6

The Base Year recorded amount includes productivity improvements of $49.1 million, which are 7

summarized in Table I-1 above. The Test Year forecast includes Operational Excellence and other 8

productivity improvements of $19.5 million. The most significant items of the Test Year productivity 9

improvements are from the CCC ($3.7 million) and from MSO ($5.4 million). Descriptions of the 10

individual forecast increases are described in detail within this Volume. Table II-4 summarizes the Test 11

Year forecast by FERC Account. 12

Table II-4 Summary of O&M For Customer Service Operations

(Excluding Uncollectibles) (Constant 2012 $000s)

CSOD is also responsible for general Operating Unit capital expenditure requirements, such as 13

meters, specialized equipment, structures, and improvements. Chapter III-B of this Volume provides 14

more information about meters and specialize equipment, structures, and improvements. CSOD is also 15

highly impacted by the implementation of large-scale capitalized software projects. CS capitalized 16

software projects are discussed in Exhibit SCE-05, Volume 2. 17

11

Figure II-2 below provides a five-year history and three-year forecast for the operating expense 1

associated with CSOD in this Volume. 2

Figure II-2 Summary of O&M Forecast for Customer Service Operations

(Excluding Uncollectibles) (Constant 2012 $000s)

2008 2009 2010 2011 2012 2013 2014 2015Labor Expense 164,905 166,819 172,546 157,765 120,220 127,106 127,211 128,061Non-Labor Expense 83,844 84,861 85,103 80,536 64,667 73,384 70,399 66,862Other 544 526 238 224 657 438 438 611Total 249,293 252,206 257,887 238,525 185,544 200,928 198,048 195,534

Adjusted/Recorded Forecast

$0

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

2008 2009 2010 2011 2012 2013 2014 2015

Other Non‐Labor Expense Labor Expense |‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐Forecast ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐|

12

III. 1

METER SERVICES ORGANIZATION (MSO) 2

MSO performs meter reading/data collection; operates and maintains all of SCE’s metering 3

systems, including the ESC metering system, meter engineering, meter testing, meter maintenance, 4

meter installation and removal, field services; and manages and supports all meter-related activities 5

throughout the service territory. By the end of 2012, MSO had approximately 680 employees, a 52 6

percent reduction from the 1,430 MSO employees in 2009 (before the deployment of ESC). A further 7

reduction to approximately 600 employees is set to occur by 2015. MSO activities and staffing levels 8

have been significantly impacted by the new ESC metering system, as described in this Chapter. 9

In addition to ensuring the safety, accuracy, integrity, and reliability for nearly five million 10

electric meters, MSO responsibilities include the qualification and quality assurance of new metering 11

technologies, support for special projects and for regulatory-required actions, and compliance with 12

Commission-adopted standards for metering and meter data9 in accordance with Rule 22 in SCE’s Tariff 13

Book. Under MSO’s guidance, the ESC Operations Center (SOC) oversees the ongoing operations of 14

the ESC metering and communication systems. MSO personnel also provide field, credit, and collection 15

activities and revenue protection services to deter energy theft and other unaccounted-for energy losses. 16

MSO workload is driven by increasing customer populations, customer mobility, the expanded role of 17

metering as the backbone of the Smart Grid, support of new rates, demand response programs, growth of 18

Home Area Networks (HAN) that communicate with the meter, and the increased complexity of new 19

metering products. 20

MSO’s Metering Services, Engineering, and SOC all function together to provide a state-of-the-21

art metering and communications system. These systems enable customer participation in ESC and 22

Smart Grid-enabled programs and services. As discussed in Volume 1 of this Exhibit, ESC technology 23

and implementation of other major software projects provide a foundation for SCE’s Customer Service 24

Model aimed at fostering customer engagement in all aspects of the energy delivery process. For MSO, 25

essential capitalized software projects include Cell Relay Replacement, Hiperwall Refresh, Integrated 26

Work Management System, and ESC Monitoring and Analysis System (SCMAS) Phase 2. The details 27

and forecast information for these capitalized software projects are provided in Exhibit SCE-05, Volume 28

2, Part 1. 29

9 See D.98-12-080 (Commission adopts Direct Access Standards for Metering and Meter Data (DASMMD)).

13

A. Meter Services Organization Functions 1

The organizational functions within MSO consist of Meter Reading/Data Collection, ESC 2

Operations Center (SOC), Electrical Metering Services, Engineering and Meter Shop, Field Services, CS 3

Safety, and Operations and Management. These groups are described individually in the sections that 4

follow. MSO O&M expenses are recorded to five FERC Accounts: 902, 586.400, 586.100, 587, and 5

580. 6

As previously discussed, with the deployment of the ESC systems, meter service functions are 7

completing the transition from manual meter reading and manual service activation/deactivation to 8

automated meter reading/data collection and remote service activation and deactivation. 9

1. Meter Reading Operations [FERC Account 902] 10

The primary Meter Reading/Data Collection function is to collect and record meter-usage 11

data needed to bill customers and needed for their participation in energy management programs and 12

services. SCE has nearly five million meters throughout SCE’s 50,000 square mile service territory that 13

are now mostly read over-the-air using the ESC system. Timely and accurate reading of meters is 14

essential for on-time and accurate billing. 15

a) Description of Meter Reading Function 16

At the end of 2012, 98 percent of SCE’s meters were being read automatically by 17

the ESC system. The level of automated meter reading/data collection is expected to increase to 99 18

percent by 2015. However, it is expected that manual meter reading/data collection will continue to be 19

required for approximately one percent, or about 52,500, of SCE’s meters because of connectivity issues 20

and customers who elect to opt out of the ESC program. As part of the ESC program, MSO worked 21

with the International Brotherhood of Electrical Workers union to eliminate the meter reading job 22

classification by 2013. Manual meter reads and data collection are now completed by Field Service 23

Representatives (FSRs) as part of their field service activities. 24

(1) Automated Meter Reading – ESC Operations Center (SOC) 25

Day-to-day operation of the automated meter reading/data collection 26

function is performed by SOC. As discussed in Chapter I of this Volume, the operations of the SOC 27

support the Intelligent Delivery component of SCE’s Customer Service Model. The ESC system 28

automatically reads residential meters at one-hour intervals and non-residential meters at 15-minute 29

intervals. The metered interval usage data is accessed and downloaded daily, seven days a week. SOC 30

plans, monitors, operates, and maintains the ESC meter and communications system to meet business 31

14

objectives. The ESC meter and communication system includes the Network Management System 1

(NMS), the Communications Network System, Cell Relays, meters, the HAN interface, and various 2

associated operational and reporting systems. SOC personnel perform oversight responsibilities through 3

a dedicated multi-disciplinary team that has in-depth business and technical knowledge. SOC is a 4

dynamic organization, continuously capturing events and scenarios, and applies that knowledge to drive 5

operational changes that deliver improved business results. SOC focuses on the three key areas 6

summarized as follows: 7

(a) Monitor and Manage “Over-the-Air” (OTA) Operations 8

SOC continuously and proactively monitors the end-to-end ESC 9

OTA operations, including remote service switch (RSS) operations, demand response actions, firmware 10

downloads, and configuration changes. SOC provides day-to-day device, network, security and 11

infrastructure monitoring and status reporting. SOC manages and directs the detection, investigation, 12

remediation, communication, and coordination of operational events and supports all related business 13

activity. 14

(b) Operations Optimization, Triage and Trouble Analysis 15

SOC maximizes efficiency and reliability of the ESC system by 16

employing analytics, end-to-end diagnostics and analysis, specific and overall process improvement, and 17

systems enhancements. SOC drives integrated trouble triage analysis and root-cause investigations and 18

manages a dynamic knowledge base for the ESC system through the capture of events and scenarios. 19

SOC develops network optimization and performance trending, conducts long-term scenario analyses, 20

works with the Planning and Service Support teams and stakeholders, and continuously applies new 21

knowledge to drive operational improvements. 22

(c) Planning and Service Support 23

Planning and Service Support communicates, coordinates, and 24

manages changes to systems, processes, and applications associated with ESC OTA operations (e.g., 25

NMS, Communications Networks, Cell Relays, Meters, and HAN support). The Planning and Service 26

Support group also provides long-term planning and scheduling, release and configuration management, 27

quality control, vendor coordination, and contract management. 28

(2) Manual Meter Reading Function 29

Although the task of reading meters manually will be eliminated for 99 30

percent of SCE’s almost five million meters by 2015, approximately 52,500 meters will continue to be 31

15

read manually each month. There are two primary reasons why these meters must be read manually: 1

(1) approximately 25,000 meters are located in areas or within facilities where direct connectivity to 2

ESC communications systems is difficult or impractical, and (2) approximately 27,500 customers will 3

opt out of ESC services and service will continue to be metered by legacy-type electromechanical 4

meters that require monthly manual meter reads. These remaining manually read meters are spread out 5

over SCE’s 50,000-square-mile service area, requiring considerable drive-time between meters to obtain 6

routine monthly meter reads. 7

With full deployment of the ESC system, all meter reader positions have 8

been eliminated. Manual meter reading/data collection is now performed by FSRs. Where feasible, 9

MSO continues to use established meter reading routes, allowing as many meters as possible to be 10

aggregated into daily routes. Before ESC, a single meter reader was able to read 500 meters on average 11

per day going premises to premises. Now, the manual meter reading/data collection is performed in 12

dispersed locations by FSRs, who will each be reading an average of 37 meters per day by 2015 in 13

conjunction with performing other field activities. 14

(3) Real-Time Energy Meter Function 15

SCE currently has approximately 18,000 Real-Time Energy Meters 16

(RTEM) installed on its largest commercial and industrial accounts. Fifteen-minute interval usage data 17

is automatically collected on a daily basis and day-after usage data is made available to these customers 18

through the Internet. Unlike ESC meters, which process data through the Meter Data Management 19

System (MDMS), RTEM-metered data is processed daily through SCE’s Customer Data Acquisition 20

System (CDAS), in which validations are applied and usage data is routed to the billing system to 21

prepare monthly bills. SCE has been replacing older technology “pager” and phone line communicating 22

meters with more modern radio-frequency (RF) communications technology. As of December 2012, 23

there were only 70 pager and 782 phone line communicating meters remaining among SCE’s RTEM-24

metered accounts. 25

b) Operating Results 26

A significant economic benefit achieved with the ESC system deployment is the 27

overall cost reduction of reading nearly five million meters. Prior to deployment of the ESC system, the 28

cost of reading meters, on a per-meter-read basis, had remained fairly steady and was $0.83 per read in 29

2009. SCE’s automated and manual meter reading costs and the resultant cost per read are summarized 30

in Table III-5 below. 31

16

Table III-5 Meter Reading Cost Per Read

Prior to and Post ESC (2008-2015) (Constant 2012 $000s)

Line No. Manual Data 2008 2009 2010 2011 2012 2013 2014 2015*

1

FTEs - Historical MR- Forecast FSR 690 692 427 350 296 90 65 64

2

Manual Legacy Meter Reading Costs $50,550 $48,874 $42,063 $27,996 $16,722 $8,797 $8,459 $9,372

3 Manual Legacy Meters Read 58,605,877 58,675,433 45,941,252 25,945,136 6,504,129 780,000 540,000 630,000

4

Manual Legacy Metering Costs per Read 0.86$ 0.83$ 0.92$ 1.08$ 2.57$ 11.28$ 15.66$ 14.88$

5 SOC Costs N/A $12 $2,185 $4,204 $4,143 $8,280 $8,964 $9,883

6 Automated Reads _5 N/A 0 14,938,222 32,413,129 53,129,284 59,100,000 60,360,000 61,800,000

7

Automated Metering Costs Per Read N/A N/A 0.15$ 0.13$ 0.08$ 0.14$ 0.15$ 0.16$

8

Total Manual and Auotmated Meter Reading Costs $50,550 $48,886 $44,248 $32,200 $20,865 $17,077 $17,423 $19,255

9

Total Manual and Auotomated reads 58,605,877 58,675,433 60,879,474 58,358,265 59,633,413 59,880,000 60,900,000 62,430,000

10 Total Cost per Read 0.86$ 0.83$ 0.73$ 0.55$ 0.35$ 0.29$ 0.29$ 0.31$

* In 2015 costs and volume of meters read include opt out customers. (The opt out data is not included in 2013/2014 as it is placed in a memo account)

Historical Forecast

By 2015, the blended cost to read all meters (both manual and automated) is 1

expected to be $0.31 per read – an overall savings of approximately $31.3 million per year as measured 2

in total costs in 2015 compared to total cost in 2008. SCE achieves this cost reduction while 3

concurrently providing hourly interval energy usage data for 99 percent of all residential customers and 4

15-minute interval usage data for small and medium non-residential customers. 5

For approximately 52,500 remaining manually read meters, monthly manual 6

meter reading costs, including management, supervision, and support costs, are expected to average 7

approximately $780,000 per month or $14.88 per read.10 Approximately half of these manual meter 8

reading costs are attributed to customers who have opted out of the ESC program and who have agreed 9

to pay for their meter reading and other related opt-out costs through the proposed Opt-Out Service 10

10 See Table III-5, Manual Metering Cost per Read, Lines 2-4. $9,372,000÷ 630,000 reads = $14.88 per read. This amount

represents the Meter Reading portion of the Other Operating Revenue (OOR) Service Charge of $22 per month for Opt-Out, as discussed in Chapter X of this Volume.

17

Charge of $22 per month.11 The Opt-Out Service Charge is accounted for as Other Operating Revenue 1

(OOR) and is discussed in Chapter X of this Volume. 2

c) Analysis of Historical Data – Meter Reading FERC Account 902 3

The recorded/adjusted costs for meter reading and metered data collection 4

activities are shown in Table III-6 and were derived after analyzing recorded costs for this activity and 5

adjusted to reflect ongoing business. The various accounting, operational, and reclassification 6

adjustments to the historical costs are discussed in the workpapers supporting this Volume. In addition, 7

the company-wide adjustments are discussed in Exhibit SCE-10, Results of Operations testimony. 8

Table III-6 Meter Reading

2008-2012 Recorded and Adjusted Expenses FERC Account 902

(Constant 2012 $000)

Line No. Description 2008 2009 2010 2011 2012 1 Labor Expense 38,047 38,557 35,001 24,895 9,787

2 Non-Labor Expense 12,503 10,329 9,247 7,305 3,433

3 Other - - - - -

4 Total Operation Expense 50,550 48,886 44,248 32,200 13,220

Two key adjustments were made to Meter Reading 2012 Base Year cost to reflect 9

ongoing operations with the ESC metering system fully deployed at year end 2012: (1) removal of non-10

recurring legacy costs equal to $7.645 million and (2) addition of ongoing steady-state automated meter 11

reading costs of $4.143 million recorded by SOC in the ESC Balancing Account (ESCBA). These key 12

adjustments are discussed below. In addition, $780,215 of Opt-Out Program direct costs are included in 13

the 2012 Base Year recorded cost. 14

(1) Removal of Non-Recurring Legacy Meter Reading Costs 15

During deployment of the ESC system from 2009 through 2012, manual 16

meter reading/data collection has gradually been replaced by automated meter reading/data collection at 17

the ongoing steady-state SOC automated meter reading cost. Table III-7 below shows the automated 18

11 The proposed Opt-Out Service Charge for CARE customers is $17 per month.

18

meter reading volumes in the first three years of operation from 2010 through 2012. For tracking 1

purposes, one full month of daily ESC meter reads is counted as one “meter-read month.” In 2012, 2

automated Meter Reading reached an average of 89 percent of the total 59.6 million meter reads 3

obtained for that year. 4

Table III-7 Percent of Automated Meter Reading Operations

2008 – 2012

Line No. Description 2008 2009 2010 2011 2012

1 Number of ESC System Meter-read Months* 0 0 14,938,222 32,413,129 53,129,284

2

Average Automated Meter Reading

N/A N/A 25% 56% 89%

*An ESC meter read month equals all daily reads in that month.

During the deployment of ESC from 2009-2012, manual meter reading 5

costs were incurred for the meters that were not being automatically read by SOC. For the recorded 6

2012 Base Year, approximately 75.6 percent of the expected $31.3 million reduction (or $23.653 7

million) in manual metering costs had already been achieved. The remaining 24.4 percent of the overall 8

benefit (or $7.645 million) will be achieved prior to the 2015 Test Year; most of this remaining benefit 9

will be achieved in 2013. These manual meter reading costs are considered nonrecurring and will not be 10

forecast for the 2015 Test Year. A downward adjustment of $7.645 million was made to remove the 11

remaining 24.4 percent of approximately $31.3 million in total potential reduction that could be 12

expected to result from the ESC system in 2012 under full steady-state operations. 13

(2) Addition of Ongoing Steady-State Automated Meter Reading Costs 14

For 2012, ongoing steady-state SOC costs were recorded in the ESCBA, 15

as required by D.08-09-039. Thus, an adjustment was required to appropriately include these recorded 16

costs for the steady-state meter reading operations in the 2012 Base Year. An adjustment of $4.143 17

million was added to the historical costs for 2012, representing 79 percent of the $5.24 million in costs 18

that were recorded by SOC in the ESCBA in 2012. It should be noted that, during the ESC deployment 19

period, much of the SOC activities were devoted to getting the communication systems to function at a 20

19

stable level; thus, the portion of SOC costs that were considered to be “steady-state” during these years 1

was somewhat less than the proportionate number of meters that were being read. 2

(3) Historical Year-to-Year Variances 3

As shown in Table III-6 above, labor expenses dropped significantly 4

during 2008 to 2012 as ESC automated meter reading operations went from zero in 2008 to an average 5

of 89 percent operational in 2012. For the same reason, non-labor expenses declined during this period 6

because of reduction of meter reading vehicle costs. As shown in Table III-5 above in line 8, the ESC 7

savings for the meter reading/data collection activity (comparing 2008 to 2015) total approximately 8

$31.3 million, and they represent the single largest economic benefit of the ESC system. However, the 9

interval usage data obtained by meter reading must then be processed through the Meter Data 10

Management System (MDMS), which requires a whole new operational process for billing operations 11

that is labor-intensive and will cost approximately $5.6 million in the 2015 Test Year. The incremental 12

cost of the MDMS process adds the equivalent of approximately nine cents per read on average to the 13

overall cost of obtaining the consumption data needed to bill the customer. The cost of the MDMS 14

operations is recorded in Billing (FERC Account 903.500) and is discussed in the Revenue Services 15

Organization (RSO) costs in Chapter IV of this Volume. 16

d) Test Year Operation Expectations FERC Account 902 17

Figure III-3 shows the recorded/adjusted historical and forecast expenses for the 18

Meter Reading/Data Collection function. Details regarding the forecast O&M expenses for this function 19

are described below. 20

20

Figure III-3 Meter Reading

FERC Account 902 (Constant 2012 $000s)

The following sections describe the adjustments that were necessary in order to 1

forecast future expense levels. 2

(1) Determination of Test Year Estimating Method 3

Because of the impact ESC has had on meter reading/data collection, 4

operating costs incurred prior to 2012 are not representative of future expectations and thus are not 5

suitable to support the use of historical averages or trends to forecast future costs. Instead, the Last 6

Recorded Year with the previously mentioned adjustments was used as the base, to which future year 7

cost adjustments were added or subtracted for cost increases and decreases expected to be incurred in the 8

Test Year. 9

(2) Test Year Adjustments 10

Figure III-4 below illustrates the Test Year forecast and adjustments for 11

FERC Account 902 as compared to the Base Year. Discussion on each forecast adjustment component 12

follows. 13

21

Figure III-4 Meter Reading

Comparison of 2012 Base Year to 2015 Test Year FERC Account 902

(Constant 2012 $000s)

(a) ESC Steady State Costs in 2015 Test Year 1

As discussed in the Analysis of Historical Data section above, the 2

2012 Base Year meter reading/data collection expenses included $4.143 million of steady-state cost 3

recorded in the ESCBA in 2012. However, the total SOC costs incurred in 2012 were only 42 percent of 4

the $9.883 million in ongoing steady-state SOC expenses forecast for the 2015 Test Year that is needed 5

to achieve a level of 99 percent automated meter reading by 2015. Thus, a Test Year adjustment of 6

22

$5.740 million ($9.883-$4.143 million) was made to account for the ongoing full steady-state SOC 1

operations in 2015. 2

(b) Customer Growth 3

The number of customers served in SCE’s service territory is 4

forecast to increase by 2.06 percent during 2012 to 2015. SOC and the remaining manual meter 5

reading/data collection operations are directly impacted by customer growth as more meters continue to 6

be added, creating additional routine operational work and increased SOC communications costs. While 7

meeting this added workload, the meter reading/data collection operations group expects to continue 8

maintaining high performance with timely and accurate meter reading/data collection. To reflect the 9

impact that this increase in the volume of meter reading activities will have on cost, an adjustment of 10

$273,000 (2.06 percent) was made to 2012 Base Year adjusted/recorded costs. 11

(c) Program Changes 12

(i) Opt-Out Program 13

The Commission has authorized customers to opt out of the 14

ESC program pursuant to D.12-04-018. As a result of this Opt-Out Decision, SCE forecast 15

approximately 27,500 customers will participate in the Opt-Out Program by 2015. The number of 16

customers participating in the Opt-Out Program by the end of 2012 was approximately 21,300. The 17

increase in Opt-Out Program participation by 6,200 customers (from 21,300 customers to 27,500 18

customers) will require incremental manual meter reading costs above the 2012 Base Year. An 19

adjustment of $1.146 million was made to reflect these incremental added costs, which will be recovered 20

from the customers participating in this program through proposed ESC Opt-Out fees as discussed in 21

Chapter X-Other Operating Revenue of this Volume. 22

(d) Operational Excellence 23

MSO has identified cost savings in the Meter Reading/Data 24

Collection function through Operational Excellence initiatives. By 2015, MSO forecasts a $1.123 25

million savings through lower staffing levels for supervisors, support specialists, and other positions. 26

This reduction is equal to about 17 full-time equivalent employees. 27

23

2. Test, Inspect and Repair Meters [FERC Account 586.400] 1

a) Description of the Test, Inspect and Repair Meters Function 2

The Test, Inspect and Repair Meters function includes SCE’s Electrical Metering 3

Services (EMS), Engineering and Meter Shop operations, and the field maintenance and repair of 4

electric billing and load survey meters. These functions are described in the following sections. 5

(1) Description of the Electrical Metering Services (EMS) Function 6

EMS ensures the accuracy and integrity of SCE’s metering systems, 7

including the in-service performance and quality of metering products. EMS administers the required 8

meter test and meter maintenance programs to ensure the accuracy of SCE’s metering population, 9

including meters for Direct Access (DA) customers, where SCE is the Meter Service Provider. EMS 10

also performs the initial installation of meters and installation of associated metering equipment on 11

complex metering installations. Meter technicians are organized into decentralized groups supporting 12

34 districts throughout SCE’s service territory. Supervisory, management, and administrative staff 13

personnel provide direction and support. Additionally, technical specialists maintain the work 14

distribution, collect meter order data to establish quality controls, and ensure the accuracy of the 15

information systems. The greatest volume of work arises from meter accuracy testing, which is divided 16

into (a) sample and routine tests, (b) request tests, and (c) installation tests. 17

(a) Sample and Routine Tests 18

The sample and routine test program as defined by SCE’s Rule 22, 19

Part G requires, “All meters and meter services must conform to the standards set forth in the Direct 20

Access Standards for Metering and Meter Data (‘DASMMD’) as approved by the CPUC.”12 SCE’s 21

sample and routine test function pursuant to the DASMMD consists of four testing programs: (1) annual 22

testing of meters with annual usage of two million kWh or more, (2) biennial testing of meters with 23

annual usage between 720,000 kWh and two million kWh, (3) random sample testing of non-residential 24

meters with annual usage less than 720,000 kWh, and (4) random sample testing of residential meters. 25

(b) Request Tests 26

Request tests for meters come from customers, Field Services 27

personnel, and the Billing Group (billing inquiries). Customers may question the accuracy of their 28

meter and request a test under the provisions of SCE’s Rule 17. A meter test may also be requested by 29

12 The CPUC established DASMMD standards in D.98-12-080.

24

the Commission, generally in response to a billing inquiry. Field Services personnel observe conditions 1

in the field, such as meter damage, that require a meter test to determine if the meter is registering usage 2

accurately and/or if it is in need of repair. When meter accuracy is found to be outside of established 3

tolerance limits, the Billing Group is provided with test results upon which billing corrections are based. 4

(c) Installation Tests 5

EMS performs meter installation tests in the field on all complex 6

metering services following meter replacement and for new services in order to ensure a safe and 7

accurate installation under Rule 17. Even though SCE tests all commercial and industrial meters in the 8

Meter Shop upon receipt from the supplier, the field installation tests are used to identify potential 9

service wiring problem conditions and/or meter programming errors that could result in unsafe 10

conditions or inaccurate billing. 11

(2) Description of the Engineering and Meter Shop Functions 12

The Engineering and Meter Shop functions are comprised of engineers, 13

technical specialists, meter technicians, project managers, and management and administrative support 14

personnel. The Engineering and Meter Shop are responsible for metering strategy, meter technical 15

specification and selection, meter deployment support, and the reliability and quality of all metering 16

products used on the SCE system. 17

(a) Engineering Products and Operations 18

Engineering Products and Engineering Operations activities are 19

primarily influenced by customer population growth, customer metering load requirements, meter 20

failure and communication issues, introduction of new meter technology, and customer participation in 21

demand response (DR) programs. Engineering personnel design all complex metering jobs for the field 22

meter technicians. On an average annual basis during 2008-2012, approximately 26,000 complex 23

metering jobs were completed each year. These jobs include all Interval Data Recorder (IDR) 24

installations required for accounts over 200 kW; Direct Access; complex ESC installations; Net Energy 25

Metering; and compensated metering installations on large accounts where, for customer convenience, 26

the meter is located some distance from the delivery point, and the metering system includes a 27

compensation adjustment for line losses incurred between the delivery point and the meter. 28

The group analyzes trouble reports generated by the Billing 29

organization and SOC to determine the root cause, identify material needed for replacement, and provide 30

replacement information to the field meter technician who performs the replacement. Trouble reports 31

25

are also issued for communication problems on phone, paging, and radio frequency communicating 1

devices. Personnel perform analysis at the account level to determine root cause, establish corrective 2

action and engineering design to ensure that appropriate metering and associated equipment is available 3

and installed as required. 4

SCE’s metering engineers work with manufacturers to evaluate 5

new metering products to meet SCE’s customer and regulatory driven needs. SCE’s metering engineers 6

develop and continuously review SCE’s metering technical specifications to ensure the latest industry 7

standards are incorporated. SCE’s metering engineers also perform product qualification testing of all 8

new metering products to be used on SCE’s system by performing American National Standards 9

Institute (ANSI) Standard Laboratory testing. 10

(b) Meter Shop 11

The Meter Shop is responsible for testing meters as they are 12

received from suppliers and for regularly managing the warranties and maintenance on meters returned 13

by field personnel. Before the meter product is delivered to the field, quality control testing is 14

performed in the Meter Shop to ensure that the meter product is safe, accurate, and capable of delivering 15

the required functionality. The Meter Shop also monitors meters returned from the field and conducts 16

root-cause analysis of field meter failures. 17

Meter Shop personnel test meters for acceptance into the SCE 18

system by sample testing new residential meters and inspecting refurbished meters returned from the 19

vendor that are covered under warranty. The Meter Shop also tests all non-residential meters before 20

accepting the meters for use. Meter Shop personnel conduct root-cause analysis of field meter failures 21

to maintain the safety, reliability, and data integrity of the meters in the field, and they work with 22

manufacturers on meter product issues, including quality and functionality improvements. 23

(3) Description of Field Maintenance and Repair of Electric Meters 24

Field maintenance and repair meter tests include electrical service 25

verifications to ensure the overall integrity of the installation by verifying that the service voltage and 26

wiring are correct. Meter technicians use a variety of instruments, such as watt-hour standards, digital 27

multi-meters, phase angle meters, and current transformer burden test sets to ensure that the service is 28

correct and the meter is measuring kWh consumption accurately. Performing appropriate measurements 29

and inspections ensures that the service is being metered correctly, so customers can be billed 30

accurately. The conversion of nearly all of SCE’s meters to two-way communication functionality has 31

26

added a degree of technical sophistication to the role of the meter technician. This requires the meter 1

technician to take additional steps, not only to verify meter accuracy, but also to verify two-way 2

communication and troubleshoot communication issues to ensure dependable performance. 3

Meter technicians also perform non-test work to the meter and panel, 4

including service wiring, interval read verifications, installation of relay equipment, and communication 5

checks and site assessments to determine if coverage is available prior to installing radio communication 6

meters. Since 2008, EMS has completed on average over 10,000 non-test jobs related to non-test work 7

annually. 8


(1) Operating Results - EMS 10

As discussed previously, the normal routine of meter testing and 11

inspection schedules has been disrupted over the last three years by deployment of the ESC metering 12

program. The following tables present the meter test and inspection operating results for sample and 13

routine tests, request tests, and installation tests, as well as the forecast volumes. In addition, tests for 14

2008-2012 have a separate line item for ESC program related tests, which began in 2010. Table III-8 15

below shows the number of meter tests and inspections performed from 2008 through 2012. 16

Table III-8 Meter Test and Inspection

2008–2012

Line No.

Description 2008 2009 2010 2011 2012

1 Sample and Routine 7,130 12,843 12,488 9,398 5,664 2 Non-OTA Request Tests 43,161 55,410 43,122 36,838 29,504 3 Installation 38,774 34,311 14,185 9,658 7,221 4 Sub-total Legacy 89,065 102,564 69,795 55,894 42,389 5 ESC OTA Request Tests N/A N/A 497 5,921 37,936 6 Total 89,065 102,564 70,292 61,815 80,325

Table III-9 below shows the number of sample, request, and installation 17

tests forecast for 2013-2015. 18

27

Table III-9 Forecast Meter Test and Inspection

2013-2015

Line No.

Description 2013 2014 2015

1 Sample and Routine 18,000 18,000 18,000 2 Non OTA Request Tests 24,000 24,000 24,000 3 ESC OTA Request Tests 55,000 50,000 45,000

4 Installation 23,000 19,000 19,000

5 Total 120,000 111,000 106,000

(a) Sample and Routine Meter Tests 1

In 2008 and 2009, sample testing was less than average due to the 2

replacement of approximately 8,300 communicating meters in the Real Time Energy Metering (RTEM) 3

program. In 2009 and 2010, testing volume was limited to only annual tests for SCE’s largest 4

customers. By the end of 2010, complex ESC meters became available, and meter technicians were 5

utilized for deployment of ESC meters and also charged their costs to the ESCBA. As new meters were 6

being installed, the routine and sample testing schedules for these large accounts were deferred in 2011 7

and 2012. This reduced sample test volume was recognized in the ESC business case as a temporary 8

benefit. 9

(b) Request Tests 10

The 2008-2010 customer rate increases associated with the Tier 11

4/5 billing rate structure generated additional billing inquiries at customer requests. Also, in 2009, 12

request test volume increased as approximately 5,500 pager meters were replaced because of battery 13

failures or communication reliability concerns. In 2010, the volume of request testing returned to 14

normal state, and efforts were shifted toward ESC deployment. In 2011 and 2012, a decrease in request 15

tests was replaced by ESC OTA testing, which has now become “business as usual” work. Most of the 16

ESC OTA request tests were internal requests related to communication irregularities that required a 17

meter technician to conduct certain diagnostic tests at the meter location. ESC request testing is now 18

part of normal operations and consists of request tests and OTA tests. As the ESC system approaches 19

steady state operationally, the sample and routine and non-OTA request testing volumes are expected to 20

return to a stable level similar to the years prior to ESC deployment. The main difference with regard to 21

28

future meter test and inspect activities is the introduction of the two-way radio communications issues 1

that will continue to impact this activity. 2

(c) ESC OTA Request Tests and Inspections 3

With the introduction of OTA-communicating ESC meters, several 4

new categories of tests and inspections have been created. MSO is experiencing five different types of 5

Test and Inspection orders that fall into the ESC OTA category. These request tests can be generated by 6

MSO Engineering, RSO, or SOC. They include: 7

1. Firmware13 push failure: Occurs when a mass firmware push 8

is initiated, and some meters’ firmware fails to update. 9

2. Configuration failure: Occurs when existing programming of 10

a meter fails. 11

3. Time sync failure: Occurs when the internal clock in the 12

meter is turned off. 13

4. OTA disconnect: Occurs when a RSS disconnect order is 14

sent OTA, and the meter fails to disconnect the customer’s 15

service. 16

5. OTA billing read: Occurs when the meter fails to 17

communicate and produce a read. 18

(2) Operating Results - Engineering and Meter Shop 19

Table III-10 below shows the number of Meter Shop tests performed each 20

year from 2008 -2012, as well as the forecast through 2015.14 21

13 Firmware is coded instructions that work with the meter’s computing chip-set to define functionality. In the ESC meter,

Firmware can be changed (pushed out) to fix functionality defects or to add new functionality within the computing chip sets limits.

14 Costs for the ESC tests were recorded in the ESCBA from 2009-2012.

29

Table III-10 Meter Shop Tests

2008 – 2015

As ESC meters were purchased and installed beginning in 2009, the volume of 1

non-ESC meter acceptance testing decreased in the Meter Shop each year through 2012. Prior to 2013, 2

testing ESC meters was part of ESC deployment and was charged accordingly to the ESCBA. This 3

change became more evident each year and culminated in 2012, when approximately 98 percent of all 4

meters tested in the meter shop were ESC meters. Beginning in 2013, this activity became “business as 5

usual,” and the costs are no longer recorded in the ESCBA. 6

c) Analysis of Historical Data 7

The recorded/adjusted costs for Test, Inspect and Repair Meters activities are 8

shown in Table III-11 below and were derived after analyzing the recorded costs and adjusted to reflect 9

ongoing operations. 10

Table III-11 Test, Inspect and Repair Meters

2008-2012 Recorded and Adjusted Expenses FERC Account 586.400 (Constant 2012 $000s)

Line No. Description 2008 2009 2010 2011 2012 1 Labor Expense 8,627 9,455 11,573 10,722 10,414 2 Non-Labor Expense 3,897 3,428 4,232 3,040 3,069 3 Other 0 0 0 0 0 4 Total Operating Expense 12,524 12,883 15,805 13,762 13,483

Although there was a reduced number of routine and sample testing that took 11

place during the deployment of the ESC meters from 2010-2012, overall costs increased in 2010 because 12

of inefficiencies caused by the deployment of ESC meters and because MSO implemented the Personal 13

30

Qualification Standard Program (PQS). This program is designed to increase safety and standardization 1

for our Meter Technicians. In 2011 and 2012, labor costs decreased due to the reduction of routine and 2

sample testing schedules as a high volume of meter replacements for the new ESC system was being 3

installed. During this period, some Meter Technicians were allocated to assist with ESC Deployment 4

and charged to the ESCBA. As will be discussed in the forecast section below, this decline in routine 5

and sample testing was a one-time occurrence. The decline has ended with the completion of ESC 6

deployment in December 2012, along with the resumption of the normal sample and routine testing 7

programs in 2013, as well as the additional ESC request tests. 8

In 2009, non-labor expense decreased primarily because of reduction in fuel and 9

overhead costs to repair and maintain vehicles. Non-labor expense increased in 2010 primarily because 10

of higher vehicle expense associated with increased vehicle lease buyouts, which occur on an as-needed 11

basis. Non-labor expense in 2011 decreased because of lower contractor costs, lower lodging and 12

mileage costs, lower vehicle maintenance, and fewer lease buyout costs. 13

The costs shown for the 2012 Base Year include an upward adjustment of 14

$745,000 for ESC ongoing steady-state meter request testing and inspection cost, which was 100 percent 15

of the cost that was recorded to the ESCBA in 2012 for this function. In addition, $169,000 of the 2012 16

Base Year cost for this account was for the incremental cost of the ESC Opt-Out program. 17

d) Test Year Operating Expectations FERC Account 586.400 18


Test, Inspect, and Repair Meters function. 20

31

Figure III-5 Test, Inspect and Repair Meters

FERC Account 586.400 (Constant 2012 $000s)




Because of the impact ESC has had on testing, inspecting, and repairing 4

meters, operating costs incurred before 2012 are not representative of future expectations and thus are 5

not suitable to support the use of historical averages or trends to forecast future costs. Instead, recorded 6

and adjusted O&M costs for 2012, as described previously, were used as the base, to which cost 7

adjustments were added or subtracted for future year cost increases and decreases to forecast the Test 8

Year. 9


Figure III-6 shows the Test Year forecast adjustments for FERC Account 11

586.400 compared to the Base Year. Discussion on each forecast adjustment component follows. 12

32

Figure III-6 Test, Inspect and Repair Meters

Comparison of 2012 Base Year to 2015 Test Year FERC Account 586.400 (Constant 2012 $000s)

(a) ESC Steady State Costs 1

To reflect the ongoing ESC meter test, inspect, and repair costs as 2

steady-state operations occur from 2013 through 2015, an adjustment of $2.831 million was made to the 3

2015 Test Year forecast. With the completion of ESC deployment, technicians now perform ongoing 4

steady state work, as well as newly added work generated by the ESC metering system. 5



expected to increase by 2.06 percent from 2012 to 2015. The test, inspect, repair, and meter 8

33

maintenance functions are directly impacted by customer growth as more meters continue to be added, 1

increasing workload and associated costs. To reflect the increased work that customer growth will cause 2

in the volume of meter tests, inspections, and repair activities, an adjustment of $278,000 (2.06 percent) 3

was made to the 2012 Base Year adjusted/recorded costs. 4

(c) Program Changes 5

ESC Warranty O&M Accounting 6

With nearly five million new meters in service, most meter 7

replacement costs are now covered under the manufacturer’s warranty. As a result, most meters 8

requiring replacement are returned to the manufacturer, where they are repaired under warranty, and sent 9

back to SCE. SCE does acceptance testing on 50 percent of these repaired and returned meters. 10

Because these meters have already been capitalized, the cost of these return acceptance tests is 11

accounted for as O&M. Historically, the cost of Meter Shop acceptance testing was charged to meter 12

capital because most meter acceptance testing was completed on new (as opposed to used) product. To 13

reflect the added O&M costs of performing warranty meter acceptance testing, an adjustment of $1.263 14

million was made to the 2015 Test Year forecast. 15

(d) Operational Excellence (Test and Inspect) 16

Through the Operational Excellence initiatives, MSO has 17

identified potential cost savings by consolidating management and supervisory positions, as well as 18

technical specialists, engineering, administrative, and analytical support personnel throughout all of its 19

functional areas and in 26 field locations. The portion of this productivity savings that is allocated to 20

meter Test and Inspection Activities results in reduced costs in the 2015 Test Year of $1.183 million 21

This is equal to about 14 Full Time Equivalent (FTE) personnel 22

3. Turn-On and Turn-Off Services [FERC 586.100] 23

a) Description of Turn-On and Turn-Off Services 24

One of the key functions of Field Services Operations is customer Turn-On and 25

Turn-Off requests for electric service. With the deployment of the ESC system, approximately 98 26

percent of residential and small commercial customers’ meters will have the functional capability to be 27

energized or de-energized through the Remote Service Switch (RSS). The RSS functionality is expected 28

to have a success rate of 96 percent. The remaining percentage will be turned on and off manually using 29

field resources. Customer-requested Turn-On and Turn-Off services are accounted for in FERC 30

Account 586.100, the cost analysis and Test Year forecast for which will be addressed in this section. 31

34

Functions similar to Turn-On and Turn-Off services are the field service 1

disconnects and reconnects resulting from the credit and collection activities directed by the Revenue 2

Services Organization (RSO). Field collection orders are important to the revenue stream and include 3

the in-person delivery of final call notices to critical care, elderly, and disabled customers. Field 4

collection orders relate to service disconnection for nonpayment, verification that previously 5

disconnected service remains turned off, and service reconnection once payment has been made. The 6

expense for field collection activity is recorded in the Credit and Payment Service FERC Account 7

903.200.15 8

FSRs receive dispatched field orders on a daily basis that are downloaded into 9

assigned FSR wireless laptop computers. Same-day dispatched orders are also downloaded, paged, or 10

radioed to the FSR from the Customer Contact Center. In addition to completing service orders and 11

field collection orders while at the customer location, FSRs also review the field environment to identify 12

potential energy theft situations and hazardous field conditions and record relevant information for 13

follow-up. 14

b) Operating Results - Turn-On and Turn-Off Services 15

A significant cost reduction is achieved with the ESC system’s RSS functionality 16

contained within residential and small commercial ESC meters. Before deployment of the ESC system, 17

the cost and service charge of Turn-On service orders in 2009 was $15 for next-day service and $26 for 18

same-day service.16 With the introduction of RSS, the average cost of turning electric services on or off 19

for residential services has been reduced to approximately $5 and $25 for commercial customers.17 The 20

cost of Turn-On services is recovered directly from the customers receiving these services through a 21

service charge, which is accounted for as Other Operating Revenue (OOR) in FERC Account 451.300 22

and Account 451.310 respectively. This cost reduction represents a direct savings to customers 23

requiring these services of approximately $12 million per year. 24

SCE expects that, at any given time, approximately five percent of residential 25

customers will not have RSS capability due to communications or other failure. Because of this normal 26

15 Credit and Payment Services activities and financial forecasts related to FERC Account 903.200 are addressed in

Chapter IV, of this Volume.

16 Authorized in SCE’s 2012 GRC Vol. 4.

17 See Testimony in Chapter X Sections C and D of this Volume for Service Connection fee.

35

level of inoperative RSS capability, the cost of providing manual Turn-On and Turn-Off services for 1

these accounts has been included in the calculations supporting the service connection charge as a 2

weighted average cost spread to all customers receiving this service. 3

Table III-12 below shows the number of completed Turn-On and Turn-Off orders 4

from 2008 through 2012, both with and without the use of the RSS. A “soft” turn-on or turn-off is one 5

that is completed with a meter read only, and there is no need to actually turn the service off. 6

Table III-12 Completed Turn-On and Off Orders

2008–2012

* RSS/Soft turn-ons and RSS/Soft turn-offs are completed with an automatic meter read and/or remote switch.

Historically, the number of manual Turn-On orders exceeds the number of manual 7

Turn-Off orders for two reasons: (1) customer growth—as new customers were added, the number of 8

active services increases proportionately; and (2) many turn-on and turn-off orders happen 9

simultaneously for customers who are moving into a location at the same time the existing customer is 10

moving out. Although this common occurrence of simultaneous turn-on/turn-off is counted as two 11

separate orders, it is completed with just one field visit to obtain a single meter read that is used for both 12

the new customer’s opening bill and for the departing customer’s closing bill. When this situation 13

occurs, the turn-on order is counted as a manual turn-on, and the turn-off order is counted as a soft turn-14

off. With the RSS now in full operation, the number of manual turn-ons and manual turn-offs has 15

dropped significantly. Although the disparity between manual turn-ons and turn-offs still exists, the 16

differential between the two is far less than in previous years. 17

36

Not included in this account are Field Services activities related to credit orders, 1

which include disconnection for non-payment, delivery of final call notices to special needs customers 2

prior to disconnecting service, and after-hour reconnects.18 These activities are discussed in more detail 3

in RSO Credit in Chapter IV, Section A.2 of this Volume. 4


The recorded/adjusted costs for Turn-On and Turn-Off Service activities are 6

shown in Table III-13 below and were derived after analyzing the recorded costs and adjusted to reflect 7


Table III-13 Turn-On and Turn-Off Services

2008-2012 Recorded and Adjusted Expenses FERC 586.100

(Constant 2012 $000s) Line No. Description 2008 2009 2010 2011 2012

1 Labor Expense 16,307 17,136 15,818 11,003 4,178

2 Non-Labor Expense 3,833 2,620 1,859 680 437

3 Other - - - - -


The costs recorded in FERC Accounts 586.100 for 2012 include an estimated 9

$8.277 million in savings attributed to RSS operations in 2012. In order to account for the remaining 10

savings expected to be realized with the RSS in full steady state operation in the 2015 Test Year, an 11

additional downward adjustment of $1.817 million was made to the 2012 Base Year adjusted/recorded 12

cost. 13

As shown in Table III-13 above, the impact of ESC and the RSS are clearly 14

evident in the significant reduction of labor and non-labor expenses from 2010 to 2012. The use of the 15

RSS was implemented in July 2011 for residential Turn-On orders, and a slow ramp-up for collection 16

orders began in September 2011. 17

18 Special needs customers include critical care, elderly (seniors), and disabled customers.

37


Figure III-7 below shows the recorded/adjusted historical and forecast expenses 2

for the Turn-On and Turn-Off function. Details regarding the forecast O&M expenses for this function 3

are described below. 4

Figure III-7 Turn-On and Turn-Off Services





Because of the impact the ESC RSS has had on the Turn-On and Turn-Off 8

functions, operating costs incurred before 2012 are not representative of future expectations and thus 9

were not suitable to support the use of historical averages or trends to forecast future costs. Instead, 10

recorded and adjusted O&M costs for 2012, were used as the basis for forecasting future Turn-On and 11

Turn-Off costs. As adjusted, the Last Recorded Year was used as the base, to which future year cost 12

38

adjustments for customer growth and Operational Excellence were made to forecast the 2015 Test Year 1

expense. 2


Figure III-8 below shows the Test Year forecast for FERC Account 4

586.100 compared to the Base Year. Discussion on each forecast component follows. 5

Figure III-8 Turn-On and Turn-Off Services


(a) Customer Growth 6


forecast to increase by 2.06 percent from 2012 to 2015. The Turn-On and Turn-Off field operations are 8

directly impacted by customer growth as more meters continue to be added, creating additional routine 9

39

Turn-On and Turn-Off field orders. While meeting this added workload, the Field Services operations 1

group expects to continue to maintain high performance with timely completion of field orders. To 2

reflect the impact that customer growth will have on the volume of Turn-On and Turn-Off orders and 3

operating cost, an adjustment of $95,000 (2.06 percent) was made to 2012 Base Year adjusted/recorded 4

costs. 5

(b) Operational Excellence 6

MSO has identified cost savings in Turn-On and Turn-Off 7

activities through Operational Excellence initiatives. By 2015, MSO forecasts savings of $414,000 by 8

consolidating and reducing the number of Supervising FSRs in the district locations. Some work 9

activities now completed by Supervising FSRs will be performed by FSRs, and the scheduling duties 10

will be centralized into the Resources Management Center. This reduction is equal to approximately 11

seven FTEs. 12

4. Customer Installation and Energy Theft Expense [FERC Account 587] 13

This section describes the functional activities and presents the 2015 Test Year forecast 14

for Installation Expense, Energy Theft, and Field Services Management and Supervision. As is the case 15

with most traditional field service activities, the Customer Installation and Energy Theft functions are 16

significantly affected by the ESC systems, as discussed in the following sections. 17

a) Description of the Customer Installation and Energy Theft Expense 18

(1) Customer Installation 19

The Customer Installation function includes activities in response to 20

requests or problems that customers have regarding their billing or electrical service. This includes 21

billing inquiries, calls about noisy meters, removal of lock rings for remodels, and reporting damaged 22

meters. In addition to customer-initiated orders, our Billing Group and automated exception review 23

processing programs in the MDMS generate electronic orders to the field requiring meter inspections 24

and/or pick-up reads. Customer Installation activities are impacted by customer growth and the volume 25

of customer requests, the specific nature of those requests, and internally identified billing exceptions. 26

A simple inquiry may be handled over the telephone by the Customer Contact Center (CCC), which is 27

not recorded in this account. More complex issues, which require the involvement of field personnel 28

and equipment, record to this account. 29

The majority of field service activities recording to this account are 30

categorized as pick-up reads, most of which were completed in the past by Meter Readers on or near 31

40

their normal meter reading routes. Starting in 2013, all pick-up reads will be completed by FSRs. The 1

remaining field service activities recording to FERC Account 587 are categorized as Field Service 2

exception orders. Table III-14 below summarizes the Field Service pick-up reads and exception orders 3

completed each year from 2008 through 2012 and the forecast level of activities through the 2015 Test 4

Year. 5

Table III-14 Field Service Pick-up Reads and Exception Orders

2008-2015

Line No. Description

Recorded Forecast

2008 2009 2010 2011 2012 2013 2014 2015

1 Meter Reading Pick Up Reads 179,205 141,176 194,775 222,103 144,603 - - -

2 Field Service Pick Up Reads 125,349 114,182 121,624 154,507 179,302 179,000 156,000 140,000

3 Field Service Exception Orders 68,254 79,303 75,263 82,366 90,696 88,000 75,000 57,000

4 Total 372,808 334,561 391,662 458,976 414,601 267,000 231,000 197,000

(a) Impact of ESC Meters on Customer Installation Activities 6

The new ESC meters have affected Customer Installation activities 7

in several ways. With ESC functionality in place, more accurate and timely meter data will decrease the 8

volume of billing related pick-up reads. However, during the ESC deployment process in the years 2010 9

and 2011, MSO experienced an increase in Meter Reader pick-up reads and an increase in 2012 for field 10

service pick-up reads. This increase was due to less experienced Meter Readers, as well as a temporary 11

volume of pick-up reads during the time the new technology was being installed, beginning 12

communication, and resolving issues. The incremental cost for OTA pick-up reads during the ESC 13

deployment period was charged to the ESCBA and are included in the 2012 Base Year expense used for 14

this GRC. 15

Overall, the ESC system is expected to provide a reduction in the 16

number of pick-up reads required in the future, as shown in the forecast for 2013–2015 in the above 17

table. The reduction will result from the ability to complete most internal, billing-related pick-up reads 18

automatically, OTA from the ESC meters. 19

41

(b) Impact of ESC Over-The-Air Communications on Customer 1

Installation Activities 2

The widespread use of radio frequency communication has created 3

a new source of meter reading/data collection failures because of the inability to communicate with 4

some meters. Although such communication failures occur less than 0.5 percent of the time, this still 5

results in a significant number of occasions that require a field visit to the meter to determine radio 6

signal strength and/or to read the meter manually. Consequently, OTA communication failures have 7

caused an increase in the volume of pick-up reads in 2011 and 2012. In addition, new meter warranty 8

provisions require field investigations, which are charged to this O&M account. With the conclusion of 9

the deployment of new ESC meters, the number of field investigations generated by these factors is 10

expected to decrease beginning in 2013, as shown in Table III-14 above. 11

(c) Service Guarantee – Missed Appointments 12

SCE’s Missed Appointment service guarantee states that SCE will 13

arrive at the agreed-upon appointment within 30 minutes before or after the scheduled appointment time. 14

SCE pays a $30 credit for each missed appointment related to service establishment (turn-on) and billing 15

inquiries. Table III-15 below shows the Missed Appointment service guarantee credits SCE paid over 16

the last five years. In 2012, out of 5,987 turn-on appointments and billing inquiries, SCE paid 280 17

claims. This represents 4.8 percent of all turn-on and billing inquiry appointments. 18

Table III-15 Missed Appointment Service Guarantee Credits 2008-2012

Nominal $s


Recorded Five-Year

Average 2008 2009 2010 2011 2012 1 Numbers of Claims Made 388 336 277 235 163 280 2 Number of Claims Paid 388 336 277 235 163 280 3 Amount Paid $11,640 $10,080 $8,310 $7,050 $4,890 $8,394

4 Total Volume of Turn-on Appointments and Billing Inquiries 5,253 6,719 6,935 6,320 4,707 5,987

5 Paid % of Total Volume of Turn-on Appointments and Billing Inquiries 7.4% 5.5% 4.0% 3.7% 3.5% 4.8%

As discussed in Chapter I of this Volume, SCE is proposing to 19

include the cost of service guarantee credits in our cost structure based on the average number of missed 20

42

appointments that have been recorded over the last five years. The existence of this service commitment 1

results in improved service levels for all customers and should be treated as a normal cost of business. 2

SCE is proposing that the five-year average of credits be used as the base level target for the Missed 3

Appointment service guarantee credits to be included in rates and is a part of FERC Account 903.500 4

Billing forecast for the 2015 Test Year. 5

SCE rarely receives a customer complaint regarding a missed 6

appointment, as complaints are generally “self-reported” by SCE. Most late missed appointments result 7

from heavy traffic preceding work that requires more time to complete than planned, and/or higher 8

priority emergency work causing a deferral of the lower prioritized work. 9

(2) Energy Theft 10

Our Energy Theft function includes activities required to collect revenues 11

that would otherwise be lost as a result of energy theft and billing exceptions caused by irregularities in 12

meter registration.19 This revenue assurance function identifies customers who potentially benefit from 13

energy usage without authorization from the utility, identifies and corrects situations in which a 14

customer has been billed incorrectly as a result of revenue assurance investigations, and collects the 15

revenue for unauthorized usage. 16

Prior to ESC metering, SCE’s Energy Theft program was heavily 17

dependent on meter readers who were trained to observe and detect potential meter tampering or energy 18

bypass installations while on their routine monthly meter reading routes. With ESC meters being read 19

automatically, SCE no longer has the ability to visually inspect all of its metering installations on a 20

monthly basis. To ensure a reasonable level of control over potential energy theft, SCE has initiated 21

three programs to replace the monthly visual observations of metering installations by meter readers. 22

These three new energy theft detection programs are currently at various stages of implementation: (1) 23

Tamper Flag Program: ESC-enabled meters are able to detect various unauthorized intrusions into the 24

metering system and communicate tamper flags that initiate a field investigation; (2) Unusual Usage 25

Program: Meter Data Management System (MDMS) customer consumption data mining analyses, 26

which will generate new leads that were not part of the program in the past; and (3) Annual Survey 27

Program: the Commission-mandated annual survey of 0.5 percent of installed ESC meters designed to 28

19 Meter registration irregularities include: Non-theft meter errors, service not registered correctly for proper billing, and

unbilled or unmetered service.

43

mitigate the absence of meter readers’ “eyes in the field” that were trained to identify potential meter 1

irregularities as part of the monthly, manual meter reading process.20 2

(a) Meter Tamper Flag Program 3

The ESC system has the ability to record Power Down (meter 4

removed), Power Up (meter installed), Inversion Tamper Detected (meter inverted), and Removal 5

Tamper Detected (power down combined with meter inverted) as independent events in the event log. 6

In addition, a “service switch open failed” event will be recorded if the service switch fails to open when 7

an open switch signal is sent or when load side voltage is present after an open switch signal has been 8

sent. Each of these tamper flag events is expected to generate a field investigation order. Implemented 9

in early 2013, the Tamper Flag Program is in the early deployment stage and is being tested for a variety 10

of potential detection functions. We are in the process of developing more defined procedures and 11

expect the program to be fully implemented and operational in 2015. It is expected that the Tamper Flag 12

program will result in 10,900 investigations in 2015. This compares well with the former program in 13

which meter readers and employees in 2009 identified 12,144 potential energy theft situations. 14

(b) Unusual Usage Program 15

The Unusual Usage Program uses data mining of customer interval 16

usage patterns to identify potential energy theft cases. Historical usage patterns become disrupted and 17

undergo certain predictable changes when a meter has been bypassed. Such usage patterns can be 18

detected automatically using software algorithms designed for that purpose. This method of theft 19

detection is especially useful for identifying commercial theft cases where the usage pattern does not 20

track the typical pattern established for that particular type of business. Data mining has been used 21

successfully by other utilities, and, in 2007, SCE conducted its own usage pattern theft detection 22

program with limited success, using only monthly consumption data.21 Now that hourly usage patterns 23

are available for nearly all customers, the MDMS Unusual Usage Program is expected to generate over 24

4,000 high quality leads annually with a 20 to 30 percent success rate of confirmed theft cases in the first 25

full year. Like the Tamper Flag program, the Unusual Usage energy theft program is still in the early 26

20 ESC Phase III deployment Decision D.08-09-039, Section 8, p. 17, and Section 10.1.2, p. 35.

21 SCE conducted a test of a commercially available theft detection program with Detectent Inc. The 2007 test produced a 16% success rate resulting from field investigations of leads generated by the Detectent programs.

44

development stages. We are in the process of developing more defined procedures and expect the 1

program to be fully implemented and operational in 2015. 2

(c) Annual Survey Program 3

A general assumption of the ESC program22 was that energy theft 4

losses would likely increase in the absence of the regular visual inspections historically conducted by 5

meter readers unless ESC system-assisted energy theft programs supplanted this role.23 The ESC 6

Deployment Settlement Agreement, as authorized by the Commission in D.08-09-039, was not only 7

supportive of SCE’s proposed Revenue Protection plans, but actually supplemented them by agreeing to 8

a continuation of the 0.5 percent annual survey of ESC meter installations as a substitute for the 9

elimination of the monthly field visits to each meter site by SCE’s meter readers. SCE has now 10

completed the first two years of conducting the 0.5 percent annual survey of ESC meter installations, the 11

results for which are shown in Table III-16 below. 12

Table III-16 ESC Energy Theft Field Inspection Samples

2011 and 2012 (Constant 2012 $s)

Line No. Description 2011 2012

1 Meters Inspected 11,032 29,094 2 Percent of ESC Meters Inspected 0.64% 0.59% 3 Verified Tampering Found 37 43 4 Energy Theft Cases Billed 36 42 5 Energy Theft Revenue Billed $44,441 $228,850

As the new ESC meter installations begin to age, the opportunity 13

for increased levels of meter tampering is likely to occur. SCE will continue to monitor energy theft by 14

continuing the 0.5 percent annual surveys as directed by the Commission. Future survey results will be 15

22 As presented in the ESC application - A.07-07-026 Appendix A “Settlement Agreement” Section 3.E., pp. 7-8.

23 SCE’s workpapers in A.07-07-026 contained references to “Revenue Protection: Using AMR and Other Tools to Guard Against Theft and Unintentional Losses,” Metering Research Series, Chartwell, Inc., 2006.

45

closely watched as a means of determining the overall potential for energy theft and the types of energy 1

theft that are associated with the new metering technology. 2

(3) Field Services Management and Supervision 3

Field Services Management and Supervision includes costs related to 4

management and supervision of our Field Service personnel, training for FSRs, and informational and 5

safety meetings. As the number of personnel performing these activities is forecast to decrease 6

significantly by 2015, so too will the costs related to these management, supervision, and support 7

functions. 8


Field service operations, customer installations, and energy theft were 10

significantly affected during the deployment of ESC during 2010-2012, as nearly all five million of 11

SCE’s legacy electromechanical meters were replaced with new, solid-state, two-way communicating 12

meters. 13

(1) Customer Installation Expense Operating Results 14

Field service orders related to Customer Installation expense are tracked as 15

Field Service and Meter Reading/Data Collection Pickup Reads and Exception Orders. In the pre-ESC 16

environment, these orders were completed by meter readers or by FSRs, depending on the type and 17

complexity of each order. Now, with ESC fully deployed, these orders are generated by SOC or by the 18

Billing Exception process, and they are all completed by FSRs. Typically, a Meter Reading or Field 19

Service Data Collection Pick-Up Read order is one that requires a second trip to the meter to obtain a 20

meter read, e.g., when an ESC meter is not communicating properly, and a re-read is needed. 21

The original ESC plan was for the ESC meters and the MDMS to 22

eliminate the need for pick-up reads and field exception orders. However, this is not turning out to be 23

the case. Although the number of meter reading data collection pick-up reads has been reduced 24

significantly, as seen in Table III-14 above, there has been an increase in OTA communication errors 25

that require on-site meter reads or communication signal verification. 26

The Field Service exception orders have increased from 2010 to 2012 due 27

to customer growth and deployment-related non-communication issues that will be reduced as we move 28

into the post-deployment ESC environment. Exception orders are generally more complex than pick-up 29

reads and can involve unsafe conditions, load and voltage checks, removal and replacement of lock 30

46

rings, communication on billing inquiries, zero usage investigations, and Turn-On service order 1

validations. Table III-17 shows the Field Service exception orders for 2008-2012. 2

Table III-17 Customer Installation Field Orders

2008-2012 Line No. Description 2008 2009 2010 2011 2012

1 Field Service Exception Orders 68,254 79,303 75,263 82,366 90,696

(2) Energy Theft Operating Results 3

Energy Theft is one of two elements of SCE’s Revenue Protection 4

programs. The second element relates to the detection of unmetered and unbilled energy use that is not 5

traceable to intentional tampering or theft. The number of verified and billed energy theft and unbilled 6

energy cases that were processed over the last five years is shown below in Table III-18. 7

Table III-18 Energy Theft and Billing Exception Cases in 2008-2012



1 Energy Theft Cases Billed 1,928 1,935 1,712 1,115 1,108

2 Energy Theft Amounts Collected $2,440 $2,201 $1,842 $1,552 $1,407

3 Billing Exception Cases Billed 1,080 1,289 708 353 198

4 Billing Exception Amounts Collected $3,428 $3,875 $1,765 $937 $652

5 Total Amounts Collected $5,868 $6,076 $3,607 $2,489 $2,059

The number of cases billed and revenue recovered shows a significant 8

reduction of detected energy theft and unbilled energy cases over the last five years. A significant one-9

time reduction in both energy theft cases and unbilled energy cases has occurred as a result of replacing 10

nearly five million legacy electromechanical meter installations with new solid state ESC meters. 11

However, as anticipated in the ESC business case, the elimination of meter readers has also eliminated 12

SCE’s primary source of meter tamper detection, which has contributed to the significant reduction in 13

the number of billed theft and unbilled energy cases. 14

47

With the deployment of ESC and the elimination of meter readers, the 1

Energy Theft program is undergoing a major transformation. As discussed above, the previous monthly 2

visual observations of nearly five million meters have been replaced by an annual sample inspection of 3

0.5 percent (approximately 25,000) meters per year. The sample results are an indicator of the general 4

state of the overall theft level across the SCE system. To date, SCE has completed two years of these 5

sample inspections; the results of these samples are included above in Table III-16. 6

(3) Field Services Management and Supervision - Operating Results 7

The Field Services Management and Supervision function includes the 8

non-core FSRs functions such as: meetings, grievances, vehicle breakdown, and training costs. There 9

are also some supervision-related costs allocated to this function. In 2010, FSR certification and FSR 10

upgrade training was provided that addressed technology advances and additional certification 11

requirements. The 2010 training was necessary to ensure our employees are all working under safe and 12

uniform procedures. In 2011, the certification training continued, and additional technology training 13

was introduced to educate FSRs about the new probe required to obtain information from ESC meters 14

manually. 15


The recorded/adjusted costs for Customer Installation and Energy Theft expenses 17

are shown in Table III-19 and were derived after analyzing the recorded costs and adjusted to reflect 18


Table III-19 Customer Installation and Energy Theft Expenses

2008-2012 Recorded and Adjusted Expenses FERC Accounts 587



1 Labor Expense 8,546 7,806 11,279 10,610 6,107

2 Non-Labor Expense 1,233 1,243 1,460 1,076 869

3 Other - - - - -


48

Several ESC Base Year adjustments were necessary for this account to reflect 1

adjustments for the removal of nonrecurring legacy costs recorded in the Base Year and to add the 2

incremental steady state ESC costs that were recorded in the ESCBA in 2012. These Base Year 3

adjustments included the following: 4

Removal of Non-Recurring Legacy Costs. Non-recurring legacy costs of $1.669 5

million were removed from the 2012 Base Year recorded costs to reflect anticipated future savings from 6

an overall reduction in legacy pick-up reads and field service exception orders that would no longer be 7

needed under full steady-state ESC operations. This represents 56 percent of the $2.981 million in 8

savings identified in the ESC business plan. The other 44 percent of these savings has already been 9

realized in the 2012 recorded cost. 10

A second nonrecurring legacy cost of $1.785 million was removed from the 2012 11

Base Year recorded cost to reflect anticipated future savings result from an overall reduction in 12

Management, Supervision, and support costs attributed to the reduction in field personnel. 13

Addition of Ongoing Steady-State Costs. ESC incremental steady state cost of 14

$1.027 million was added to the 2012 Base Year cost. This cost is related to the new type of Over The 15

Air pick-up reads. OTA pick-up reads are needed when various OTA operations malfunction and a field 16

representative is sent to the meter location to determine the cause of the malfunction. OTA operations 17

include Firmware updates, programming configuration failures, time sync failures, OTA disconnect 18

failures, and OTA billing read failures. 19

Year-by-Year Variance Analysis. In 2009, labor expense decreased by $740,000 20

as a result of almost 40,000 fewer Meter Reading Exception Orders because Electronic Radio 21

Transmitter sets were deployed to address access issues. In 2010, labor expense increased by $3.5 22

million as a result of safety initiatives related to access customers’ property and FSR certification 23

training. New safety initiatives created an increase in order completion time, and pick-up read orders 24

increased 24 percent. In 2012, labor expense decreased by $4.5 million as a result of completion of the 25

FSR Certification training, as well as the reduction in work force that resulted from the transition from 26

manual to automated pick-up reads and RSS operations as previously described. 27

In 2010, non-labor expense increased by $217,000 as a result of a safety initiative 28

requiring MSO to purchase uniforms with higher fire rating and face shields to protect employees from 29

electrical burns. In 2011 and 2012, non-labor expense decreased as a result of all fire-rated uniforms 30

and face shields being purchased in 2010, and a reduction in vehicle expense as the ESC meters were 31

49

being installed. The drop in non-labor expense in 2012 was primarily due to the shift from manual to 1

automated field service orders, as more ESC meters were deployed and RSSs were becoming 2

operational. 3

d) Test Year Operating Expectations FERC Account 587 4


Customer Installation and Energy Theft function. Details regarding the forecast O&M expenses for this 6

function are described below. 7

Figure III-9 Customer Installation and Energy Theft





Because of the impact ESC has had on Customer Installation and Energy 11

Theft operations, operating costs incurred prior to 2012 are not representative of future expectations and 12

thus are not suitable to support the use of historical averages or trends to forecast future costs. The Last 13

50

Record Year was used as the base, to which cost adjustments were added or subtracted for future year 1

cost increases and decreases. 2


Figure III-10 shows the 2015 Test Year adjustments for FERC Account 4

587 compared to the Base Year. Discussion on each forecast adjustment component follows. 5

Figure III-10 Customer Installation and Energy Theft



(a) ESC Steady State Costs 6

To reflect the future increase in costs of new energy theft programs 7

associated with the implementation of ESC as steady state operations occur from 2013 through 2015, an 8

adjustment of $1.180 million was made to the 2015 Test Year forecast. As discussed in Operating 9

51

Results above, activities charged to the Revenue Protection account are all related to field meter 1

activities and were significantly impacted by the deployment of the ESC systems. The cost for the 2

Tamper Flag and Unusual Usage Programs are not included in the Base Year, as ESC deployment was 3

completed in December 2012. As the meter reading activities were converted from manual to automatic 4

reading processes, fewer meter tampering investigations occurred, as the number of leads originating 5

from meter readers diminished in 2011 and 2012. This was a temporary reduction in energy theft 6

investigations because the two new energy theft programs, ESC tamper flags and MDMS data mining, 7

are just beginning and are expected to generate nearly triple the number of field theft investigations and 8

confirmed theft cases that occurred previously. 9


The number of customers in SCE’s service territory is forecast to 11

grow by 2.06 percent during 2012 to 2015. The increased number of customers will result in an increase 12

of customer meter installations and energy theft. Thus, an adjustment of $144,000 was made to Last 13

Recorded Year to forecast Test Year expenses to account for the impact of customer growth on 14

Customer Installation and Energy Theft operations. 15

(c) Operational Excellence 16

MSO has identified cost savings in Revenue Protection activities 17

through Operational Excellence initiatives. By 2015, MSO forecast a reduction of $355,000 by 18

eliminating Supervising FSRs in the revenue protection function. Less complex work previously 19

completed by Supervising FSRs will be performed by FSRs while conducting other routine work. This 20

cost reduction is equal to about six FTEs. 21

5. Meter Services Operations and Management [FERC 580] 22

a) Description of Meter Services Operations and Management Support 23

The Meter Services Operations and Management functions recorded in FERC 24

Account 580 include Customer Service Safety and Management Support, which are described below. 25

(1) CS Safety 26

As the largest provider of field services and hands-on electrical repair and 27

maintenance functions within Customer Service, MSO is responsible for the development and 28

enforcement of CS Safety & Environmental Health policies, practices, and procedures. The CS Safety 29

Organization develops and implements safety programs that are specifically tailored to the requirements 30

of the Customer Service Operating Unit. Customer Service employs a wide variety of occupations, 31

52

which encompass field, technical, and office environments. The CS Safety group is chartered with 1

continually improving Customer Service safety programs and helping to maintain a safe work 2

environment for all employees working in locations across our 50,000-square-mile territory. The CS 3

Safety group collects and analyzes injury data to develop an understanding of the safety issues 4

associated with each occupational environment. This group designs, develops, and implements 5

programs, policies, and procedures to help reduce employee injuries. 6

CS Safety oversees the direction, management, and maintenance of 7

infrastructure critical to the effectiveness of CS’s safety program. With our primary objective to achieve 8

an injury-free workplace, CS Safety focuses on providing services to comply with California OSHA 9

regulations and Commission safety requirements. CS Safety provides compliance and program-related 10

training and developing and deploying programs to prevent and reduce injuries. CS Safety consults with 11

Corporate Environment, Health and Safety (EH&S) to achieve these objectives. CS Safety is organized 12

into two groups, Safety Field Operations and Safety Support and Training, that are described below. 13

(a) Safety Field Operations 14

The Safety Environmental Specialists (SESs) in Field Operations 15

are safety professionals who work closely with personnel in the field. SESs are focused on 16

strengthening our safety culture through several core work responsibilities that involve interacting with 17

management personnel, safety team members, and front line employees. SES activities include (1) 18

providing field and office personnel coaching and guidance while acting as a liaison with Corporate 19

EH&S, (2) developing and implementing safety awareness programs, procedures, and policies, (3) 20

conducting general and compliance safety awareness training, (4) supporting management and employee 21

safety teams that examine operational and safety culture issues to design client-specific programs, (5) 22

participating in incident reviews, (6) partnering with site management in facility inspections, and (7) 23

providing safety trends and performance reports. These activities are conducted at various field 24

locations, requiring a significant amount of travel for SESs. 25

(b) Safety Support and Training 26

Safety Support and Training is comprised of employees who 27

perform safety-related analytical, administrative, and program support functions for Customer Service. 28

Safety Support and Training is responsible for the collection, synthesis, and dissemination of all safety-29

related reporting, including incident, accident, and compliance training for Customer Service. This 30

group collaborates with Field Operations in developing programs aimed at preventing injuries and 31

53

provides project management support for the Safety Culture Change Process. Additionally, in 1

collaboration with Corporate EH&S, Corporate Communications, and other partners, this group 2

develops and distributes safety and environmental communications that address issues affecting 3

Customer Service employees. 4

(2) Management Support 5

Management Support provides a variety of management support services 6

for MSO. Management Support personnel deliver administrative, analytical, budgetary, communication, 7

evaluative, and operational support, as well as process control, project management, quality 8

management, benchmarking, training, resolution of union issues, and strategic planning services for all 9

MSO operations. The following eight groups comprise our Management Support organization: 10

1. The Business Systems and Field User Support team provides subject-11

matter expertise, technology implementation, and support for system 12

testing, including field deployment. 13

2. The Training and Delivery staff is dedicated to training MSO 14

employees in support of safety, quality initiatives, and new work 15

processes. The team is responsible for delivering that material in 16

classroom settings and through morning briefings. 17

3. The Major Initiatives group supports business process and 18

requirements management, risk management, mitigation, change 19

management, transition planning, and operational readiness (including 20

triage and post-support work). 21

4. The Operational Improvement Program group manages operations and 22

cross-functional process improvement projects. The group oversees 23

compliance, business continuity, and corporate exercise activities 24

across MSO. It maintains the MSO Information Center on the intranet 25

and produces operational communications products for multiple 26

written, online, and internal video channels. 27

5. The Business Analytics & Reporting team produces reports that are 28

essential to day-to-day operations. It completes routine performance 29

metrics and reporting (i.e., weekly, monthly, yearly) and develops ad 30

hoc analytics for operations and executives. 31

54

6. Operational & Regulatory Planning works to develop regulatory 1

information, performs benchmarking analytics and industry trending. 2

The group develops complex analytics, operational data modeling, and 3

business planning integration. 4

7. The Quality Management System group provides methods for process 5

and corrective action improvements, documentation standards and 6

controls, assessment and audit methods, procedures, reporting and 7

records management, as well as oversees of legacy and ESC field 8

operations work. 9

8. The Resource Management Center (RMC) manages the centralized 10

and consolidated multiple systems used by field supervisors matches 11

human resource asset availability and proficiency to the field work 12

activities. The RMC manages work initiation, planning, forecasting, 13

scheduling, and reporting, as well as physical space appropriation. 14


(1) CS Safety 16

Customer Service is committed to maintaining a healthy and safe 17

workplace for its employees based on the premise that employees are responsible to ensure they are 18

engaged in promoting a safe workplace and complying with all safety policies and regulations. The safe 19

workplace is one where employees are committed to their own safety as well as to that of their co-20

workers. Each organization is engaged in their ongoing safety action plans. 21

The Days Away from Work, restricted duty, and Transfer (DART) Rate, is 22

a common utility measurement that enables SCE to benchmark against other utilities to track 23

improvements in safety. The DART Injury Rate, which shows the number of DART injuries for every 24

200,000 hours worked, measures our overall safety performance. Customer Service’s DART 25

performance over the last five years is shown in Table III-20 below. For 2012, the CS DART Rate was 26

2.50, which was a 31 percent improvement over the five-year average of 3.29. With our challenging 27

work environment in 2012, in light of the significant reduction in workforce and beginning of MSO’s 28

restructuring, this reduction over 2011 was a notable accomplishment. Customer Service will continue 29

to focus on reducing workplace injuries by developing and implementing new programs and action plans 30

targeting our safety culture. 31

55

Table III-20 Customer Service Operations

DART Rate (2008-2012)


Five-Year Average

1 Injury Index 4.87 3.26 3.0 2.83 2.50 3.29

(2) Operations and Management Support 1

The transition from legacy meters to a fully deployed ESC meter system 2

was extremely challenging, and required management oversight to execute without negatively impacting 3

service level to our customers. The largest overall management achievement of MSO over the last five 4

years has been the successful deployment of nearly five million ESC meters, along with the radio 5

communication systems needed to access and process the customer interval usage data recorded by these 6

meters and the capability to remotely turn each meter on and off. At the end of 2012, the ESC systems 7

were operational at an ongoing steady-state level. 8


The recorded/adjusted costs for Meter Services Operations and Management 10

activities are shown in Table III-21 and were derived after analyzing the recorded costs and adjusted to 11

reflect ongoing operations. 12

56

Table III-21 Meter Services Operations and Management 2008-2012 Recorded and Adjusted Expenses


Line No. Description 2008 2009 2010 2011 2012 1 CS Safety 2 Labor 1,540 1,969 2,025 1,760 1,706 3 Non-Labor 1,514 1,614 1,185 981 530 4 Other 0 0 0 0 0 5 Sub-Total 3,054 3,583 3,210 2,741 2,236 6 Management Support 7 Labor 2,951 3,210 6,284 6,351 6,007 8 Non-Labor 1,112 528 510 361 295 9 Other 0 0 0 0 0 10 Sub-Total 4,063 3,738 6,794 6,712 6,302 11 FERC 580 12 Labor 4,491 5,179 8,309 8,111 7,713 13 Non-Labor 2,626 2,142 1,695 1,342 825 14 Other 0 0 0 0 0 15 Total 7,117 7,321 10,004 9,453 8,538

(1) Customer Service Safety 1

In 2009, labor expense increased by $429,000 as a result of higher safety 2

and recognition incentives being paid, as well as an increase of four personnel in late 2008 related to 3

restructuring the CS Safety organization. In 2011, labor expense decreased by $265,000 as a result of 4

reduction in the safety recognition program and three vacancies for portions of the year. 5

In 2010, non-labor expense decreased by $429,000 as a result of 6

restructuring our incentive program, related to a company-wide initiative that resulted in reduced costs 7

for incentives related to safety recognition. In 2012, non-labor expense decreased by $451,000 as a 8

result of continuing to reduce costs related to safety recognition awards and incentive programs. 9

(2) Management Support 10

In 2009, labor expenses increased by $259,000 due to the hiring of three 11

employees to support compliance efforts and help maintain aging systems. In 2010, labor expense 12

57

increased by $3.074 million as a result of a change in the department organizational structure to better 1

align with ESC operations. The structure changes required area managers and supervision to now begin 2

recording to Management Support. In 2012, labor decreased by $344,000 due to eliminating several 3

positions in conjunction with Operational Excellence efforts. 4

In 2009, non-labor expenses decreased by $584,000 due to the lower cost 5

associated with wireless services, remote computer access, and other field personnel equipment. In 6

2011 non-labor decreased $149,000 related to lower employee expenses. 7

d) Test Year Operating Expectations FERC Account 580 8


Meter Services Operations and Management function. Details regarding the forecast O&M expenses for 10

this function are described below. 11

Figure III-11 Meter Services Operations and Management

FERC Account 580 (Constant 2012-$000s)



58


The Last Recorded Year is the most appropriate forecast method for the 2

Base Year as expenses for this FERC Account have decreased since 2010. Meter Services Operations 3

and Management costs incurred prior to 2012 are not representative of future expectations and thus are 4

not suitable to support the use of historical averages or trends to forecast future costs. The Last 5

Recorded Year was used as the base, to which cost adjustments were added or subtracted for future year 6

cost increases and decreases. 7


Figure III-12 shows the Test Year forecast for FERC Account 580 9

compared to the Base Year. 10

59

Figure III-12 Meter Services Operations and Management

Comparison of 2012 Base Year to 2015 Test Year (Constant 2012 $000s)


The number of customers in SCE’s service territory is expected to 2

grow by 2.06 percent during 2012 to 2015. Because of the associated increase in support and 3

management activities, an adjustment of $176,000 was made to 2012 Base Year adjusted/recorded costs. 4

(b) Operational Excellence 5

MSO has identified cost savings in Meter Service Operation and 6

Management activities through Operational Excellence initiatives. By 2015, MSO will reduce $2.306 7

million by reducing the number of managers, supervisors, technical specialists, training specialists, and 8

administrative and analytical support. This will be achieved by realigning our management within MSO 9

to reduce costs and manage the new ESC metering system. We also plan to decrease the use of 10

60

contingent workers and IT devices utilized by our personnel. This cost reduction is approximately 20 1

FTEs. 2

B. Meter Services Organization Capital 3

1. Overview 4

This section addresses the capital requirements for MSO, which average $30.8 million 5

per year for 2013 through 2017. The largest component of the MSO general capital forecast is for 6

meters, which comprises approximately 97 percent of the total general capital requirements. The MSO 7

capital forecast requirements are shown in Table III-22. 8

Table III-22 Capital Requirements (Nominal $ Millions)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Structures and Improvements $ - $ 0.674 $ 0.849 $ - $ - $ 0.715 $ 0.775 $ - $ - $ - 2 Specialized Equipment 0.390 0.117 0.967 0.196 0.031 0.307 0.314 0.214 1.997 0.337 3 Meters 23.920 23.824 17.154 7.723 6.832 18.824 27.419 33.552 34.054 35.684 4 Total $ 24.310 $ 24.614 $ 18.970 $ 7.919 $ 6.863 $ 19.846 $ 28.508 $ 33.766 $ 36.052 $ 36.021

Line No Class of Plant

Recorded Forecast

2. Metering Capital Requirements (CCS-00-CM-CO-RB-00001, CCS-00-CM-CO-RB-9

00003, CCS-00-CM-CO-RB-00004, CCS-00-CM-CO-RB-00005, CCS-00-CM-CO-10

RB-00006, CCS-00-CM-CO-NR-00001, CCS-00-CM-CO-NR-00002) 11

With the completion of ESC deployment in 2012, metering capital costs going forward 12

will be for new ESC growth, replacement meters, legacy meters used for Opt-Out customers, and RTEM 13

metering for SCE’s largest customers (over 200 kW). The ESCBA remains open in 2013 and 2014 for 14

the implementation of HAN. However, it is closed for all other costs, including meter capital. 15

Therefore, all metering capital requirements will now be requested in the GRC. 16

a) Meter Capital Forecast 17

(1) New Growth Meter Installations (Residential, Commercial, and 18

Agricultural) 19

With the completion of the ESC deployment, ESC meters will be used for 20

new growth meter installations for all customers with demands under 200 kW that have not opted out of 21

the ESC program. The conventional electromechanical (legacy) meters will only be used for those 22

customers who select to opt out of ESC metering. SCE’s March 2013 Retail Sales & Customer 23

61

Forecast24 was used to forecast the Residential, Commercial and Agricultural new growth meter 1

requirements, with residential ESC meter inventory adjustments in 2013 and 2014. 2

(2) Replacement Meter Capital (Residential, Commercial, & 3

Agricultural) 4

With the exception of the RTEM meters (for customers over 200 kW) and 5

the ESC opt-out meter requirements, the replacement meters installed during and after the completion of 6

the ESC deployment are ESC meters and not the conventional electromechanical (legacy) meters. The 7

replacement quantity in 2013 is expected to be substantially less than prior legacy meter quantity 8

because the ESC meters are newer than legacy meters and they are still under warranty. ESC 9

replacement meters are, however, more costly than legacy meters. For 2013, SCE will not forecast any 10

new residential meters in order to deplete above normal post-deployment levels of inventory for smart 11

meters. For non-residential replacement meters, no surplus of inventory of meters exists and therefore, 12

annual purchases must be completed. 13

(3) Legacy Meters (including Opt-Out Program) 14

Legacy meters include the former conventional electromechanical meters 15

used prior to the ESC deployment for customers with demands under 200 kW. Because of the 16

requirements of the Commission-approved Opt-Out Program, SCE needs to continue an inventory of 17

conventional electromechanical meters for customers electing to opt out of the ESC program. Based on 18

customer growth and SCE’s past experience of customers moving into and out of the Opt-Out Program, 19

SCE forecasts the need for 3,600 electromechanical meters per year for 2013 through 2017. 20

(4) Real Time Energy Meters (RTEM) Meters 21

SCE’s largest customers with demands in excess of 200 kW are typically 22

more complex metering systems that are beyond the scope of the ESC program. RTEM meters are 23

interval data recorder (IDR) meters that are needed to accommodate the most complex rates and billing 24

options. SCE is replacing older RTEM meters with advanced communications using Radio Frequency 25

(RF) technology. The RTEM replacement program is based on the five-year replacement average from 26

2008 through 2012. 27

24 See SCE’s March 2013 Retail Sales & Customer Forecast.

62

b) Historical Expenditures 1

The historical and forecast metering capital expenditures are shown in Table III-2

23 and forecast requirements are discussed more fully in the following sections. 3

Table III-23 Metering Equipment

Recorded 2008 – 2012 and Forecast 2013-2017 (Nominal $ Millions)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Meters $ 23.920 $ 23.824 $ 17.154 $ 7.723 $ 6.832 $ 18.824 $ 27.419 $ 33.552 $ 34.054 $ 35.684

Line No Expenditure

Recorded Forecast

Metering capital expenditures averaged $15.9 million in 2008 through 2012, 4

however, it is important to note that the meter volumes and capital expenditures recorded for 2010 5

through 2012 do not include the nearly five million recently installed ESC meters, the cost for which 6

was recovered through the ESCBA. Due to the deployment of ESC the normal growth meter 7

requirement pattern was disrupted, with a good portion of the growth meter requirement in 2011 through 8

2014 being filled from inventory as shown in Table III-24 below. Thus the recently recorded meter 9

volumes and capital expenditures do not reflect typical meter capital requirements. Meter capital 10

expenditures trend with customer growth over time but may fluctuate slightly from year-to-year because 11

meters bought in one year may be installed in a subsequent year. 12

c) Growth Meter Forecast 13

Table III-24 shows the number of recorded gross meter sets by customer class for 14

the years 2008 through 2012, the gross meter forecast for 2013 through 2017, and the growth meter 15

requirement after using up the ESC carry-over inventory. For 2013 through 2017, the customer growth 16

rate is forecast to be approximately 0.8 percent per year based on SCE’s Retail Sales and Customer 17

Forecast. 18

63

Table III-24 Growth Meter Recorded and Forecast Volumes

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Residential Growth Meters 32,594 23,643 19,146 14,125 17,692 27,785 38,643 51,238 56,320 55,9392 Inventory Change 101 4 4 (8,535) (16,640) (27,785) (7,996) - - - 3 Res. Growth Meter Purchases 32,695 23,647 19,150 5,590 1,052 - 30,647 51,238 56,320 55,939 4 C&I Growth Meters 12,808 8,078 6,109 5,411 4,865 5,114 6,542 8,607 10,698 11,897 5 Inventory Change (64) 66 64 (2,676) (4,264) - - - - - 6 C&I Growth Meter Purchases 12,744 8,144 6,173 2,735 601 5,114 6,542 8,607 10,698 11,897 7 Agricultural Growth Meters 646 424 311 293 309 316 332 335 339 343 8 Inventory Change - 2 2 (30) (111) - - - - - 9 Ag. Growth Meter Purchases 646 426 313 263 198 316 332 335 339 343 10 Total Growth Meters 46,048 32,145 25,566 19,829 22,866 33,215 45,517 60,180 67,357 68,179 11 Total Inventory Change 37 72 70 (11,241) (21,015) (27,785) (7,996) - - - 12 Total Growth Meter Purchases 46,085 32,217 25,636 8,588 1,851 5,430 37,521 60,180 67,357 68,179

Line No Customer Class

Recorded Forecast

d) Replacement Meter Forecast 1

Table III-25 below shows the replacement meter forecast for 2013 through 2017. 2

As previously discussed, the residential replacement meter forecast is substantially below historical 3

replacement volumes due to the fact that nearly all residential meters are new ESC meters that are 4

expected to have lower than normal replacement rates. SCE estimates 80 percent of ESC meter 5

replacements will be covered under the original manufacturer’s warranty. The C&I replacements are 6

based on a five year historical replacement average of 9,095 meters, with adjustments in 2014 through 7

2016 to take into account routine and sample testing schedule cycles that are expected to have an 8

influence on the number of replacements in those years. The Agricultural replacement forecast is based 9

on the five-year recorded average of 1,337 meters per year. Opt-Out replacements are expected to be 10

driven by opt-out customer turnover, as existing opt-out customers decide to revert back to ESC meters, 11

and as existing ESC-metered customers choose to opt out of their ESC meter. 12

Non-routine meter replacements include delayed ESC meter replacements that are 13

yet to be completed due to access issues and other extenuating circumstances that will delay the final 14

ESC installations into 2016 and 2017; PCAN meter replacements are a one-time replacement program to 15

upgrade obsolete legacy meters with ESC meters; RTEM meter replacements are for SCE’s largest 16

customers with demands over 200 kW. RTEM replacements occur as load requirements among these 17

large customers change, along with changes in metering system requirements. In addition, SCE is 18

gradually replacing meters based on older communication technology, in order to update them to 19

modern RF communication capability. The RTEM replacement meter forecast is based on the most 20

recent five-year historical average. 21

64

Table III-25 Replacement Meter Capital Volume Forecast

2013 2014 2015 2016 2017

1 Routine2 Residential Replacement - 5,890 5,275 5,364 5,448 3 C&I Replacement 9,095 7,800 6,079 5,744 9,095 4 Agricultural Replacement 1,337 1,337 1,337 1,337 1,337 5 Opt-Out Replacement 3,600 3,600 3,600 3,600 3,600 6 Subtotal - Routine 14,032 18,627 16,291 16,045 19,480 7 Non-Routine8 Delayed ESC Meter Installations - - 16,666 - - 9 PCAN Meter Replacement - 307 333 370 -10 RTEM Meter Replacement 2,028 2,028 2,028 2,028 2,028 11 Subtotal - Non-Routine 2,028 2,335 19,027 2,398 2,028 12 Total 16,060 20,962 35,318 18,443 21,508

Line No Type of Work

Volumes

e) Forecast Requirements 1

Our total capital forecast expenditures and volumes for new and replacement 2

metering installations are summarized in Table III-26 below. These expenditures were calculated by 3

applying the forecast volume of new meter sets and replacements per year (2013-2017) to the expected 4

cost per meter. The meter capital forecast reflects an overall increase in volume and costs from 2013 to 5

2017. The metering costs in 2013 are significantly lower than in subsequent years because existing 6

residential meter inventory above normal levels will be used before purchasing new meters. 7

Table III-26 Meter Capital Expenditure Forecast

(Nominal $ Millions)

Volume Costs Volume Costs Volume Costs Volume Costs Volume Costs1 Routine2 Residential Growth - -$ 30,647 4.120$ 51,238 7.031$ 56,320 7.765$ 55,939 7.837$ 3 Residential Replacement - - 5,890 0.792 5,275 0.724 5,364 0.740 5,448 0.763 4 C&I Growth 5,114 4.341 6,542 5.866 8,607 7.878 10,698 9.839 11,897 11.117 5 C&I Replacement 9,095 7.721 7,800 6.994 6,079 5.564 5,744 5.283 9,095 8.499 6 Agricultural Growth 316 0.268 332 0.298 335 0.307 339 0.312 343 0.321 7 Agricultural Replacement 1,337 1.135 1,337 1.199 1,337 1.224 1,337 1.230 1,337 1.249 8 Opt-Out Replacement 3,600 0.215 3,600 0.227 3,600 0.231 3,600 0.232 3,600 0.236 9 PEV Meters 15 0.002 15 0.002 15 0.002 15 0.002 15 0.002 10 Subtotal - Routine 19,477 13.682 56,163 19.496 76,486 22.961 83,417 25.402 87,674 30.025 11 Non-Routine12 Delayed ESC Meter Installations - - - - 16,666 2.287 - - - - 13 PCAN Meter Replacement - - 307 2.492 333 2.761 370 3.082 - - 14 RTEM Meter Replacement 2,028 5.142 2,028 5.431 2,028 5.544 2,028 5.570 2,028 5.660 15 Subtotal - Non-Routine 2,028 5.142 2,335 7.923 19,027 10.591 2,398 8.652 2,028 5.660 16 Total 21,505 18.824$ 58,498 27.419$ 95,513 33.552$ 85,815 34.054$ 89,702 35.684$

Line No Type of Work

2013 2014 2015 2016 2017

65

The following sections describe how meter volume estimates were developed and 1

the special projects that will increase the forecast for meters. 2

(1) Routine Work 3

Routine work includes a combination of new meter sets based on the 4

customer growth forecast and meter changes resulting from replacement of defective or broken meters. 5

Of the Residential Replacement meters, SCE forecasts that 80 percent of these meters would be covered 6

under the meter warranty, while 20 percent would fall outside the warranty due to physical damage 7

caused by nature or people (e.g., lighting strikes or car accidents). 8

(2) Non-Routine Work 9

(a) Infrastructure Replacement Program - RTEM meters 10

Non-routine work includes our Real Time Energy Meter (RTEM) 11

infrastructure replacement program, which began in 2003. RTEM meters are interval data recorders 12

installed on SCE’s largest customers with demands exceeding 200 kW. These customers are not 13

affected by the ESC program. When an RTEM meter fails, that meter is replaced with the improved 14

technology of a Radio Frequency (RF) meter. The RF technology includes the pre-installed radio 15

transmitter within the meter, improving communications for customers with 200kW demand or greater. 16

We have forecast replacement meter costs for RTEM meters based on an assumption of a five-year 17

historical average. The number of meters forecast for replacement each year is shown in Table III-25 18

above, and the cost for the infrastructure replacement program is approximately $2,700 per meter 19

installed. 20

(b) PCAN Meter Replacement 21

PCAN meters house the utility’s kWh meter and the test links 22

under one cover. They are typically used on agricultural accounts and mounted on a pole eight to 12 23

feet from the ground but may be placed higher or at eye-level as needed. The PCAN meters were 24

installed before 1950. These meters are now obsolete and are a safety concern for FSRs to read each 25

month. SCE will replace a total of 1,010 of these meters with ESC meters starting in 2014 and ending in 26

2016. This project is forecast to cost $8.34 million. 27

(c) Delayed ESC Meter Installations 28

While the ESC deployment was completed in December 2012, 29

approximately 50,000 legacy meters (excluding opt-out) remain in the field due to accessibility, owner 30

permission, and safety issues. No new meters are forecast for 2013 and 2014, while SCE depletes the 31

66

higher-than-normal inventory of ESC program meters. For 2015, the capital expenditures forecast for 1

these delayed ESC meter installations is $2.29 million. 2

3. Specialized Equipment (CCS-00-SE-CO-MS-00001, CCS-00-SE-CO-MS-00004, 3

CCS-00-SE-CO-MS-00005) 4

SCE’s forecast for the specialized equipment for MSO is budget-based and considers the 5

age and condition of the equipment. Recorded amounts for the specialized equipment capital 6

expenditures for Customer Service are shown in Table III-27. Specialized equipment items forecast 7

from 2013 through 2017 are described in the sections that follow. 8

Table III-27 MSO Specialized Equipment

Recorded 2008-2012 and Forecast 2013-2017 (Nominal $ 000s)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Specialized Equipment $ 390 $ 117 $ 967 $ 196 $ 31 $ 307 $ 314 $ 214 $ 1,997 $ 337

Line No. Expenditure

Recorded Forecast

a) Hand-Held Meter Interrogation Devices 9

Before ESC deployment, meter readers used an Itron G5 electronic hand-held 10

computer system device to record meter information and unusual or unexpected conditions, such as 11

broken or damaged equipment encountered in the field. With the deployment of ESC meters, these 12

devices are obsolete. FSRs need new Electric Metering Services (EMS) devices to interrogate smart 13

meters. EMS devices were purchased to continue to provide FSRs the capability of interrogating both 14

legacy meter (including these used by opt-out customers) and smart meters that cannot be read over the 15

air. This tool is mobile and provides FSRs with the ability to collect the reads in a safe and reliable 16

manner. These tools were initially purchased within the ESCBA in 2012, have a three-year warranty 17

period, and need to be replaced similar to other computing devices. SCE is planning to utilize these 18

devices through 2016, which will extend the use of the devices for up to five years. After five years of 19

extended usage, the devices will need to be replaced to maintain the current technology of both the 20

operating system and metering tools as well as prevent the end of its useful life. The replacement 21

devices are expected to cost approximately $4,447 dollars per unit with one device required for each of 22

the 400 FSRs resulting in a 2016 forecast expenditure of $1.8 million. 23

67

b) Tool Kits 1

Meter technician tool kits are comprised of equipment needed by field meter 2

technicians to perform their duties, including testing and troubleshooting meters during installation and 3

verifying integrity of service. New tool kits are needed for new field meter technicians, and replacement 4

kits are needed to replenish aging equipment. The capital expenditure forecast is approximately 5

$200,000 for each year 2013 through 2016 and $337,000 in 2017, for a total of $1.2 million over the 6

five-year period. 7

c) Temperature Cycle Chambers 8

The Meter Shop requires temperature cycle chambers to perform accelerated 9

stress testing for product reliability, which is applied to electronic metering equipment and is performed 10

to identify design weaknesses. This testing method greatly reduces the probability of in-service failures 11

(i.e., SCE works with the manufacturer to correct any faults it finds with the product) and decreases 12

costs associated with maintenance or the replacement of design failures. 13

The Meter Shop has four temperature cycle chambers that have a six-year 14

lifecycle. With the deployment of the ESC program, these chambers are being utilized on a constant 15

basis, producing even more wear on the chambers. The chambers are past their useful life and are being 16

repaired frequently. MSO Engineering uses these chambers to simulate environmental conditions such 17

as extreme heat, cold, and humidity. Based on the chamber results, MSO Engineering can validate a 18

vendor’s claim of product performance and ensure that meter products are robust enough to be safely 19

installed in SCE’s distribution system. The capital expenditure forecast is approximately $100,000 in 20

both 2013 and 2014 for the purchase of one temperature cycle chamber in each year, respectively. 21

4. Structures and Improvements (CCS-00-SI-CO-MS-00001) 22

a) Meter Shop 23

The Structures and Improvements forecast includes upgrades for the Meter Shop’s 24

training room, training equipment, and test stations that will need to be redesigned, updated, and 25

expanded to properly train staff on the new and emerging technologies that our field employees are 26

expected to be familiar with including HAN-enabled devices. This training room will also be utilized 27

for general training purposes such as safety awareness for the Meter Shop. Table III-28 below shows 28

the recorded expenditures for 2008-2012 and the forecast expenditures of $715,000 in 2013 and 29

$775,000 in 2014. 30

68

Table III-28 Structures and Improvements Expenditure Forecast

(Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Meter Shop $ - $ 674 $ 849 $ - $ - $ 715 $ 775 $ - $ - $ - 2 Total Structures and Improvements $ - $ 674 $ 849 $ - $ - $ 715 $ 775 $ - $ - $ -

Line No Expenditure

Recorded Forecast

69

IV. 1

REVENUE SERVICES ORGANIZATION (RSO) 2

RSO is comprised of operational, management, and support personnel who are responsible for all 3

billing, payment, credit and collection activities, and program operations. RSO also has postage 4

oversight for over 53 million billing statements, notices, reminders, and other correspondence issued 5

each year to customers. 6

In the process of providing accurate and timely billing for our 4.9 million customers, RSO’s 7

activities include operational oversight for bills sent to all customers, validation and exception 8

processing of interval usage data, exception billing for all residential and non-residential customers, and 9

operationalization of regulatory initiatives and activities that impact the routine customer energy usage 10

validation, billing, and credit processes. Credit and Payment activities are directed at keeping SCE’s 11

uncollectible expense as low as possible by establishing and implementing credit and payment policies 12

and practices designed to prevent service disconnections by providing the customer with convenient and 13

flexible payment options. Program Services activities include program operations for various customer 14

engagement utility products and programs across SCE. 15

RSO is responsible for two technology initiatives needed to enable dynamic pricing and other 16

recently developed products and services. These technology initiatives are (1) the operation of the new 17

Meter Data Management System (MDMS) and (2) the policy and implementation of the ESC-enabled 18

Remote Service Switch (RSS) for credit-related disconnections and reconnections. MDMS provides the 19

platform that enables Dynamic Pricing and demand response programs. RSS has made SCE’s credit 20

disconnection and reconnection practices more efficient, resulting in the elimination of the Field 21

Assignment Charge and a significant reduction in the Reconnection Charge, as provided for in SCE’s 22

2012 GRC Decision.25 23

A. Description of the Revenue Services Organization Functions 24

In support of the Energy Solutions component of SCE’s Customer Service Model described in 25

Volume 1 of this exhibit, this chapter will describe each of RSO’s four major functional areas: Billing, 26

Credit and Payment Services, Postage, and Uncollectible Expense. The analysis of historical data, the 27

Test Year estimating method, and the future year adjustments made to arrive at the Test Year forecasts 28

for the Revenue Services accounts will be addressed in each of the following sections. 29

25 See D.12-11-051 at p. 378.

70

1. Billing Services [FERC Account 903.500] 1

a) Description of Billing Function 2

The RSO Billing group provides timely and accurate billing services to SCE’s 4.9 3

million customers. This organization manages, maintains, and supports the customer usage and billing 4

processes and program operations. ESC metering has brought new opportunities to our customers. 5

Interval data and billing provide more accurate data to our customers and offers new programs available 6

for customers to better manage their energy usage. In 2012, SCE issued over 55 million customer 7

billing statements. In addition to the accounts routinely billed through SCE’s Customer Service System 8

(CSS), SCE has approximately 1,350 accounts that require manual, complex processing, largely as a 9

result of new rates or rate structure changes. In total, RSO processes almost two million customer 10

energy usage and billing exceptions annually. SCE’s costs related to billing Policy Adjustments are 11

included with the Test Year forecast for this FERC account and will be addressed as part of the Analysis 12

of Historical Data for this account. 13

(1) Energy Usage and Billing Process Oversight 14

Routine oversight of the energy usage and billing process is comprised of 15

usage validation, bill calculation, bill consolidation, and bill delivery. This function includes monitoring 16

current quality control processes for regulatory compliance and billing accuracy. Additionally, this 17

group performs process improvement analysis to reduce failure points and maintain efficiency within the 18

usage validation and customer billing processes. Random sampling of bills and notices is conducted on 19

a regular basis to verify accuracy and timeliness. When errors are found, this group identifies the causes 20

of billing errors and makes changes to billing operations, procedures, and/or systems, to avoid similar 21

errors in the future. When customers are not billed in a timely manner, operational areas are alerted to 22

analyze the root causes of usage and billing delays. Billing also has oversight of SCE’s Service 23

Guarantees related to the accuracy and timeliness of customers’ first bills. 24

Oversight for electronic billing options, such as Electronic Data 25

Interchange, CheckFree, and SCE.com are also monitored by the Billing group. Customers have the 26

option to select the manner in which they receive their monthly statement. In addition, SCE provides 27

enlarged bill formats on a recurring basis after receiving a customer request. As authorized in SCE’s 28

2012 GRC, RSO is in the process of automating the enlarged bill format and will be adding a Braille 29

billing option beginning in 2014. 30

71

Billing usage analysis has increased in complexity as a result of advanced 1

tariffs and demand response programs that use interval usage data provided by ESC meters. These new 2

dynamic pricing programs and new demand response programs enabled by ESC were available for 30.8 3

percent of SCE customers at the start of 2012 and for 98.5 percent of SCE customers at the end of 4

2012.26 The large increase in interval recording meters has resulted in increased quantities of complex 5

energy usage exceptions and more personalized rate analyses. 6

(2) Billing Exception Processing 7

Calculating and delivering the vast majority of bills is a highly automated 8

process requiring little or no manual intervention. However, given that approximately 250,000 billing 9

accounts are being processed daily and the large quantity of interval usage data involved in the process, 10

even a very small percentage of missing or out-of-tolerance data results in a considerable level of labor- 11

intensive attention. It is important that the Billing group processes all exceptions timely and accurately 12

so customers can benefit from their interval usage data, receive timely and accurate bills, and take 13

advantage of the various demand response programs and rates that SCE offers. These exceptions are 14

reviewed, analyzed, and corrected by the interval usage and the customer billing exception processing 15

groups, which comprise the largest portion of the Billing organization. These two groups are 16

responsible for the accuracy and timeliness of customer billing activities and for initiating corrective 17

action as necessary. 18

Prior to the availability of interval usage data, the customer billing 19

exception process only had to handle one monthly cumulative meter read per month for most accounts. 20

With the availability of 15-minute and hourly interval usage data being downloaded daily from nearly 21

five million ESC meters, a new dimension has been added to the billing exception process. Billing 22

exception processing now takes place at four distinct levels: (1) the “Interval Usage Data Collection and 23

Validation” exception process includes Real Time Energy Metering (RTEM) which has been processed 24

through the Customer Data Acquisition System (CDAS) over the last twenty years, (2) Interval data 25

retrieved from ESC meters is managed by the recently established Meter Data Management System 26

(MDMS) group, (3) the “Customer Billing” exception process deals with an array of other factors (aside 27

from interval usage) that can affect the accuracy and timeliness of issuing nearly five million bills every 28

26 See Table IV-33 for more information on availability of billing data for 2012.

72

month, and (4) the Manual Billing processes required for new and complex rate options. These four 1

levels of exception processing are described further in the following sections. 2

(a) Real Time Energy Metering (RTEM) and the Customer Data 3

Acquisition System (CDAS) 4

Prior to deployment of ESC and the MDMS, the availability of 5

interval usage data was limited to SCE’s largest customers (over 200 kW), using Real Time Energy 6

Metering (RTEM) and to those customers billed on voluntary time-of-use (TOU) rates and Net Energy 7

Metered (NEM) rates, who were billed using Interval Data Recorder (IDR) meters. While most of the 8

IDR-metered customers now have ESC meters, approximately 18,000 of SCE’s largest customers 9

continue to be metered by RTEM meters. The RTEM-metered data is processed through the Customer 10

Data Acquisition System (CDAS). CDAS is the precursor of the MDMS and has been in operation for 11

over 20 years. 12

(b) Usage Data Exceptions and the Data Validation Process – 13

MDMS 14

The MDMS performs the first critical review of interval usage data 15

accessed from the ESC meters to assure that a complete set of 15-minute or hourly interval data is 16

available for billing at the end of each service account’s monthly billing cycle. The automated system 17

includes validations that are set to ensure accurate billing components and accurate usage calculation. 18

Validations are set to identify any missing data that may occur due to meter or communication system 19

lapses or failures, out-of-tolerance data that may occur because of incomplete or inaccurate meter 20

records, meter changes, or potential tampering. When an otherwise “routine” bill fails to meet system 21

validation routines, an “exception” is generated, requiring follow-up processing. These usage 22

exceptions are routed to MDMS personnel for resolution and processing. 23

(c) Customer Billing Exception Processing 24

The Customer Billing exception process deals with factors that are 25

outside of the initial usage exception processes described above. Non-routine circumstances—such as 26

partial month bills, rate changes, and significant changes in consumption—trigger an exception process 27

that requires further review by customer billing personnel. These types of exceptions are typically 28

generated by the Customer Service System (CSS). Before ESC metering and the MDMS, this was the 29

only level of billing exception processing needed for the vast majority of SCE’s customer accounts. 30

With ESC metering and MDMS, more complete and accurate data is now available at this second level 31

73

of exception processing, thus relieving some aspects of the workload. On the other hand, new complex 1

rates and the advent of dynamic pricing has increased the volume of rate changes and meter changes due 2

to data requirements, resulting in more non-routine exception processing. 3

(d) Complex Rates and the Manual Billing Processes 4

Although the vast majority of customer bills are generated 5

automatically, there is an ongoing need for manual billing processes to bill customers on new, complex, 6

or special contract rates that are not programmed into the customer billing system. Generally, newly 7

mandated, complex, or special contract rates affect only a small portion of the customer population, 8

currently consisting of approximately 1,350 accounts. Manual processing allows for the timely 9

implementation of new mandated rates for an interim period, while a determination is made regarding 10

cost and feasibility of automation. Existing complex or special contract rates, for which it has been 11

determined that automation is either too complex or not cost-effective, will continue to require ongoing 12

manual processing. 13

(3) Program Services 14

Program Services (PS) operations partners closely with Customer 15

Programs (SCE-04, Vol. 3) and provides operational oversight for various customer engagement utility 16

products and programs across SCE. Medical Baseline, Home Area Network (HAN), and Budget 17

Assistant are GRC-funded programs processed by PS operations. Table IV-29 below shows the number 18

of enrollments performed by PS for the last five years for these programs. 19

Table IV-29 Program Services Historical Enrollment Volume

2008 – 2012

Line No. Program 2008 2009 2010 2011 2012

1 Medical Baseline 35,421 47,057 44,946 55,673 73,787 2 HAN N/A N/A N/A N/A 500

3 Budget Assistant N/A N/A N/A 118,848 119,626

For the programs listed above, PS operations includes rebate processing, 20

program enrollment, reject (incomplete) application processing, technical review, audit activities, quality 21

control, enhanced customer communication, customer notifications, system maintenance, system 22

enhancements, and reporting. 23

74

(4) Project Management 1

Project managers and analysts are responsible for the entire 2

implementation of billing-related projects, including the modification of existing rate schedules and the 3

implementation of new rate schedules and programs mandated by regulatory decisions and system 4

process improvements. The Project Management group is essential to the successful implementation of 5

regulatory-directed programs affecting billing and the overall performance of Revenue Services. The 6

Project Management group also manages the development and prioritization of business requirements 7

for improvement. 8

(5) Policy Adjustments 9

Policy adjustments for customers’ bills are initiated by representatives in 10

Billing, Credit, Customer Contact Center, Consumer Affairs, and the Business Customer Division to 11

resolve customer disputes and company-initiated adjustments related to billing errors or inconsistencies. 12

Typically, such disputes may result from meter and/or billing errors, differences relating to service 13

establishment dates, and settlements on unresolved billing complaints or issues. RSO is responsible for 14

administering the Policy Adjustment process to warrant fair and consistent treatment of each situation 15

based on the specific circumstances. 16

b) 2012 Operating Results - Billing 17

(1) Billing Performance Measures 18

The measurement of the amount of Revenue Billed on Time, Customers 19

Billed on Time, Bills Prepared Accurately, and Estimated Bills continues to be important to the overall 20

Billing operational effectiveness. Together, these four measures allow RSO to ensure that our customers 21

are being billed in a timely and accurate manner and that one measurement does not improve at the 22

expense of the others. Performance measurements are equally important. The results achieved from 23

2008 through 2012 are shown in Table IV-30 below. 24

75

Table IV-30 Billing Performance Measures

2008 – 2012

Line No. Description 2008 2009 2010 2011 2012 1 Revenue Billed on Time 99.8% 99.7% 99.8% 99.4% 99.3%

2 Customers Billed on Time 99.9% 99.9% 99.9% 99.7% 99.6%

3 Bills Prepared Accurately 99.4% 99.3% 99.4% 99.6% 99.7%

4 Estimated Bills 0.8% 0.8% 1.0% 1.1% 0.6%

Revenue Billed on Time measures the revenue dollars actually billed as a 1

percentage of total potential revenue that could be billed by month-end. Customers Billed on Time 2

measures the number of customers actually sent bills each month as a percentage of customers who 3

potentially could have been sent bills that month. Revenue Billed on Time performance remained 4

steady during 2008 to 2010 at 99.7 to 99.8 percent and dropped to 99.4 percent and 99.3 percent, 5

respectively, in 2011 and 2012. Similarly, the Customers Billed on Time performance remained stable 6

at 99.9 percent from 2008 through 2010 and then dropped to 99.7 percent and 99.6 percent, respectively, 7

in 2011 and 2012. The drops in 2011 and 2012, as reflected in these two performance measures 8

(Revenue Billed on Time and Customers Billed on Time), were directly attributable to the additional 9

complexity of processing interval usage data and inherent delays in processing the extremely large 10

volume of meter changes that took place in 2011 and 2012, as nearly five million new ESC meters were 11

installed and cut-over to operations (COTO).27 12

Bills Prepared Accurately performance improved to 99.6 percent in 2011 13

and 99.7 percent in 2012. Additionally, the number of Estimated Bills decreased by nearly half in 2012 14

at 0.6 percent as compared to 1.0 percent in 2010 and 1.1 percent in 2011. The high levels of 15

performance in the Bills Prepared Accurately and Estimated Bills performance measures are primarily 16

the result of more accurate and timely interval usage data coming from the new ESC meters and the 17

MDMS. This results in the ability to minimize the number of billing exceptions generated by CSS as 18

27 Cut-over to Operations (COTO) was the process (and subsequent system status) used to convert accounts to full ESC

functionality including: interval billing, eligibility for Peak Time Rebate incentives, and web presentment functionality.

76

the bills are being processed. The savings attributed to the more accurate and timely data provided by 1

ESC meters and the MDMS resulted in an estimated savings in 2012 Base Year costs of approximately 2

one million dollars and an additional Base Year adjustment of $604,000 for nonrecurring costs attributed 3

to 2015 Test Year savings.28 4

Table IV-31 below contains a historical summary of processed billing 5

exceptions, which continue to impact our resource requirements. The number of CSS-generated 6

customer billing exceptions has diminished significantly in 2011 and 2012 because many traditional 7

billing exception processes have been replaced by the MDMS system validations and automated 8

exception processing performed by the MDMS. The number of special billing exceptions has increased 9

in 2011 and 2012 because of the increase in the number of Net Energy Metered (NEM) accounts and the 10

complexity of maintaining these new rates. Meter Order Processing exceptions increased in 2012 due 11

primarily to the large volumes of meter changes during the installation phase of the new ESC meters. 12

The drop in the number of Returned Mail Exceptions resulted as SCE 13

implemented improvements to its customer address cleansing process in the fourth quarter 2011. As a 14

result of having more up-to-date information regarding forwarding addresses, annexations, and street 15

name conversions, mail pieces are being delivered with more accuracy. In addition, a system 16

implementation in the second quarter of 2011 involving the United States Postal Service’s (USPS’s) 17

Intelligent Mail Barcode (IMB) project enables some address updates to be delivered to SCE 18

electronically, eliminating the need for human intervention. The address corrections processed 19

electronically prevent return mail exceptions from occurring, thereby reducing the volume of exceptions. 20

28 See Section (1) (a) below for details.

77

Table IV-31 Billing Exceptions

2008 – 2012 (Amounts in 000s)

Line No. Exception Type 2008 2009 2010 2011 2012

1 System-Generated Exceptions 844 861 1,010 947 276

2 Special Billing Exceptions 172 154 176 207 228

3 Direct Access Exceptions 7 19 13 13 42

4 RTEM Interval Usage Exceptions 152 141 123 260 156

5 Meter Order Processing Exceptions 68 68 70 70 219

6 Returned Mail Exceptions 695 670 657 503 127

7 Total Billing Exceptions 1,938 1,913 2,049 2,000 1,048

(2) Meter Data Management System (MDMS) 1

ESC interval usage data processed through the MDMS brings new energy 2

efficiency and demand response opportunities by providing interval usage data for dynamic pricing rate 3

options, new demand response programs, and the ability of early detection related to revenue protection 4

and potential energy theft activities. While the Billing group is experiencing operational labor savings 5

due to more accurate billing data, accurate and timely completion of turn-on and turn-off orders, and 6

improved data validations, these achievements come with significant cost impacts of implementing the 7

MDMS. As we transition from collecting one monthly cumulative read per meter per month to 8

collecting 720 hourly interval usage reads per month for a typical residential meter, we are experiencing 9

significant increases in the volume of interval usage exceptions. This magnitude of change reflects an 10

exponential growth in customer usage data, resulting in a significant increase in interval usage 11

exceptions. The Usage and Billing groups review, analyze, and process these exceptions to ensure 12

accuracy of interval usage data to maintain a consistent level of service with accurate and timely bills. 13

Although the number of exceptions seems large, these exceptions 14

represent only a very small percentage of the data being processed as approximately 250,000 accounts 15

are billed each day from approximately 720 hourly intervals of usage data per account for each month. 16

Processing these interval usage exceptions requires a significant amount of manual intervention. 17

Table IV-32 below contains a quarterly historical summary of processed 18

usage exceptions, which continue to impact our resource requirements. 19

78

Table IV-32 Usage Exceptions

2011 – 2012 (Amounts in 000’s)


1 Quarter Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q42 MDMS Usage Exceptions 52 215 376 682 227 417 662 927

2011 2012

Table IV-33 below shows the quarterly progress in getting the ESC meters 1

COTO in the MDMS in 2012. As shown, the COTO total went from 1.5 million meters (30.8 percent) 2

at the end of 2011 to 4.9 million meters (98.5 percent) at the end of 2012. As discussed previously, this 3

rapid increase in MDMS processing had a significant impact on SCE’s overall billing performance 4

measures for 2012. 5

Table IV-33 ESC Meters

Cut-Over to Operations (COTO) Quarterly December 2011 – December 2012

Line No.

Description 2011 2012 2012

1 Month Dec Mar Jun Sep Dec Avg. COTO

2 ESC

Meters 1,535,584 2,105,040 2,916,206 4,121,392 4,906,367 3,151,958

3 COTO percent

30.8% 42.3% 58.6% 82.8% 98.5% 63.3%

From the first quarter of 2011, when just 24.7 percent of SCE’s meters 6

were COTO, until December 2012 as meter installations approached 98.5 percent COTO, the average 7

percent of accounts that generated exceptions daily decreased from 10.2 percent to 2.5 percent. As we 8

proceed to 100 percent steady-state operations, as shown in Figure IV-13 below, we expect to approach 9

an optimum performance level of exceptions between two percent and three percent. 10

79

Figure IV-13 ESC Meters

Exceptions vs. ESC Meters Installed

(3) Complex Rates and the Manual Billing Process 1

The Billing group is responsible for processing low volume but complex 2

billing and exceptions that are not processed automatically. These special-billing accounts generally 3

include customers billed on the most complex tariffs, service contracts, and/or metering requirements. 4

The demand for complex rates is expected to increase as customers continue to search for better ways to 5

manage their electricity consumption and their costs. In 2012, the Billing group’s manual billing efforts 6

were directed at special contract rates that require special handling. Most contract accounts fall into 7

three areas: Net Energy Metering (NEM), Wireless Technology Rate (WTR), and Departing Load (DL). 8

80

Table IV-34 below shows the number of manual billing accounts in each of these categories. A brief 1

description of each manual billing category follows the table. 2

Table IV-34 Number of Customers on Complex Rates Requiring Manual Billing

2008 – 2012

Line No.

Rate 2008 2009 2010 2011 2012

1 Net Energy Metering (manual) 63 76 236 523 123

2 Wireless Technology Rate 578 757 1,039 1,106 1,066

3 Departing Load 219 319 194 183 168

4 Total Complex Billing 860 1,152 1,469 1,812 1,357

(a) Net Energy Metering (NEM) 3

NEM accounts are for customers who have their own alternative 4

source of energy, such as wind, solar, or cogeneration. These customers are metered to record energy 5

flowing both into and out of their location, and they are billed on the net amount of energy consumed or 6

provided based on the rate in effect during each time period. 7

(b) Wireless Technology Rate (WTR) 8

WTR was designed for wireless cell phone companies to install 9

cell towers to broaden their coverage for the public. These are contract-based rates and are not metered. 10

The cell towers that qualify for this rate cannot exceed 500 kWh per month. Depending on the pre-11

established usage of the installed equipment, the customer is charged in 50 kWh incremental blocks 12

known as tiers. The first tier is 0-50 kWhs and the tenth tier is 450-500 kWh. The billing is processed 13

monthly based on the day of the month that the work order was completed. 14

(c) Departing Load (DL) 15

Former SCE customers now receiving electricity from a source 16

other than SCE are still responsible for paying SCE for the non-bypassable charges, including Nuclear 17

Decommission Charge, Public Purpose Program Charge, Customer Transition Charge, and any 18

applicable city tax. However, load that is eligible for NEM, is not considered to be part of departing 19

load. 20

81

c) Analysis of Historical Data – Billing FERC Account 903.500 1

Historical costs will be discussed separately below for two functional areas: (1) 2

Billing and (2) Policy Adjustments. These two functional areas are aggregated together for purposes of 3

forecasting FERC Account 903.500. 4

(1) Billing – Without Policy Adjustments 5

The recorded/adjusted costs shown in Table IV-35 below were derived 6

after analyzing the recorded costs and adjusting them to reflect ongoing operations for the Billing 7

function. This was accomplished by (1) removal of the non-recurring legacy costs recorded in 2012 that 8

would not exist with full deployment of ESC and 100 percent steady-state MDMS operations and (2) 9

addition of that portion of costs recorded in the ESCBA in 2012 that represented steady-state operations. 10

Various other accounting, operational, and reclassification adjustments are discussed in the workpapers 11

supporting this Volume. 12

Table IV-35 Billing (Without Policy Adjustment Expense) 2008 – 2012 Recorded and Adjusted Expenses


Line No. Category 2008 2009 2010 2011 2012

1 Labor 18,149 18,695 19,187 20,394 19,378

2 Non-Labor 2,344 2,114 3,358 3,046 1,700

3 Other 0 0 0 0 0

4 Total 20,493 20,809 22,545 23,440 21,078

(a) Removal of Nonrecurring Legacy Costs 13

The MDMS is expected to deliver $1.646 million in ESC benefits 14

by the 2015 Test Year as more accurate and timely billing data becomes available. Because the MDMS 15

was only 63.3 percent operational on average in 2012, only 63.3 percent of this benefit (or $1.042 16

million) was actually realized in 2012. The remaining 36.7 percent (or $604,000) of these benefits will 17

be realized in future years. Thus, some of the costs that were recorded as O&M in 2012 are 18

nonrecurring, legacy costs that will no longer be incurred once the MDMS becomes fully operational. 19

82

These benefits have been accounted for as nonrecurring costs in 2012 by removing the remaining 36.7 1

percent of the total $1.65 million benefit from the 2012 Base Year recorded cost for FERC Account 2

903.500. 3

To account for the nonrecurring legacy costs that were recorded in 4

2012 (i.e., an unrealized future benefit), the 2012 Base-Year recorded costs were reduced by $604,000.29 5

The nonrecurring costs for 2012 were calculated as follows: 6

Savings attributed to more accurate billing data and timely 7

completion of turn-on and turn-off orders was estimated to be 8

$1.646 million per year at full ongoing steady-state deployment 9

of ESC meters. 30 10

Since only 63.3 percent of meters were COTO on average in 11

2012, the remaining 36.7 percent of the benefit was not yet 12

reflected in the recorded cost for 2012. 13

Thus, 36.7 percent of $1.646 million, or $604,000, was considered 14

to be a nonrecurring cost recorded in 2012. 15

(b) Addition of Ongoing Steady-State costs recorded in the 16

ESCBA 17

Because all ESC incremental costs were recorded in the ESCBA in 18

2012, the steady-state cost portion of MDMS operations in 2012 is not included in recorded O&M in 19

FERC Account 903.500. To account for the steady-state costs incurred in 2012, the 2012 Base Year 20

recorded O&M costs were increased by $4.027 million. This adjustment includes 63.3 percent of 21

MDMS costs, or $3.548 million, that was charged to the ESCBA as “steady-state” costs, as opposed to 22

“one-time” start-up costs. In addition, 100 percent of the Program Services (PS) costs ($383,427) 23

charged to the ESCBA and 100 percent of Operations Support (OS) costs ($95,176) were entirely related 24

to new ESC operations and were not one-time/start-up related costs. These last two functions are 25

entirely related to ongoing steady-state activities related to the ESC systems and programs that will 26

continue into the 2015 Test Year and beyond. The steady-state adjustments to the 2012 recorded data 27

were calculated as follows: 28

29 The derivation of the base year and future year adjustments are shown in the workpapers.

30 As forecast in SCE’s 2012 General Rate Case, Exhibit SCE-04, Vol. II, p. 161, $1.5 million escalated to 2012 dollars.

83

Total MDMS charges to the ESCBA in 2012 was $5.605 1

million. 2

On average, in 2012, 63.3 percent of SCE’s meters were 3

COTO. See Table IV-33 above. ($5.605 x 0.633 = $3.548 4

million) 5

Plus 100 percent of PS cost of $383,000 and 100 percent of 6

Operations Support costs of $95,000. 7

Thus, $3.548 + $0.383 + $0.095= $4.027 million. 8

(c) Historical Year to Year Variances 9

Labor expenses increased $1.039 million from 2008 to 2010 10

because of customer growth and increased rate complexity. Year-to-year labor and non-labor variances 11

are impacted by new regulatory mandates and their effect on the collection of interval usage data, usage 12

validations, and customer billing processes. Implementing new regulatory mandates on a timely basis 13

often requires additional labor. Non-labor expenses include the system and programming support costs 14

needed to implement and maintain new and more complex rate structures. Non-labor expenses declined 15

in 2009 because of a decrease in new billing systems enhancements and contract support required for 16

operational activities. After implementation, the work in support of regulatory mandates is integrated 17

into our automated interval usage validation and billing processes and results in higher non-labor 18

expenses as reflected the $1.245 million increase in 2010 non-labor recorded cost. 19

Beginning in 2011, as ESC meters started to become operational, 20

traditional legacy labor costs began to decrease as a significant portion of the billing exception process 21

was being transferred to the MDMS, and the cost of that work increased as recorded in the ESCBA. As 22

the MDMS progressed from 30.8 percent operational at the end of 2011 to 98.5 percent operational at 23

the end of 2012, the costs of the legacy billing exception process diminished accordingly, and the level 24

of steady-state costs being recorded in the ESCBA increased accordingly. 25

(2) Recorded and Adjusted Policy Adjustments 26

The 2008-2012 recorded/adjusted expenses for Policy Adjustments are 27

shown in Table IV-36 below. Year-to-year comparisons of policy adjustments tend to vary, usually due 28

to several large adjustments in any given year. There were eight policy adjustments over $10,000 in 29

2008 and seven policy adjustments over $10,000 in 2009, two of which were over $100,000. In 2010 30

and 2011, there were only four policy adjustments and three policy adjustments over $10,000, 31

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respectively. In 2012, there were six policy adjustments over $10,000 and one policy adjustment over 1

$100,000. In addition, in 2012, several policy adjustments resulted from the implementation of new, 2

complex rates. As SCE’s large customers begin to accept new, more complex rates, the 2012 results 3

will be more typical of what may be expected for future year policy adjustments. 4

Table IV-36 Policy Adjustments (Without Billing Expenses) 2008 – 2012 Recorded and Adjusted Expenses


Line No. Category 2008 2009 2010 2011 2012

1 Labor 0 0 0 0 0

2 Non-Labor 2 (1) 0 0 0

3 Other 544 526 238 224 657

4 Total 546 525 238 224 657

d) Test Year Operating Expectations –FERC Account 903.500 5

Figure IV-14 below shows the adjusted / recorded historical and forecast expenses 6

for the Billing function. Details regarding the forecast O&M expenses for this function are described 7

below. 8

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Figure IV-14 Billing

FERC Account 903.500 2008 – 2015 Adjusted / Recorded and Forecast Expenses





The FERC 903.500 Billing Account was forecast in two components: (1) 4

the Billing component ($21.078 million), representing approximately 97 percent of the cost recorded in 5

this account in 2012, was forecast using the 2012 adjusted and recorded Base Year Expense as the 6

starting point, adding incremental costs and savings for each forecast year, to reach the 2015 Test Year 7

forecast; and (2) the Policy Adjustment component ($657,000), representing only three percent of the 8

cost recorded in this account in 2012, was forecast using the five-year recorded average ($438,000) from 9

2008 to 2012. The rationale used to forecast these two components is presented in the following 10

sections. 11

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(a) Billing 1

Because of the influence ESC has had on billing operations 2

beginning in 2011, recorded costs prior to 2012 are not representative of future expectations and thus 3

were not suitable to support historical averages or trends to forecast future costs. Instead, recorded and 4

adjusted O&M costs for 2012 were used as the basis for forecasting future costs by adding a downward 5

adjustment for non-recurring legacy costs (i.e., future benefits) and an upward adjustment for 6

incremental steady-state MDMS, PS, and OS costs that were charged to the ESCBA in 2012. 7

With the above described adjustments to the 2012 Base Year 8

recorded levels, the 2012 adjusted/recorded cost was used as the base to which future adjustments were 9

made to forecast Test Year Billing costs. Figure IV-14 above shows the last five years of recorded costs 10

for the Billing component of FERC Account 903.500 and the 2015 Test Year Forecast with the 11

adjustments described in the following Section. The future cost adjustments were added or subtracted in 12

the increments discussed below and as shown in workpapers. 13

(b) Policy Adjustments 14

In light of the year-to-year variances attributed to large policy 15

adjustments in any given year, and because one adjustment in 2012 was larger than what usually occurs 16

in any given year, neither the last year recorded expense nor the five-year trend was an appropriate 17

indicator of future year expenses for this account. Instead, the five-year average of $438,000 was used 18

to forecast the 2015 Test Year expense for the Policy Adjustment component of Billing expenses. This 19

is the “Other” category component of the FERC 903.500 aggregated account, and the Customer Growth 20

adjustment was not applied to this component of the aggregated account. 21

(c) Service Guarantee – Timely and Accurate First Bill 22

SCE’s First Bill service guarantee states that SCE will issue an 23

accurate bill to every customer within 60 days of establishing service on a new customer account. SCE 24

pays a $30 credit for every time that it does not meet this standard. SCE “self-reports” this performance 25

and automatically processes claims for each customer for whom this standard is not met. Table IV-37 26

below shows the First Bill service guarantee credits SCE paid from 2008 through 2012. Out of 27

approximately 1.1 million first bills issued in 2012, there were 5,887 occurrences of not meeting this 28

service goal. This represents less than one percent of all first bills. SCE issued over 99 percent of 29

timely and accurate first bills in every year from 2008 through 2012. 30

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Table IV-37 Timely and Accurate First Bill – Service Guarantee

2008 – 2012

As the information in Chapter I Section D. of this Volume 1

demonstrates, our performance in the area of billing timeliness and accuracy has remained steady over 2

the last five years. Our billing timeliness and accuracy has consistently been above 99 percent. The 3

slight drop in 2012 from 99.56 percent to 99.60 percent is attributed to the transition of the Billing 4

Exception process over to the MDMS. That transition is now complete and future performance is 5

expected to exceed past performance relating to this service guarantee. We continue to maintain our 6

performance in billing timeliness and accuracy and understand that our systems are not built for absolute 7

perfection. 8

SCE has included a Program Change adjustment in the forecast for 9

this account. The five year average of credits (i.e., $164,000) has been included as the base level of First 10

Bill service guarantee credits to be allowed in rates. These expenses are part of the FERC Account 11

903.500 forecast for the 2015 Test Year as described in Section (4) (c) below. 12


Figure IV-15 below illustrates the relative levels of the 2012 Base Year 14

expense to the 2015 Test Year forecast and the adjustment components used to arrive at the forecast cost 15

for SCE’s Billing operations in 2015. 16

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Figure IV-15 Billing Comparison of 2012 Base Year to 2015 Test Year


(a) ESC Incremental Steady-State Cost Forecast – Billing 1

The only incremental ESC costs expected to occur in the 2015 Test 2

Year, in excess of the costs added to the 2012 Base Year, are the incremental MDMS steady-state 3

exception processing costs that exceeded those already allocated to the 2012 Base Year recorded cost. 4

As shown previously in Table IV-33, the MDMS process had reached the 98.5 percent COTO level at 5

the end of 2012. At the same time, the volume of exceptions being processed leveled out at between 6

two percent and three percent of the accounts being billed daily. This two to three percent exception 7

rate is expected to be the steady-state level that will carry into the 2015 Test Year; the MDMS labor 8

expenses throughout 2012 remained relatively constant. On average, in 2012, the MDMS was only 63.3 9

percent operational. Thus, the $3.548 million in steady-state costs recorded in the ESCBA in 2012 was 10

only 63.3 percent of the $5.605 million total steady-state costs that is expected to occur under full 11

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steady-state operations in the 2015 Test Year. A 2015 Test Year adjustment of $2.057 million ($5.605 - 1

$3.548 million) was made to account for the added cost of the remaining 36.7 percent of full steady-state 2

MDMS operations in 2015. 3

(3) Customer Growth 4

The number of customers served in SCE’s service territory is expected to 5

increase by 2.06 percent from 2012 to 2015. The Billing group is directly impacted by customer growth 6

as more meter data is processed, more bills will be generated to new customers, creating additional 7

routine operational work in usage and billing process oversight, exception processing and manual 8

billing. While meeting this added workload the Billing group expects to continue maintaining high 9

performance with timely and accurate billing to our customers. To reflect the cost impact that customer 10

growth will have on the volume of billing related processes will have on cost, an adjustment of $435,000 11

(2.06 percent) was applied to the labor and non-labor components of the 2012 Base Year 12

adjusted/recorded costs. 13

(4) Program Changes 14

There are five Billing related program changes in the forecast for FERC 15

903.500. Three are in Program Services operations, one is for Braille and Enlarged Font billing option, 16

and one is related to Service Guarantees. 17

(a) Program Services 18

Program Services (PS) operations processes customer program 19

applications, field work orders, troubleshooting activities, and quality control to manage customer 20

program enrollments and rebate processing. PS also performs maintenance and system enhancements 21

with the systems used to process customer enrollments. Table IV-38 below shows the forecast customer 22

enrollment volume by program for the years 2013 – 2017. 23

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Table IV-38 Program Services Projected Enrollment Volumes

2013-2017

Line No. Year

Medical Baseline HAN

Budget Assistant

Lifestyle Packages

1 2013 67,201 10,500 120,693 29,400 2 2014 73,264 23,500 143,551 13,440 3 2015 79,878 33,136 2,500 9,677 4 2016 87,093 38,665 2,500 N/A 5 2017 94,966 46,436 2,500 N/A

The increased customer participation in these programs will 1

increase forecast expense as described below. 2

(i) Medical Baseline 3

PS forecasts incremental funding of $250,000 to support 4

incremental processing operations related to program enrollment, increasing program enrollment volume 5

and enhanced customer notification around customer application status and results. PS activities in 6

support of the program include: application processing, customer enrollment, customer renewals, 7

updating agreements, application rejection, enhanced customer support (customer communication and 8

outreach), quality control, audit support, system maintenance, system enhancements, and reporting. 9

(ii) Home Area Network (HAN) 10

In support of the Energy Solutions component of the 11

Customer Service Model described in Volume 1 of this Exhibit, PS forecasts incremental funding of 12

$515,000 to support incremental volume increases in program enrollment and troubleshooting customer 13

connectivity issues between meter and HAN device. PS activities in support of the program include: 14

application processing, customer enrollment, application rejection, enhanced customer support 15

(customer communication and outreach) and issue resolution, troubleshooting, quality control, audit 16

support, system maintenance, system enhancements, and reporting. 17

(iii) Lifestyle Package 18

In support of the Energy Solutions component of the 19

Customer Service Model described in Volume 1 of this Exhibit, Lifestyle Packages is an incremental 20

program to PS beginning 2013. PS forecasts incremental funding of $79,000 to support customer 21

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enrollments in customer Lifestyle Packages as PS is projected to enroll one-third of the total enrollments 1

for the program. PS activities in support of the program include: application processing, customer 2

enrollment across various products and programs, customer care, application rejection, enhanced 3

customer support (customer communication and outreach), quality control, audit support, system 4

maintenance, system enhancements, and reporting. 5

(b) Braille and Enlarged Font Billing 6

Billing costs related to implementation of the Braille and enlarged 7

font billing preparations are forecast to total $53,000 by 2015. That amount has been added to the 2015 8

Test Year forecast as a Program Change. 9

(c) Service Guarantee 10

RSO forecasts incremental funding of $173,000 for SCE’s Service 11

Guarantee program. This includes service guarantees for both missed appointments ($9,000) and timely 12

and accurate first bills ($164,000) as discussed in Chapters I, III and IV of this Volume. 13

(5) Productivity Operational Excellence 14

(a) Operational Excellence 15

The Billing group expects to decrease $2.554 million in various 16

support activities and streamlining several exception processing events. These actions will include 17

processing work more efficiently and effectively without adding additional costs in the future or having 18

an adverse effect on our current billing performance measures. Some activities are currently in progress, 19

and will be fully implemented by 2015. 20

(b) Other Productivity – Program Services 21

PS forecasts an incremental decrease of $246,000 from the 2012 22

Base Year costs in the Budget Assistant Program. PS is reducing the incremental costs needed due to 23

significant decreases in volume levels beginning in 2015 driven by increased use of self-service 24

enrollment channels. PS activities in support of the program include application processing, customer 25

enrollment, application rejection, enhanced customer support (customer communication and outreach), 26

quality control, audit support, system maintenance, system enhancements and reporting. 27

(6) Forecast Method 28

A downward adjustment of $219,000 was made from the recorded Base 29

Year level for the Policy Adjustment component of this account. This adjustment was equal to the 30

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difference between the 2012 Base Year recorded expense of $657,000 and the five-year average of 1

$438,000 which was the method used to forecast the Policy Adjustment component. 2

2. Credit and Payment Services [FERC Account 903.200] 3

The Credit group and Payment Services group work hand-in-hand to manage customer 4

receivables and keep SCE’s uncollectible expense as low as possible by establishing and providing 5

convenient payment options, and implementing credit and payment policies and practices designed to 6

prevent service disconnections. The Credit group establishes, maintains, and enforces credit policies 7

and practices, while the Payment Services group strives to assist customers in making their payments on 8

time by providing numerous convenient payment options. Currently, SCE customers can pay their 9

electric bill through the mail, in person through an APA or Rural Office, or by utilizing one of seven 10

electronic payment options. 11

a) Description of the Credit Functions 12

SCE’s Credit functions involve activities performed daily by Customer Service 13

Representatives (CSRs) in the Customer Contact Center (CCC) and in SCE’s Rural Offices, Field 14

Services personnel located throughout SCE’s service area, and Customer Assistance programs 15

administered by SCE’s Consumer Affairs Organization. It also now includes the Company’s policies 16

and practices related to the RSS components of the ESC system. 17

The credit function in the utility industry is unique in that there is a delay, on 18

average, of 80 to 90 days from the time service is rendered until disconnection can take place.31 19

Typically, residential customers disconnected for nonpayment will owe SCE the cost of nearly three 20

months’ worth of service. With the recent, more lenient credit practices and disconnect policies 21

established in the Residential Disconnect OIR proceeding,32 this typical process flow timeline has 22

increased to a minimum of 180 days for residential customers that take advantage of the extended 23

payment arrangements. In 2012, there were approximately 200,000 residential customers and 22,000 24

non-residential customers disconnected for nonpayment. Although 74 percent of these disconnected 25

residential customers were able to reestablish service same day by bringing their past due arrears 26

31 A description of SCE’s credit and disconnect process flow and time-line is contained in workpapers.

32 Order Instituting Rulemaking to Establish Ways to Improve Customer Notification and Education to Decrease the Number of Gas and Electric Utility Service Disconnections (R.10-02-005).

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current,33 SCE’s uncollectible expense for 2012 was still $29.9 million as reflected in Table IV-53 in 1

FERC 904. 2

In general, the credit process consists of policy development and enforcement, 3

customer verification, fraud prevention, customer risk assessment, collection activities, and the overall 4

management of credit-related operations to minimize arrearages and uncollectible expense. A primary 5

goal of the Credit group is to mitigate loss of revenue by acquiring adequate security for newly 6

established and higher risk existing accounts and to pursue collection of unpaid balances. These 7

processes have been prescribed by the Commission and provided for in accordance with SCE’s 8

established tariffs, specifically Rules 6 and 7. 9

(1) Credit Risk Assessment 10

The credit risk assessment function begins with the identification of 11

customers “at risk” of non-payment to prevent uncollectible expense. This process occurs when a new 12

applicant applies for service. The new customer risk assessment includes obtaining positive 13

identification in the form of a social security number and a credit score that is based upon the customer’s 14

individual credit history. This process is used to determine whether a security deposit is required to 15

establish credit and also to prevent identity theft in compliance with the Red Flag Rules.34 Once an 16

assessment is completed, higher-risk customers are secured by selecting various forms of approved 17

securities, such as cash and non-cash deposits, enrollment in Direct Pay, and payment guarantees. For 18

large commercial accounts, the Credit group conducts a financial analysis at the time a new service is 19

established and continues to monitor their financial status on a regular basis for any material change. 20

Analyses consist of publicly available financial statements and credit scores to determine credit 21

worthiness. If there is a material change in the customers’ financial or credit status, the Credit group 22

will negotiate security either by cash deposit or non-cash security options. 23

(2) Collection Activities 24

Collection activities include tracking, monitoring, and follow-up action on 25

delinquent active and closed accounts. In addition to written notifications, SCE's Interactive Voice 26

Response (IVR) capability in the CCC provides outbound “final call” notifications to our delinquent 27

33 86 percent of disconnected residential customers reconnect within 30-days of disconnection for nonpayment.

34 In 2008, as a result of the Fair and Accurate Credit Transaction Act (FACTA), SCE developed a program that identifies and detects relevant warning signs.

94

customers. SCE’s goal is to collect delinquent revenue while helping customers avoid disconnection. 1

SCE has a number of options to help customers avoid disconnection, such as meaningful customer 2

contact and communication, energy conservation education, outreach programs, bill payment assistance, 3

and financial assistance. Additionally, customers who fail to pay a closing bill on time may be subject 4

to credit bureau placement, which results in a negative attribute on their credit file. Unpaid closed 5

account balances remain visible when a customer attempts to reestablish service with SCE and the 6

Credit group continues to monitor these balances to attempt collection. Closed account collection 7

activities include a manual and automated skip-trace process, credit bureau placement, and contracted 8

agencies to collect unpaid balances. 9

(a) Commission Policy on Credit Related Disconnects 10

In late 2009, the Commission ordered a moratorium halting credit 11

disconnections for residential customers and to encourage utilities to expand their efforts to help 12

customers to set up a payment arrangement or obtain a payment extension. Concerned about the 13

economic crisis in California and an increase in residential utility service disconnections, on February 5, 14

2010, the Commission initiated an Order Instituting Rulemaking (OIR) to reduce the number of 15

residential gas and electric service disconnections due to nonpayment and to identify best practices to 16

reduce customer disconnections.35 As a result, the Commission required PG&E, SoCalGas, SDG&E 17

and SCE to immediately implement three interim practices:36 18

1. CSRs must inform residential customers at risk for 19

disconnection of their right to arrange a bill payment plan 20

extending for a minimum of three months and up to 12 months 21

based on the circumstances. 22

2. Once a residential customer has established credit, the utility 23

must not require that customer to pay additional 24

reestablishment of credit deposits with the utility for either 25

slow-payment/no-payment of bills or following a 26

disconnection. 27

35 R.10-02-005, pp. 1-3.

36 R.10-02-005, pp. 16-17.

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3. Utilities were authorized to establish memorandum accounts 1

using Tier 1 Advice Letters (AL) to track any significant 2

additional costs, including operations and maintenance charges 3

associated with implementing the customer practices and any 4

uncollectible expenses that exceed those projected in the 5

utility’s last general rate case. 6

(i) Residential Disconnection OIR Phase I Decision 7

In the Phase 1 decision in this OIR, the Commission 8

provided various other protections for California Alternate Rates for Energy (CARE) customers. 37 In 9

addition to the measures implemented in February 2010, the following practices were introduced in 10

October 2010: 11

1. Narrowed the scope from “all residential” to “all 12

CARE and Family Electric Rate Assistance 13

(FERA)” customers that are not required to pay 14

additional reestablishment of credit deposits 15

following a disconnection. 16

2. Medical Baseline or life support customers shall not 17

be disconnected without an in-person visit from a 18

utility representative. 19

3. SCE lowered the deposit calculation from two times 20

the highest monthly bill to two times the average 21

monthly bill. 22

(ii) Residential Disconnection OIR Phase II Decision 23

In the Phase II decision, the Commission took additional 24

steps to reduce the number of disconnections. The Commission directed utilities to do the following:38 25

1. Establish a six percent CARE disconnection 26

benchmark, where no more than six percent of the 27

37 D.10-07-048, Ordering Paragraph 2.a., p.32.

38 D.12-03-054, pp. 54-59.

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CARE population may be disconnected for nonpayment 1

annually. 2

2. Ensure that CSRs offer residential customers the option 3

of enrollment in the CARE rate program over the 4

telephone. 5

3. For any written communication to residential customers 6

concerning the risk of service disconnection, provide 7

key information in large print, such as 14-point sans-8

serif font. 9

4. For residential customers who have previously been 10

identified as disabled and who have identified a 11

preferred form of communication, provide all 12

information concerning the risk of disconnection in 13

these customers’ preferred format. 14

5. For households identified as using non-standard forms 15

of telecommunication, ensure that outgoing calls 16

regarding the risk of disconnection are made by a live 17

representative. 18

6. Inform residential customers who self-certify that they 19

have a serious illness or condition that could become 20

life-threatening if service is disconnected that a utility 21

representative will make customer contact via an in-22

person visit prior to disconnection. 23

(3) Residential Disconnection OIR Impact on SCE’s Uncollectible 24

Expense 25

The more lenient credit and disconnect policy changes mandated by the 26

OIR resulted in an increase in outstanding account balances for residential customers and increased 27

SCE’s risk exposure to uncollectible expense. SCE’s 2012 GRC authorized uncollectible expense based 28

on the ten- year average from 2000 through 2009 was $23.0 million. However, in 2012, SCE’s 29

uncollectible expenses grew to $29.9 million, which is $6.9 million higher than the 2012 GRC 30

authorized level. Accordingly, the Residential Disconnect OIR component of this added Uncollectible 31

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Expense (approximately $4.9 million) is included in the total Residential Disconnect OIR O&M charges 1

recorded in the Residential Service Disconnection Memorandum Account (RSDMA), discussed in this 2

section below titled “Recovery of Interim Disconnect OIR Cost in RSDMA”. For a full discussion of 3

the Residential Disconnect impact on the Uncollectible Factor (as recorded in FERC Account 904), 4

please see Chapter IV, Part 4 of this Volume. 5

b) 2012 Operating Results – Credit 6

The results of SCE’s Credit operations over the last three years is best described 7

in terms of the Residential Disconnect OIR, the need to comply with the Commission’s order for more 8

lenient credit and disconnection practices for residential customers, and the results those provisions have 9

had on SCE’s Uncollectible Expense. If measured by the ability to reduce the number of credit-related 10

disconnections, the last three years were very successful in achieving the Commission’s goal in that 11

respect. As shown in Figure IV-16 below, the reduction in the number of disconnections in 2010 12

through 2012 came at the expense of greatly increased levels of Uncollectible Expense. Although this 13

figure shows the total number of disconnections and total uncollectible expense for all SCE accounts, 14

both factors are heavily influenced by residential accounts, which comprise approximately 90 percent of 15

total disconnections and went from 69 percent of total uncollectible expense in 2008 to 93 percent of 16

total uncollectible expense in 2012. 17

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Figure IV-16 Uncollectible Expense vs. Number of Credit Disconnections

2008-2012

Figure IV-16 above also shows the lag effect that extended payment arrangements 1

have on the delayed time of write-off. The true impact of the more lenient Residential Disconnect OIR 2

provisions that took effect beginning in 2010 began to show a cumulative lag effect that impacted 2012 3

uncollectible expense much more than in the initial years that those provisions were applied. Whereas 4

the average closing bill that was written off prior to 2009 had only 60 to 90 days owing, with the 5

Residential Disconnect OIR payment arrangement provisions, the average bill was typically six to 6

twelve months owing before the service was disconnected and a closing bill was finally issued. The 7

actual write-off does not get recorded as Uncollectible Expense until 180 days after the closing bill is 8

issued and all attempts at collection have been exhausted. Assuming a December 2013 sunset date for 9

the Residential Disconnect OIR provisions, overall this 12 to 18 month lag will continue to impact 10

Uncollectible Expense well into the 2015 Test Year. 11

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(1) Recovery of Interim Disconnect OIR Cost in the Residential Service 1

Disconnection Memorandum Account (RSDMA) 2

Pursuant to the Commission’s order in D.12-03-054 and D.10-07-048, 3

SCE has tracked in a Memorandum Account the compliance costs associated with implementing the 4

credit and disconnection practices arising out of the Residential Disconnect OIR.39 D.12-03-054 states 5

the intent of the Commission to review these costs in the utilities’ next GRC.40 Consistent with this 6

direction, SCE sets out the total recorded O&M costs contained in its Residential Service Disconnection 7

Memorandum Account (RSDMA) below for recovery through its existing Base Revenue Requirement 8

Balancing Account (BRRBA) process. 9

The practices established in the Residential Disconnect OIR that 10

contribute to ongoing costs will sunset at the end of the 2013. However, because the impact on 11

uncollectible factor will lag by approximately 12 to 18 months, the costs will continue to accrue well 12

into the 2015 Test Year. SCE assumes that the RSDMA will close at the end of 2014 and has included 13

the forecast residual impact that carries over to 2015 in its 2015 Test Year forecast for the FERC 14

Account 904 Uncollectible Factor. Some IT costs may also be incurred in 2014 in order to update 15

SCE’s billing systems to remove those practices that SCE does not continue past the sunset date. As 16

such, additional costs will be provided, related to 2013 and 2014 uncollectible and IT costs, via the GRC 17

update process. 18

Costs related to interest on the RSDMA, as well as additional information 19

on SCE’s proposed recovery process are set forth in Exhibit SCE-10, Volume 1, while Table IV-39 20

below provides the total O&M related costs that have been tracked to the RSDMA. 21

39 R. 10-02-005, Ordering Paragraph 3(c), p. 16.

40 D. 12-03-054, p. 37.

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Table IV-39 RSDMA O&M Costs

August 2010-July 2013 (Nominal $000)


Recorded Cost

1 Uncollectible Expense $7,709 2 Field Disconnection / Visits 868 3 IT System Changes 591 4 Total $9,168

SCE’s proposal for recovering the Residential Disconnect OIR 1

uncollectible expense related costs is covered in detail in Part Four below (Uncollectible Expenses). 2

SCE has tracked $868,000 in costs associated with the manual 3

disconnection of customers from January through November 2012. These costs result from the interim 4

practices and delays to RSS implementation that arose as a result of the Residential Disconnect OIR. 5

The interim practices in the Residential Disconnect OIR required SCE to provide an in-person field visit 6

and field collection to any customers on the medical baseline rate or the life support program. The 7

Phase II Decision extended this practice to customers who certify they have a serious illness or condition 8

that could become life-threatening if service is disconnected. Additionally, on October 14, 2011, 9

Commissioner Florio issued Assigned Commissioner’s Ruling Granting Motion to Temporarily Delay 10

Implementation of Remote Disconnections, which directed SCE to temporarily suspend implementation 11

of remote disconnection of customers without first having conducted a field visit by a utility employee, 12

pending issuance of the Phase II decision in the Residential Disconnect OIR.41 At that time, SCE was 13

just beginning to phase in RSS disconnection, and the order caused SCE to delay that implementation, 14

which resulted in costs associated with manually disconnecting all residential accounts. As such, RSS 15

implementation was delayed, and the customers eligible for RSS disconnection were limited as a result 16

of the Residential Disconnect OIR, requiring SCE to add incremental field personnel to carry out manual 17

disconnections and offer customers field payment options. 18

An additional $591,000 in IT costs has also been tracked to the RSDMA. 19

These costs were incurred updating SCE’s billing system to ensure that the practices set forth in the 20

41 D.11-12-028 affirmed that ruling in Ordering Paragraph No. 2, p. 6.

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Residential Disconnect OIR were followed. These costs were primarily associated with the interim 1

practices mandated in the Order Instituting Rulemaking and the Additional Practices required by the 2

Phase II Decision.42 To avoid double counting of these costs, SCE assumes these costs will be fully 3

recovered through the RSDMA and has removed these costs from the recorded history for each affected 4

FERC account based on this assumption. To the extent the Commission finds any portion of these 5

memorandum account expenses not to be a reasonable result of the Residential Disconnect OIR, the 6

portion not allowed to be recovered through the RSDMA should be added back into the history for each 7

affected FERC account before completing the final 2015 Test Year forecast. 8

c) Description of the Payment Services Functions 9

The Payment Services group is responsible for oversight of electronic and 10

Authorized Payment Agency (APA) payments. The Remittance Processing group in the Controllers 11

Department has responsibility for processing of mail-in payments, and the Transmission and 12

Distribution Operating Unit handles in-person payments made at SCE’s Rural Offices. Currently, SCE 13

customers can pay their electric bill through the mail, in person through an APA or Rural Office, or by 14

utilizing one of seven electronic payment options. In support of the Energy Solutions component of 15

SCE’s Customer Service Model described in Volume 1 of this Exhibit, a new, proposed prepayment 16

program, which allows residential customers to pre-pay for electric service and avoid a deposit, is 17

discussed below in Section g). The major functions of the various payment options are described as 18

follows: 19

(1) Electronic Payment Options 20

Electronic payment options in aggregate have grown to be the most 21

commonly used method of payment. There are currently seven electronic payment options available for 22

our customers: (1) Electronic Funds Transfer, (2) Online Bill Payment (SCE.com), (3) Electronic Data 23

Interchange, (4) Direct Payment, (5) Pay-by-Phone, (6) QuickCheck, and (7) Credit and Debit Card. 24

The online billing option provides customers with an e-mail notification each month when their 25

electronic bill has been created and is ready for viewing. Customers can then choose to make payment 26

through the option of their choice. SCE continues to accept Electronic Funds Transfer from customers 27

who use home banking services or other bill payment websites. Commercial or industrial customers 28

who have Electronic Data Interchange (EDI) capabilities may receive their bills and make payments 29

42 See D.12-03-054, pp. 54-59.

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through this channel. Customers can enroll in Direct Payment and have their bill amount automatically 1

deducted from their bank account each month ten days after their bill is generated. Customers can also 2

make an ad hoc (one-time) payment or recurring payments by enrolling in My Account on SCE.com. 3

Pay-by-Phone is a free payment option that enables enrolled customers to 4

make a payment from their checking account by dialing an 800 number from a touch-tone phone. 5

Customers can use QuickCheck to pay their bill by calling our Customer Contact Center and providing 6

their bank account information. SCE eliminated the fee for this option in January 2012. 7

In 2010, SCE received approval from the Commission and implemented 8

the Credit and Debit Card option for our residential customers. This payment option was implemented 9

in June 2010 with a convenience fee of $1.75.43 On June 26, 2013, SCE’s Advice Letter 186-G/2901-E 10

was approved, expanding this offer to include VISA and reducing the fee to $1.65. The convenience fee 11

for this payment option goes directly to the credit and debit card processor. 12

(2) Mail-In Payments 13

Mail-in Payments are processed by the Remittance Processing group in 14

SCE’s Controllers Department and are our second most commonly used method of payment. Checks 15

are banked electronically through the Accounts Receivable Conversion and Check 21-Image processes. 16

Remittance Processing also performs other payment-related activities including processing cash 17

payments received through the mail, bank deposit reconciliation, general ledger posting, returned check 18

processing and bank adjustments for all payment options. 19

(3) In-Person Services 20

Walk-in payments made through our APA network and Rural Offices are 21

the third most common method of payment. Customers use this payment type for the convenience of 22

using cash or check to pay bills and receive a receipt. 23

(a) Authorized Payment Agencies 24

APAs are positioned throughout SCE’s service territory to provide 25

local, convenient walk-in payment service at no charge to customers. Although volume fluctuates, SCE 26

had 318 payment locations as of December 31, 2012, which provide customers with the convenience of 27

paying their electric bill at a nearby location. Many of these agencies offer customers a one-stop-shop to 28

make payments for all of their utility bills at no charge. Also, the convenience of extended hours and 29

43 Reference Credit and Debit Card Resolution G-3443.

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weekends is available at many of these locations. Typically, the agencies are located in areas convenient 1

to customers, such as shopping centers, drug stores, stationery stores, grocery stores, and other types of 2

businesses with high customer traffic. 3

(b) Rural Offices 4

SCE has ten Rural Offices in addition to one Business Office 5

located on Catalina Island. All Rural Offices and the Catalina office provide walk-in payment services. 6

They are manned by SCE personnel and maintain normal business hours, five days a week. For added 7

customer convenience, APA offices are also available near most rural office locations, and many APAs 8

provide walk-in services during extended hours and on weekends. We continue to evaluate the payment 9

activity in the areas served by the Rural Offices and support customers with additional APA locations as 10

needed. 11

d) 2012 Operating Results - Payment Services 12

The volume of payments processed has increased by one million from 2008 to 13

2012 with a total of over 51.5 million payments processed in 2012. The payment type and number of 14

payments by year are presented in Table IV-40. For the five-year period from 2008 through 2012, 15

electronic payments have increased by 50 percent, while Mail-In payments have decreased by 30 16

percent and In-Person APA payments have decreased by 18 percent. 17

Table IV-40 Payment Posting Volume in 2008-2012

(In 000s)

1 Mail-In Payments 23,496 21,550 19,672 18,021 16,4052 In-Person Payments3 Authorized Payment Agencies 7,665 7,622 7,150 6,995 6,3224 Rural/Local Offices 297 294 284 276 2705 Electronic Payments: 19,050 21,294 23,705 25,996 28,5566 Total 50,508 50,760 50,811 51,288 51,553

2010 2011 2012DescriptionLine No. 2008 2009

(1) Payment Services Performance Measures 18

(a) Cost Per Payment 19

For convenience, customers continue to migrate towards electronic 20

payment options, most of which are provided at no cost to customers. Table IV-41 shows Payment 21

Services overall costs, volumes, and cost-per-payment over the last five years. As shown below, 22

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although the number and convenience of new payment options are saving time and money on the 1

customer’s side, the cost per payment to SCE has decreased from 20 cents per payment in 2009 to 16 2

cents per payment in 2012. 3

Table IV-41 Average Cost-Per Payment for Payment Services in 2008-2012


1 Total Payment Services Costs (Constant 2012 $000) $9,553 $10,312 $10,006 $9,557 $8,1832 Total Number of Payment Processed (In 000s) 50,508 50,760 50,811 51,288 51,5533 Average Cost-Per Payment (Constant 2012 $) $0.19 $0.20 $0.20 $0.19 $0.16

(b) Payment Posting Timeliness 4

SCE continues to maintain superior performance in the area of 5

payment posting timeliness. As illustrated in Table IV-42, same-day payment postings have continued 6

to average above 99 percent over the last five years. Next-day payment postings for APAs are also 7

nearly 100 percent. 8

Table IV-42 Payment Posting Timeliness

2008-2012


2008 2009 2010 2011 2012 Same Day %

Next Day %

Same Day %

Next Day %

Same Day %

Next Day %

Same Day %

Next Day %

Same Day %

Next Day %

1 Mail-In Payments

100 n/a 100 n/a 100 n/a 100 n/a 100 n/a

2 APAs 96.62 99.93 97.40 99.94 96.81 99.95 98.02 99.96 99.30 99.97

3 Electronic 100 100 100 100 100 100 100 100 100 100

4 Overall 99.46 99.99 99.35 99.96 99.54 99.98 99.73 99.99 99.91 99.99

(2) American Disability Act (ADA) Compliance 9

In SCE’s last two GRCs, the Disabilities Rights Advocates (DisabRA) has 10

addressed various issues of public access to SCE facilities, right-of-way access to streets and sidewalks 11

affected by permanently installed utility property or construction, internet access, and emergency 12

communications with customers. More specifically, with regard to SCE’s payment services, these issues 13

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addressed SCEs Authorized Payment Agencies and their need to comply with established public access 1

standards. 2

(a) Disability Rights Advocates (DisabRA) 2009 GRC Settlement 3

In SCE’s 2009 GRC, the Commission adopted a settlement 4

between the SCE and DisabRA. The Commission directed SCE to document and demonstrate in its 5

2012 GRC that SCE made significant and useful changes to utility operations as a result of the 6

settlement. The Commission also required SCE to have all APAs in compliance with seven primary 7

related ADA transactional elements by March 2013, excluding approved exceptions. As shown in Table 8

IV-43 below, at the time this application is being filed, all 318 APAs are compliant, and four APAs have 9

received approved exception status. 10

(b) DisabRA 2012 GRC Settlement 11

DisabRA raised similar issues in SCE’s 2012 GRC regarding the 12

impact of SCE’s practices on people with disabilities, including (1) follow-up to issues from the 2009 13

GRC settlement and (2) accessibility of SCE’s communications with its customers. As part of the 2012 14

GRC proceeding, SCE and DisabRA reached a settlement to adopt a mutually acceptable outcome to 15

certain access issues raised by DisabRA. The terms and conditions of the Settlement Agreement were 16

accepted by the Commission as part of its final decision in SCE’s 2012 GRC.44 17

SCE is currently completing the annual ten percent Follow-Up 18

Surveys, as stipulated with DisabRA. 19

Table IV-43 2012 APA / ADA Compliance Results

Line No. APA Network Compliant

1 Standard Agents 272

2 Declaration Letter Agents 46

3 Total 318

4 Approved Exception Agents 4

Since the original survey, all 318 Standard and Declaration Letter 20

Agents are ADA compliant. The four non-compliant agents are approved Exception Agents. Annually, 21

44 D.12-11-051, pp. 687-688.

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SCE surveys ten percent of our APA network, which will include at a minimum of four new APAs to 1

ensure continued compliance with the ADA requirements. 2

The SCE website provides a listing of accessible APAs, which is 3

updated as changes are made to our APA network.45 4

(3) Electronic Payment Options 5

Electronic payment options have become the most preferred payment 6

option among SCE customers. These options and the volume for each are shown in Table IV-44. 7

Table IV-44 Electronic Payment Options and Volumes 2008-2012

(In 000s)

Line No. Electronic Payments 2008 2009 2010 2011 2012

1 Electronic Funds Transfer 8,530 8,933 9,428 10,817 11,7502 On-line Bill Payment (SCE.com) 4,054 5,219 6,467 7,331 7,8783 Direct Payment 4,013 4,553 4,841 5,405 6,1304 QuickCheck 1,716 1,588 1,357 1,231 1,7835 Electronic Data Interchange 642 989 1,524 901 5986 Pay-by-Phone 95 12 2 30 457 Credit/Debit Card* 0 0 86 281 3728 Electronic Payments Total 19,050 21,294 23,705 25,996 28,556

* Credit / Debit card implemented in 2010.

Customers’ use of SCE’s electronic payment options has increased by 8

over nine million payments during the 2008 to 2012 period, which represents a 50 percent increase. 9

Customers have increased their use of online bill payment (SCE.com) option by nearly four million 10

payments because of the ease, convenience, and low cost of electronic banking and they no longer need 11

to mail in their payments. 12

(4) Mail-In Payments 13

In 2010, the volume of Mail-In payments was collectively surpassed for 14

the first time by electronic payments. As of 2012, Mail-In payments still account for 16.4 million 15

payments or 32 percent of all payments received. As more customers become familiar with electronic 16

45 SCE’s website is www.sce.com.

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payment options, SCE expects a continued movement from mail-in toward electronic payment options, 1

which offer more convenience. 2

(5) In-Person Services 3

Authorized Payment Agencies (APAs) collected more than 6.3 million 4

payments in 2012, which represents 12 percent of SCE’s total payments collected. As shown above in 5

Table IV-40, the volume of APA payments has decreased by 1.3 million from 2008 to 2012, mostly as a 6

result of customers migrating to electronic payment options. The number of APAs decreased slightly 7

over recent years, going from 380 in 2008 to 318 in 2012. The Commission has endorsed the following 8

criteria for locating and establishing APAs throughout our service territory. APAs must be: 9

Within a reasonable distance from customers’ homes or offices; 10

Within retail centers that provide parking, access via public 11

transportation, safety, and convenience; 12

Businesses that are clean and pleasant; 13

Businesses that process payments in a timely and efficient manner; and 14

Able to provide the seven primary related ADA transactional elements 15

as follows: 16

1. Handicapped parking facilities 17

2. Accessible pathways from parking to APA front door (i.e., ramp 18

access) 19

3. Ease of opening door 20

4. Accessible pathway inside APA 21

5. Service counter tops 22

6. Clear pathway to service counter 23

7. Public restroom with handicap stall (applies to chain store agents 24

with more than four locations) 25

e) Analysis of Historical Data – Credit and Payment Services - FERC Account 26

903.200 27

As described in the previous section, SCE’s Credit and Payment Services 28

Operations have been significantly impacted by the ESC metering system and the use of RSS. Also 29

affecting Credit operations in recent years was the impact of the Residential Disconnect OIR on credit 30

practices, service disconnections, and special accommodations that were made in field credit operations. 31

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Because of these changes, the timing of this GRC is such that the historical expenses as recorded are of 1

minimal use in forecasting future expense levels for the Credit and Payment operations. The following 2

sections will describe the historical data and the adjustments that were necessary in order to predict 3

future expense levels. 4

Because the 2012 Base Year was a transition year for ESC and the use of the 5

RSS, not all ESC deployment related savings were fully realized in SCE’s normal operating accounts in 6

2012. In order to align the recorded data with future steady-state expectations, the forecasting method 7

used for this GRC required a nonrecurring cost adjustment to the 2012 recorded data in order to fully 8

account for future savings. The forecasting method and the required adjustments are described in the 9

following sections. 10

The recorded/adjusted costs shown in Table IV-45 below were derived after 11

analyzing the recorded costs and adjusting them to reflect ongoing future operations for the Credit and 12

Payment Services functions. This was accomplished by removing the non-recurring legacy costs 13

recorded in 2012 that would not exist with full deployment of ESC steady-state RSS operations. 14

Table IV-45 Credit and Payment Services – FERC Account 903.200

2008-2012 Recorded and Adjusted Expenses (Constant 2012 $000s)

12 Labor 15,498 15,228 13,547 13,887 6,594 3 Non-Labor 4,695 4,139 4,124 4,204 3,093 4 Other - - - - - 5 Sub-total 20,193 19,367 17,671 18,091 9,687 67 Labor 2,937 3,784 3,920 3,688 3,442 8 Non-Labor 6,616 6,528 6,085 5,870 4,741 9 Other - - - - - 10 Sub-total 9,553 10,312 10,005 9,558 8,183 11 Grand Total 29,679 27,676 27,649 17,870

2011 2012Credit

Payment Services

Line No. Category 2008 2009 2010

Credit costs are primarily driven by field collection activities, which have 15

decreased in recent years because of the more lenient credit provisions of the Residential Disconnect 16

OIR starting in 2010 and the increased use of the RSS in 2011 and 2012. Payment Services costs are 17

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primarily driven by APA activities, the increased use of electronic payment options, and the number of 1

payments processed. 2

For Credit operations in 2009, labor costs decreased due to a Commission ordered 3

moratorium in 2009, which preceded the Residential Credit Disconnect OIR that was issued in February, 4

2010. Credit related non-labor costs decreased in 2009 due to a decrease in supplemental contract 5

support and a decrease in collection agency costs. Payment Services labor costs increased in 2009 due 6

to an accounting change that began in 2008 resulted in an increase in recorded labor expense for 7

Payment Services activity. Labor costs for Remittance Processing are now recorded as direct labor costs 8

instead of as an allocation to non-labor costs. 9

In 2010, Credit labor expense decreased because of a decrease in field service 10

orders resulting from various moratoriums on credit disconnects and other, more lenient credit 11

provisions from the Residential Disconnection OIR. Payment Services labor increased in 2010 due to 12

the timing of hiring two positions to backfill vacancies that existed in 2009. Payment Services non-13

labor costs decreased in 2010 due partially to the fact that the APA survey effort ended in 2009, and 14

minimal costs related to that effort were recorded in 2010. Additionally, in 2010, non-labor costs 15

decreased because of lower payment volumes experienced at APAs, offset partially by increases in 16

informational system professional services and credit-related non-labor expenses. 17

In 2011, Credit related labor expenses increased due to an increase in field service 18

overtime, which was partially offset by reductions from unfilled vacancies in the Credit organization. 19

Payment Services labor decreased in 2011 because of decreased payment volume due to shifts in 20

customer payment options away from mail-in payments and to electronic payment options. Non-labor 21

costs in Payment Services decreased in 2011 due to lower contract APA fees, reduced APA volumes, 22

and a reduction in ADA rebates. 23

The decrease of $8.4 million in Credit related labor and non-labor in 2012 was the 24

direct result of increased use of the RSS for credit-related disconnects and reconnects, as the ESC 25

systems approached full deployment at the end of 2012. The RSS eliminated approximately 63.3 26

percent of field disconnects and reconnects in 2012, resulting in not only a reduction in labor but also a 27

reduction in non-labor costs related to vehicle usage. Additionally, a nonrecurring cost adjustment was 28

made to the 2012 recorded expense to account for future savings. This nonrecurring cost adjustment 29

will be more fully described in the following section. Payment Services labor expense dropped in 2012 30

as a result of the shift in customer preferences for electronic payment options, which resulted in reduced 31

110

Accounts Receivable costs due to a reduction in mail-in payment volumes. Non-labor Payment Services 1

costs in 2012 were lower due to a reduction of contingent worker expense resulting from lower mail-in 2

payment volumes because of the shift in customer preferences to electronic payment options. 3

(1) 2012 Base Year Adjustment for Nonrecurring Cost 4

Because the ESC System and the RSS were only 63.3 percent operational 5

on average during 2012, some of the field disconnect and reconnect costs that were recorded as O&M in 6

2012 were non-recurring, legacy costs that will no longer be incurred once the RSS becomes fully 7

operational. Thus, only a portion of ESC benefits were recorded as O&M in 2012. This was resolved 8

by adjusting the 2012 recorded costs downward by $2.689 million to recognize the unrealized benefits 9

of ESC and the RSS in future years.46 The nonrecurring costs for 2012 were calculated as follows: 10

The total savings attributed to reduction in the number of field 11

disconnects and reconnects equals $7.326 million.47 12

Because only 63.3 percent of RSSs were COTO on average in 2012, 13

the savings realized by the end of 2012 was $4.637 million. 14

The remaining 36.7 percent of the benefit was not yet reflected in the 15

recorded cost for 2012. Thus 36.7 percent of $7.326 million, or 16

$2.689 million was considered to be non-recurring cost recorded in 17

2012. 18

With the above described adjustments to the 2012 Base Year recorded 19

levels, the 2012 adjusted/recorded cost was used as the base to which future adjustments were made to 20

forecast Test Year Credit and Payment Services costs. Table IV-46 below shows the last five years of 21

recorded costs for the Credit and Payment Services FERC Account 903.200 and the 2015 Test Year 22

Forecast with the future year adjustments described in the following section. The future cost 23

adjustments were added or subtracted in the increments discussed below and as shown in workpapers. 24

46 The derivation of the base year and future year adjustments are shown in the workpapers.

47 As forecast in SCE’s 2012 General Rate Case for 2013, Exhibit SCE-04, Vol. 2, p. 150, $6.7 million escalated to 2012 dollars.

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Table IV-46 Credit and Payment Services –FERC Account 903.200

2008 – 2012 Recorded and Adjusted Expenses (Constant 2012 $000)

Line No. Category 2008 2009 2010 2011 2012 1 Labor 18,435 19,012 17,467 17,575 10,036 2 Non-Labor 11,311 10,667 10,209 10,074 7,834 3 Other 0 0 0 0 0 4 Total 29,746 29,679 27,676 27,649 17,870

f) Test Year Operating Expectations – FERC 903.200 1

Figure IV-17 below shows the recorded/adjusted historical and forecast expenses 2

for the Credit and Payment Services function. 3

Figure IV-17 Credit and Payment Services



The FERC 903.200 Credit and Payment Services Account was forecast 5

using the 2012 adjusted recorded Base Year Expense as the starting point, adding incremental costs and 6

112

savings for each forecast year, to reach the 2015 Test Year forecast. Due to the influence ESC and the 1

Residential Disconnect OIR have had on Credit Operations beginning in 2010, recorded costs prior to 2

2012 are not representative of future expectations and thus were not suitable to support historical 3

averages or trends to forecast future costs. The recorded and adjusted O&M costs for 2012 were used as 4

the basis for forecasting future costs after adding a downward adjustment for non-recurring legacy costs 5

(i.e., future benefits) and an upward adjustment for steady-state RSS costs that were charged to the 6

ESCBA in 2012. 7




for SCE’s Credit and Payment Services operations in 2015. 11

113

Figure IV-18 Credit and Payment Services




expected to increase by 2.06 percent from 2012 to 2015. The Credit and Payment Services functions are 3

directly impacted by customer growth as more bills are generated to new customers, creating additional 4

routine operational work related to credit and payment activities. While meeting this added workload, 5

the Credit and Payment Services groups expect to continue maintaining high performance with timely 6

posting of payments and adherence to established credit rules and policies to assure that Uncollectible 7

Expenses are kept to a minimum, while still meeting customers’ needs. To reflect the impact that this 8

increase in the level of credit and payment activities will have on cost, an upward adjustment of 9

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$369,000 (2.06 percent) was applied to the labor and non-labor components of the 2012 Base Year 1

adjusted/recorded costs. 2

(b) Program Changes 3

There are four Credit and Payment Program Changes in the 4

forecast for FERC Account 903.200. These include upward adjustments in the 2015 Test Year required 5

by the Prepayment Program: (1) $295,000 for increases in the number of notices, (2) $353,000 for 6

increases related to multiple payments being processed per month, (3) $261,000 increase for a 7

percentage of customers that will require a field disconnection or reconnection where the RSS is not 8

available, and (4) an increase of $40,000 in 2015 for the number of field disconnects and reconnects 9

because opt-out customers do not have RSS that can be turned on and off automatically. The 10

Prepayment Program is discussed in Section g) below. 11


A downward adjustment of $635,000 in Test Year 2015 reflects 13

savings resulting from the consolidation of Management Support functions for Field Services personnel 14

who work on credit-related service connections and disconnections. This is the field credit allocation of 15

the savings resulting from the elimination of Supervising FSRs working in each of SCE’s 26 field 16

district locations. In addition, the addition of the Visa credit card payment option is forecasted to result 17

in a $448,000 reduction in fees paid and costs incurred in other payment options. These two 18

adjustments equate to a total Operational Excellence reduction of $1.083 million. 19

g) SCE Prepayment Program 20

With the implementation of ESC, SCE is in a position to leverage smart meter 21

technology to offer a bill prepayment program to residential customers. In support of the Energy 22

Solutions component of SCE’s Customer Service Model described in Volume 1 of this Exhibit, the 23

proposed SCE Prepayment Program will enable customers to pay for their energy in advance of use. 24

Under the prepayment program, customers would not be required to pay a deposit in order to establish or 25

re-establish credit prior to turn-on or reconnection. Additionally, because the plan will allow customers 26

to increase their energy account balance at any time, there will be no set recurring due date, from the 27

customer’s perspective, allowing participating customers to fully match energy payments to their 28

personal finances. The wide variety of payment methods available to customers, and account balance 29

alerts through multiple channels, will aid customers in keeping a positive energy account balance. The 30

prepayment program is a viable tool for customers that do not want to pay a deposit or that want to have 31

115

more control of energy bill situation. Finally, the bad debt feature, described below, will offer those 1

customers with outstanding bad debt to SCE an option to establish an energy account prior to fully 2

extinguishing that debt. 3

Prior to developing this program, SCE investigated the potential interest level in a 4

prepayment program. In November 2012, SCE conducted a study of 300 English- and Spanish-speaking 5

residential customers and 200 Small Business customers regarding their interest level in prepay. Interest 6

was highest among residential deposit customers – 20 percent responded that they would “definitely” 7

sign up for the prepayment program if one were available. The interest expressed by customers in this 8

study is supported by the experience of other utilities that have instituted prepayment programs. At this 9

time, over 80 utilities offer a prepayment program in the United States, five of which are investor-10

owned. The Salt River Project in Arizona has reported an enrollment rate of 14 percent of total 11

residential customers, and has reported a high satisfaction rate with its prepayment program.48 12

Similarly, the Oklahoma Electric Cooperative (OEC) has reported an enrollment rate of 11.6 percent of 13

total residential customers, in its prepayment program.49 SCE estimates that the customers most likely 14

to enroll are the current residential deposit customers. Accordingly, the expected SCE customer 15

enrollment as a percentage of total residential customers will be 0.32 percent in 2015 and will increase 16

to 0.90 percent in 2016 and 1.47 percent 2017. 17

The major elements of SCE’s Prepayment Program are described below. 18

(1) Eligibility 19

The SCE Prepayment Program will be available to ESC-metered 20

residential customers with RSS capability. Customers on the medical baseline rate and self-certified 21

serious illness customers50 will be ineligible because of customer safety concerns. Customers who 22

choose to opt out of smart metering will also be ineligible. Additionally, customers on certain utility 23

programs and tariffs, such as On-Bill Repayment and NEM, will be ineligible at the time of launch 24

because of billing system constraints. 25

48 See The Persistence of Consumer Choice, Association for Demand Response + Smart Grid, June 2012, p. 8 (noting “over

90 percent of M-Power [Prepay] customers gave either a very satisfied or satisfied rating when we asked about the program”).

49 OEC Presentation to the DEFG Prepay Energy Winter Workshop, p. 7, December 12, 2012.

50 The Residential Disconnect OIR established this category.

116

(2) Enrollment 1

Customers will be able to enroll through SCE.com, the Customer Contact 2

Center (CCC), or by mail-in application. In order to enroll, the customer must be eligible, as discussed 3

above, and must establish a minimum prepaid balance of $10 (approximately $14 for those customers 4

who must make a bad debt payment as discussed below). 5

(3) Deposits 6

Customers who enroll in the plan will not be required to pay a deposit if 7

they are establishing a new service account. Customers who need to re-establish credit through a service 8

deposit will also have the option to enroll in the SCE Prepayment Program to re-establish energy service 9

with no deposit, as long as the customers have brought their accounts to current status. Customers for 10

whom SCE currently holds a deposit will have those deposits refunded to them should they choose to 11

enroll in the Prepayment Program. 12

(4) Rates and Payments 13

Customers on the SCE Prepayment Program will be billed based on their 14

existing rate schedules. They will be able to add funds to their account balance at any time, fully 15

enabling them to make payments based on their cash flows. Normal payment options will continue to be 16

available to SCE customers, including online, credit/debit payment, IVR, payment through APAs, and 17

mail-in. 18

(5) Bad Debt 19

Customers with prior bad debt51 will be eligible to enroll in the plan and 20

must stipulate that 25 percent of each payment will go toward paying off prior bad debt. This will 21

provide customers with bad debt an option for reestablishing energy service before fully extinguishing 22

the bad debt. 23

(6) Bill Statements 24

Customers must enroll in MyAccount and accept online billing as a 25

requirement of the Prepayment Program. On the SCE Prepayment Program, customers will view their 26

account balance, legal notices, and monthly account statement online as part of the online billing 27

component of the plan. Customers participating in the plan will not receive a paper billing statement. 28

51 “Bad debt” is a customer’s arrears after an account has been designated as part of SCE’s uncollectible expense. It must

be paid before re-establishment of electric service.

117

(7) Customer Alerts 1

Participating customers will be able to receive balance alerts through 2

multiple channels, including e-mail, text, and IVR calls. Current balance information and historical bill 3

usage will also be made available online at SCE.com through MyAccount. 4

(8) Disconnection and Reconnection 5

Customers enrolling in the plan must also agree to terms and conditions 6

authorizing the disconnection of energy service after four days of negative balances or a balance of 7

negative $20 or more, whichever happens first.52 However, customers will not be disconnected on 8

holidays, weekends, or during extreme weather events,53 which could allow for a negative balance 9

exceeding $20. Customers will primarily be disconnected and reconnected via the RSS. However, a 10

small percentage of disconnections will need to be done in the field. As such, customers who are 11

disconnected will continue to be charged a service connection fee at time of reconnection.54 12

(9) Capital Project 13

Billing and payment system upgrades will be necessary to support the 14

SCE Prepayment Program and will be implemented as a one-time system upgrade as described in SCE-15

05, Vol. 2. 16

(10) Energy Conservation Benefit 17

SCE anticipates that societal benefits will accrue through an energy 18

conservation benefit. Salt River Project has reported a 12 percent reduction in energy consumption 19

among customers who have enrolled in its prepayment program.55 Based on this data, SCE projects a 20

total conservation benefit of $2.75 million between 2015 and 2017. SCE anticipates that this benefit 21

52 SCE notes that this is less than the 10 days’ notice required under Cal. Pub. Util. Code § 779.1(a). However, A Review

of Pre-Pay Programs for Electricity Service, which was issued by the CPUC Policy and Planning Division on July 26, 2012, notes the Commission has previously allowed customers to “voluntarily choose a different rate design and leave the rate protections afforded them by current statutes.” See D.06-10-051.

53 A special disconnection policy to alert the FSRs takes effect whenever the average temperature reaches or is forecasted to read 105 degrees or hotter and whenever the temperature is or is forecasted to be 25 degrees or lower. The FSR assigned to disconnect a customer’s service will first attempt to contact the customer at the door. When customer contact is made, the FSR will determine whether or not any special needs or circumstances exist that should preclude the disconnection.

54 See Chapter X of this volume for information on the residential Service Connection charges.

55 EPRI Technical Update October 2010: “Paying Upfront: A Review of Salt River Project’s M-Power Prepaid Program”, p. 51.

118

will be recognized in future Long Term Procurement Plan (LTPP) proceedings through a reduction in 1

energy procurement. 2

(11) O&M Costs and Benefits 3

The costs and benefits of the prepay program are set forth in Table IV-47 4

below and discussed further in the applicable sections of testimony, based on FERC Account. 5

Table IV-47 Costs and Benefits – Prepay Program

2015 through 2017 (Constant 2012 $000s)

With respect to FERC account 903.200, the proposed Prepayment 6

Program is expected to generate an increase in the number of credit-related alerts and notifications of 7

prepaid balances in order to provide prepayment customers some assurance that their service will not be 8

unexpectedly interrupted. The cost of this increase in notification activities is expected to be $295,000 9

for Test Year 2015. For this program, 6,427 manual field visits are also expected for instances when the 10

RSS capability does not function. SCE expects an additional cost of $261,000 in Test Year 2015; 11

however, these costs will be partially offset by the service connection fee. The additional cost for the 12

increased call volume is reflected in the CCC O&M forecast and is described in Chapter V of this 13

Volume. The proposed Prepayment Program is expected to require processing of 3.5 prepayments per 14

month, on average, per customer on the program. This added level of prepayment processing is 15

expected to cost an additional $353,000 in Test Year 2015. Benefits related to the Prepayment Program 16

119

include a $338,000 reduction in Uncollectible Expense and a postage reduction of $84,000. Reductions 1

of $34,000 in SCE’s mailing operations are also forecast. 2

3. Postage [FERC Account 903.100] 3

a) Description of the Postage Function 4

RSO oversees the mailing process of SCE’s bills, associated notices, reminders, 5

and correspondence and is responsible for the efficient utilization of resources to assure mailings are 6

timely and cost-effective. SCE sent over 45 million billing statements and 7.7 million notices, 7

reminders, and correspondence each year at a total postage expense of $20.009 million in 2012. SCE 8

keeps postage costs down by taking advantage of bulk mail discounts made available by the United 9

States Postal Service (USPS) and by finding ways to improve processes to gain efficiency. The billing 10

group monitors bill length and the number of bill onserts in an effort to manage the postage costs. In 11

recent years, mailing costs have been lowered significantly by encouraging customers to convert to 12

electronic billing options, thus eliminating their need for a paper bill each month. The productivity 13

savings of $2.400 million (2013 – 2015) attributable to “paperless billing” campaigns is included as a 14

Productivity Initiative in Table I-1 of this Exhibit and is also included in the Operational Excellence cost 15

reductions identified in the Test Year 2015 forecast for FERC 903.100 account. 16

b) 2012 Operating Results 17

Table IV-48 below shows the recorded postage expense for the last five years. A 18

steady decline in postage expense from 2009 through 2012 is the result of customer migration away 19

from paper bill statements to more convenient electronic billing options, which has resulted in a 20

reduction in the number of required mailings. 21


The recorded/adjusted costs shown below in Table IV-48 were derived after 23

analyzing the recorded costs for this activity and adjusting them to reflect ongoing operations. 24

120

Table IV-48 Postage


1 Labor Expense - - - - - 2 Non-Labor Expense 22,721 23,487 22,044 21,739 20,009 3 Other - - - - - 4 Total Operation Expense 22,721 23,487 22,044 21,739 20,009

2012Line No. Category 2008 2009 2010 2011

Postage expense in 2012 was $20.0 million, $2.71 million below the 2008 1

recorded level of $22.72 million. The increase of $0.77 million in 2009 was due to the USPS average 2

rate increase of 3.2 percent. The decreases of $1.44 million and $0.30 million in 2010 and 2011, 3

respectively, were due to customer migration from paper to electronic billing and changes made to the 4

reserve account funding process, offset by costs related to address cleansing and a USPS rate increase. 5

Expenses recorded in 2012 continued to decline because of further increase in the number of customers 6

using electronic billing and choosing not to receive paper bills. 7

As shown in Table IV-49 below, RSO realized a reduction in the number of 8

mailings, going from 12.56 mailings per customer in 2008 down to 10.82 mailings per customer in 2012. 9

Table IV-49 Mailings Per Customer

Line No. Year Mailings Average Customers

Mail Per Customer

1. 2008 61,104,184 4,866,324 12.56 2. 2009 59,656,731 4,883,787 12.22 3. 2010 58,035,906 4,909,662 11.82 4. 2011 55,351,168 4,929,149 11.23 5. 2012 53,560,739 4,950,465 10.82 6. 2013 53,837,994 4,975,785 10.82 7. 2014 54,194,978 5,008,778 10.82 8. 2015 54,668,613 5,052,552 10.82

121

Under the January 2012 postal rate structure, SCE received postage discounts for 1

six types of mailings: 2

5-Digit Presorted mailings, discount of $0.103 per item; 3

3-Digit Presorted mailings, discount of $0.079 per item; 4

AADC (Automated Area Distribution Center) mailings, discount of $0.079 5

per item; 6

Mixed AADC mailings, discount of $0.049 per item; 7

Non-Manifest 1st Class, discount of $0.076 per item; 8

Summary First Class Overweights, average cost of $1.924 per item. 9

Residual mail consists of those items of insufficient volume to normally qualify 10

for the maximum postage discount. We use a presort-contractor that combines SCE’s residual mail with 11

similar pieces of mail from other large mail volume companies on a daily basis. This qualifies such mail 12

for a discounted rate, which would otherwise not be available. 13

The six rates mentioned above are the least expensive available under the postal 14

rate structures. A detailed breakdown of recorded mailings by type for each year from 2008 through 15

2012 is included in the workpapers. 16


Figure IV-19 shows the recorded/adjusted historical and forecast expenses for the 18

Postage function. Details regarding the forecast O&M expenses for this function are described below. 19

SCE expects that continuing customer migration to electronic billing options will result in a continued 20

decline in the overall number of mailings. SCE’s proposed Prepayment Program is expected to result in 21

a further reduction in the number of required paper bills, saving $84,000 annually. SCE anticipates that 22

USPS will continue to apply annual postage rate increases. Program Change adjustments totaling 23

$531,000 have been added for customer growth and other postage related activities in FERC Account 24

903.100. The anticipated 2.06 percent in customer growth from 2012 to 2015 is incorporated into the 25

postage study itself, as it affects the total number of required mailings. 26

122

Figure IV-19 Postage


Applicable postage rates and postage expenses by type of mailing are shown in 1

Table IV-50 below. In view of the factors driving the postage expense and continued efforts to maintain 2

these expenses at the lowest possible levels, the 2012 recorded/adjusted expenses reflect a mix of 3

mailing types and are considered representative of future expectations. 4

123

Table IV-50 Postal Rates and Total Expense by Type of Mailing

Recorded Forecast Type of Mailing 2008 2009 2010 2011 2012 2013 2014 2015

Postal Rate Category 5 Digit 0.320 0.332 0.335 0.337 0.347 0.347 0.347 0.347 3 Digit 0.342 0.354 0.357 0.362 0.371 0.371 0.371 0.371 AADC (Automated Area Distribution Center) 0.348 0.357 0.360 0.365 0.371 0.371 0.371 0.371 Mixed AADC (Automated Area Distribution Center) 0.366 0.378 0.382 0.387 0.401 0.401 0.401 0.401 Misc 1st Class N/A N/A 0.385 0.368 0.374 0.374 0.374 0.374 Misc 1st Class Overweights N/A N/A 0.759 0.450 0.374 0.374 0.374 0.374 Full 1st Class Overweights N/A N/A N/A 0.440 0.450 0.450 0.450 0.450 Full 1st Class Overweights (Over 2oz) N/A N/A N/A 0.904 0.698 0.698 0.698 0.698 Non-Manifest 1st Class1 0.369 0.381 0.385 0.368 0.374 0.374 0.374 0.374 Non-Manifest 1st Class Overweights N/A N/A 0.510 0.493 0.374 0.374 0.374 0.374 Summary 1st Class2 0.697 0.733 0.702 N/A N/A N/A N/A N/A Summary 1st Class Overweights2 N/A N/A 0.853 1.881 1.924 1.924 1.924 1.924 Late Notices 0.369 0.381 0.385 0.368 0.374 0.374 0.374 0.374 Misc Pieces 0.374 0.448 0.385 0.403 0.412 0.412 0.412 0.412

Weighted Average 0.334 0.349 0.360 0.356 0.362 0.362 0.362 0.362

Postal Expense (Nominal $000) 5 Digit $13,354 $13,527 $13,256 $11,236 $12,934 $13,000 $13,087 $13,201 3 Digit $3,740 $3,906 $3,827 $3,733 $4,072 $4,093 $4,120 $4,156 AADC (Automated Area Distribution Center) $90 $88 $91 $87 $79 $80 $80 $81 Mixed AADC (Automated Area Distribution Center) $190 $191 $194 $178 $218 $219 $221 $223 Misc 1st Class N/A N/A $1 $43 $.2 $.2 $.2 $.2 Misc 1st Class Overweights N/A N/A $.2 $.5 $108 $109 $109 $110 Full 1st Class Overweights N/A N/A N/A $26 $79 $80 $80 $81 Full 1st Class Overweights (Over 2oz) N/A N/A N/A $.1 $.3 $.3 $.3 $.3 Non-Manifest 1st Class1 $1,266 $1,205 $707 $552 $263 $264 $266 $268 Non-Manifest 1st Class Overweights N/A N/A $669 $2,733 $412 $414 $417 $421 Summary 1st Class2 $499 $316 $100 N/A N/A N/A N/A N/A Summary 1st Class Overweights2 N/A N/A $429 $957 $387 $389 $391 $395 Late Notices $452 $447 $431 $393 $411 $413 $416 $419 Misc Pieces $856 $1,056 $798 $887 $406 $408 $411 $414 Prepaid Meter Postage3 $416 $660 -$945 -$571 $4 $4 $4 $4

Other Mailings4 $59 $46 $244 $252 $238 $245 $245 $245 Other Postage related activities5 $27 $355 $1,094 $706 $397 $521 $521 $521

Sub-total $20,949 $21,798 $20,894 $21,213 $20,008 $20,239 $20,368 $20,540 Online Billing Productivity Adjustment (Organic) N/A N/A N/A N/A N/A -$429 -$992 -$1,599 Operational Excellence Productivity Adjustment N/A N/A N/A N/A N/A -$242 -$423 -$761 Pre-Pay Initiative Productivity Adjustment N/A N/A N/A N/A N/A N/A N/A -$84

Total $20,949 $21,798 $20,894 $21,213 $20,008 $19,568 $18,954 $18,096 1 Included all Non-Manifest, Late notices & Miscellaneous pieces2 These pieces did not include late notices or Miscellaneous pieces3 Adjusted amount in Pitney Bowes meters and bank account less roll over from previous year 4 Customer correspondence generated by Revenue Services and Customer Contact Center5 Postage related costs associated with Intelligent Mail Barcode, Address Cleansing, EDI Charges, Timing of Bank Reconciliation, and USPS postage fee corrections/charges Note: - All historical recorded costs reflect actual postage rate increases. - N/A's indicate mailing category did not exist in recorded year and on occasion new mailing rate will overlap with old rate. - Negative amounts displayed for pre-paid meter postage indicate over budget expenses.




for SCE’s Postage operations in 2015. 4

124

Figure IV-20 Postage


(a) Program Changes 1

The Test Year adjustment for Program Changes is a $531,000 2

increase from 2012 recorded. The increase is attributed to the number of mailings related to customer 3

growth and an increase in postage-related activities reflected in Table IV-50 above. 4

(b) Productivity 5

Productivity adjustments for this account reflect savings of $1.599 6

million for continuing customer migration to online billing options and an additional $84,000 annually 7

for reduced number of mailings attributed to SCE’s proposed Prepayment Program. Should the 8

proposed Prepayment Program be either withdrawn by SCE or denied by the Commission, the $84,000 9

annual savings adjustment should be added back into the forecast for this account. 10

125


In addition to the anticipated savings based on historic trends for 2

customer migration to online billing options, SCE expects further postage savings of $761,000 through 3

an enhanced customer engagement initiative to encourage the use of new mobile technologies to pay 4

bills online, further eliminating paper bills. 5

4. Uncollectible Expenses [FERC Account 904] 6

a) Description of Uncollectible Expense 7

FERC Account 904 records SCE’s expenses for all revenue components of 8

uncollectible customer accounts. Historically, expenses recorded in this account are authorized based on 9

an estimate of the uncollectible expense factor, which is expressed as a percent of SCE’s total revenue.56 10

Once determined, this authorized rate of uncollectible factor is applied to Test Year generation and 11

distribution revenues in the GRC proceeding and is also applied to revenue components litigated in other 12

ratesetting proceedings before the Commission and/or the Federal Energy Regulatory Commission 13

(FERC).57 There are no other functions or activities other than uncollectible expense recorded in FERC 14

Account 904. 15

b) Accounting for Uncollectible Expense 16

SCE’s estimate for Account 904 includes that portion of recorded revenues 17

subsequently determined to be uncollectible. Because all receivables are recorded as revenue when the 18

sale is recorded, revenues are overstated by the amount that will never be collected due to customers’ 19

failure to pay. To avoid this overstatement of revenues (and a corresponding overstatement of assets), a 20

provision for the uncollectible portion is retained as a credit balance in the General Ledger - Provision 21

for Uncollectible Accounts. This provision for uncollectible expense is estimated each month because 22

the actual uncollectible expense is not known until the uncollectible expenses are written off. Typically, 23

uncollectible revenues are written off approximately 180 days from the date a closing bill remains 24

unpaid. 25

56 The application of the uncollectible expense factor for revenues determined in other proceedings is described in SCE’s

Preliminary Statement for each authorized revenue related recovery mechanism, such as the Base Revenue Requirement Account Preliminary Statement, Paragraph YY.2.e.

57 In addition to the distribution and generation revenue requirement being litigated in this rate case, the uncollectible factor is applied to the other public purpose revenue component which is litigated independently. For purposes of calculating the FERC Account 904 uncollectible factor, the associated dollar amounts described in this section are expressed in terms of gross revenue.

126

Thus, FERC Account 904 records the provision for uncollectible expenses; it does 1

not record SCE’s actual uncollectible expense. For our estimating purposes in this proceeding, the 2

recorded levels in FERC Account 904 have been adjusted to reflect actual levels of uncollectible 3

expense for each year. 4

c) Uncollectible Expense Operating Results 5

Table IV-51 shows the 2012 Commission Authorized level for uncollectible 6

expense, SCE’s forecast in the 2012 GRC, and the actual recorded uncollectible expense for 2012 with 7

and without the impact of the Residential Disconnect OIR. 8

Table IV-51 Uncollectible Factor and Expense

2012 Authorized Vs. 2012 Recorded (Nominal $ Millions)

Note: 2012 dollar impacts are based on $11.243 billion gross revenue in 2012

To help California consumers endure the recessionary impacts in recent years, the 9

Commission conducted a rulemaking, which examined the credit and disconnection practices of 10

California utilities.58 This rulemaking is referred to throughout this chapter as the “Residential 11

Disconnect OIR.” In both phases of the Residential Disconnect OIR, the Commission ordered specific 12

provisions that resulted in more lenient customer payment arrangements and disconnect practices, and 13

required a waiver of security deposits for high-risk accounts. The impact of the Residential Disconnect 14

OIR on Uncollectible Expense from 2010 through 2012 is the most critical factor to be considered in 15

reviewing the operating results related to Uncollectible Expense over the last five years. As shown in 16

Table IV-51 above, the 2012 recorded level of 0.266 percent of SCE’s gross revenue (approximately 17

$29.9 million based on approximately $11.2 billion in revenue) exceeded the 2012 authorized level of 18

58 See D.12-03-054, p. 2.

127

0.205 percent by 0.061 percent, or approximately $6.9 million. Approximately $4.9 million of the 1

excess in 2012 is attributable to the provisions of the Residential Disconnect OIR. 2

(1) Disconnect OIR Impact on Uncollectible Expense in 2012 3

The Phase 1 decision in the Residential Disconnect OIR (D.10-07-048) 4

authorized the utilities to establish memorandum accounts to track the cost impacts of the OIR 5

provisions, including Uncollectible Expense. The decision also authorized Utilities to “track any 6

significant additional costs, including operations and maintenance charges associated with implementing 7

the customer practices and any uncollectible expenses exceeding those projected in the utility’s last 8

general rate case.”59 Table IV-52 below shows the volume and dollar value of unpaid residential 9

accounts that were granted payment arrangements, or deposit waivers in 2012 by rate class (CARE, 10

FERA, and other) and the incremental $4.9 million in write-off attributable to the more lenient credit 11

provisions of the Residential Disconnect OIR. 12

Table IV-52 Disconnect OIR Impact on Uncollectible Expense in 2012

(Nominal Dollars)

Line No.

Rate

Accounts Granted Payment

Arrangements and Deposit

Waivers

Write-Off

Attributable to those

Accounts

Normal Write-off Without OIR

Provisions

Incremental Write-off

resulting from OIR

Provisions

1 CARE Domestic 11,165 $6,181,185 $3,125,445 $3,055,740

2 Non CARE Non FERA

Domestic 5,185 3,689,421 1,798,755 1,890,667

3 FERA Domestic 78 76,681 36,716 39,966 4 Total 16,428 $9,947,287 $4,960,915 $4,986,372

Although some provisions of the Residential Disconnect OIR have been in 13

effect for the over three years, the impact recorded in 2012 far exceeds that of the prior years. This is 14

due primarily to the lag time between granting a more lenient payment arrangement, or waiver of a 15

deposit, the time a service disconnection occurs, and eventually a closing bill is issued. In prior years, 16

this average lag time was approximately three months; in 2012, it nearly doubled to six months on 17

average for those accounts taking advantage of the Residential Disconnect OIR provisions. The result is 18

59 See D.12-03-054, pp. 5-6.

128

a much larger average closing bill going to write-off. Looking at the impact of the Residential 1

Disconnect OIR from the standpoint of the number of accounts that took advantage of the Residential 2

Disconnect OIR provisions, approximately 16,000 (or 12 percent) of the 133,500 accounts written-off in 3

2012 had received more lenient, extended payment arrangements as provided for in the Residential 4

Disconnect OIR decision. The number of accounts that actually went to write-off decreased by five 5

percent, going from 140,497 in 2009 to 133,399 in 2012, while the average amount of write-off per 6

account went up from $166.00 in 2009 to $224.00 in 2012, a 35 percent increase. 7

Figure IV-21 below shows the history over the last five years of the total 8

number of service disconnections compared to the level of uncollectible expense for those years. A 37 9

percent drop in the number of disconnects took place over the last five years (from 357,000 in 2008 to 10

222,000 in 2012), commensurate with a 44 percent rise in overall uncollectible expense (from $20.8 11

million in 2008 to $29.9 million in 2012). Although this figure shows the total number of 12

disconnections and total uncollectible expense for all SCE accounts, both factors are heavily influenced 13

by residential accounts, which comprise approximately 90 percent of total disconnections and went from 14

69 percent of total write-off in 2008 to 93 percent of total write-off in 2012. 15

129

Figure IV-21 History of Service Disconnects and Uncollectible Expense

2008 – 2012

(2) Three-Year Impact of the Disconnect OIR on Uncollectible Expense 1

2010 – 2012 2

The three-year impact of the Residential Disconnect OIR provisions on 3

recorded Uncollectible Expense from 2010 to 2012 is shown below in Table IV-53. The cumulative 4

effect of the longer grace period before issuance of the closing bill is evident in the year-to-year 5

increased level of write-off and the uncollectible factors over these three years. As shown in Table IV-6

53, the total Residential Disconnect OIR write-off impact over the last three years was $7.7 million. The 7

impact of the Residential Disconnect OIR on uncollectible expense through April 2013 appears to be 8

occurring at a similar pace as was recorded for 2012. 9

130

The impacts on uncollectible Expense were estimated by reviewing over 1

100,000 residential customer accounts that were written-off each year. Prior to implementing the 2

directives of the Residential Disconnect OIR, SCE’s average closing bill in write-off was equal to three 3

months of billings per customer. Therefore, SCE used the average three-month bill amount for each 4

account for an estimate of what would have been incurred since the Residential Disconnect OIR 5

mandates and included the difference between each account’s average three-month bill and the amount 6

actually written-off for each account as being attributed to the provisions of the Residential 7

Disconnection OIR.60 8

(3) Residential Disconnection Memorandum Account 9

Based on the Commission decision in Phase I of the Disconnect OIR, the 10

Commission authorized SCE to establish a Residential Service Disconnection Memorandum Account 11

(RSDMA) “to track any significant costs associated with complying with the new practices,” including 12

“any uncollectible amounts in excess of those projected in the utility’s last GRC.”61 In their decision, 13

the Commission further determined that the reasonableness of the RSDMA cost recovery “would be 14

determined in the next GRC for each utility.”62 15

As of 2012 year-end, SCE has recorded $7.7 million in costs related to 16

incremental uncollectibles in FERC 904 as shown in Table IV-53 below. The difference between SCE’s 17

authorized Uncollectible Expense and the recorded Uncollectible Expense for the three affected years 18

(2010 through 2012) was $8.4 million. The incremental uncollectible amount was calculated by 19

determining the portion of SCE’s total uncollectibles that were directly attributable to the more lenient 20

credit practices instituted by the Residential Disconnect OIR (primarily extended payment arrangements 21

and the elimination of reestablishment of credit deposits for CARE customers). Because the total impact 22

of the Residential Disconnect OIR on uncollectible expense (Table IV-53, Row 6) is less than the 23

difference between SCE’s authorized and recorded Uncollectible Expenses (Table IV-53, Row 5) for 24

2010 through 2012, the lower of the two amounts ($7.7 million) is used. 25

60 The workpapers include a sampling of this very large data file by showing the top, middle, and bottom pages of over

16,000 uncollectible customer accounts that were affected by the Disconnect OIR in 2012.

61 D.12-03-054, p. 36. SCE has addressed the reasonableness of the costs recorded in its Credit Disconnect OIR Memorandum account in Chapter IV.B of this Volume.

62 Id.

131

Table IV-53 OIR Impact on Uncollectible Expense in 2010 – 2012

Line No.

2010 2011 2012 Total

1 SCE Revenue

10,091,307,660 10,070,802,164 11,243,208,193 31,405,318,018

2 Uncollectible Recorded 24,790,986 25,139,077 29,939,171 79,869,234

3 GRC Authorized Uncollectible Factor

0.240% 0.240% 0.205% N/A

4 GRC Authorized Uncollectible Expense

24,219,138 24,169,925 23,048,577 71,437,640

5 Difference = Recorded vs. Authorized

571,847 969,152 6,890,594 8,431,593

6 Incremental Write-off Due to OIR

417,719 2,305,245 4,986,372 7,709,336

7 OIR Impact as a % of Recorded Unc. Expense

1.68% 9.17% 16.66% 9.65%

(4) Residual Impact of the Disconnect OIR Provisions Beyond 2012 1

In accordance with the Commission’s order in D.12-03-054, some of the 2

provisions of the Residential Disconnect Decision are set to expire on December 31, 2013, unless 3

otherwise extended by the Commission. Given that the impact to uncollectible expenses for 2013 and 4

beyond are not yet known at the time of filing this GRC application, SCE plans to update the RSDMA to 5

include the cumulative impacts incurred through the end of 2013, as well as a forecast of any residual 6

impacts that are expected to extend into 2014. In addition, SCE has included an adjustment to its 7

proposed Test Year 2015 forecast for FERC Account 904 to recognize the expected residual effect of the 8

revenue lag, as well as the Residential Disconnect Decision provisions that will not expire at the end of 9

2013. 10

(5) Analysis of Historical Data 11

Figure IV-22 below illustrates 20 years of historical uncollectible factors 12

and shows the variability of the uncollectible factor over time, going from a high of 0.444 percent in 13

1993 to a low of 0.108 percent in 2006. Over the last five years, the factor has gone from a low of 0.217 14

percent in 2008 to a high of 0.266 percent in 2012. The historically low levels of uncollectible expense 15

recorded in 2005 and 2006 were the result of consumer liquidity attributable to excessive credit 16

availability through sub-prime lending that culminated in 2006. The economic downturn that began in 17

132

2007 resulted from consumer de-leveraging of the massive amounts of credit accumulated in 2005 and 1

2006 and has had a significant impact on consumer discretionary spending in recent years. 2

Figure IV-22 History of Uncollectible Factor and Test Year Factor

Through 2012

As shown above in Figure IV-22, the historic pattern of recorded levels of 3

uncollectible expense over the last 20 years is erratic, and heavily influenced by the two extremely low 4

uncollectible factors occurring in 2005 at 0.112 percent and 2006 at 0.108 percent. As will be discussed 5

below, the most recent five years of uncollectible expense has been heavily influenced by the more 6

lenient credit provisions that were ordered by the Commission in the Residential Disconnect OIR. 7

d) Uncollectible Expense Financial Analysis and Forecast - FERC 8

Account 904 9

Because the status of the RSDMA is to be simultaneously reviewed for 10

reasonableness in this proceeding and given the review includes a Commission determination of the 11

extent to which the recorded Uncollectible Expense is reasonably the result of the Residential 12

133

Disconnect Decision, the outcome of the reasonableness review will potentially impact the 2015 GRC 1

Uncollectible Factor forecast. 2

(1) Test Year Operating Expectations – FERC 904 3

It is expected that the Commission will allow the provisions of the 4

Residential Disconnect Decision to “sunset” on December 31, 2013 as proposed in its Phase II 5

Decision.63 With that expectation, SCE has forecasted its 2015 Test Year for the Uncollectible factor 6

based on the most recent five-year average recorded expense. Figure IV-23 below shows the five-year 7

recorded amounts and the outcome of the five-year average versus the five-year trend for FERC 8

Account 904. The five-year trend is shown merely to indicate what would be expected to occur in future 9

years if the more lenient credit provisions of the Residential Disconnect OIR were allowed to continue 10

into the 2015 Test Year. 11

63 See D.12-03-054, Section 3.6, pp. 31-32.

134

Figure IV-23 Uncollectible Factor Forecast

Historical Trend 2008 – 2017

To avoid double counting, the impacts of the Residential Disconnect 1

Decision have been removed from the derivation of SCE’s proposed forecast of Uncollectible Factor 2

based on the five-year historical average, assuming that the Commission will authorize the recovery of 3

the amounts recorded in the RSDMA. Should the Commission decide to deny RSDMA recovery (or 4

portions thereof), then adjustments for the disallowed portion of the impact should be added to the five-5

year average used to forecast SCE’s 2015 Test Year Uncollectible Factor. Should the Commission 6

decide to extend the provisions of the Residential Disconnect Decision beyond 2013, SCE’s proposed 7

forecast method would require an adjustment to the five-year average forecast to include the impact of 8

the OIR provisions going forward into the 2015 Test Year. 9

135

Figure IV-24 below illustrates SCE’s forecast factor of 0.230 percent after 1

adjusting for a Commission decision to allow full recovery of the Residential Disconnect OIR impact 2

amounts as recorded by SCE in the RSDMA64 and before making the four adjustments as described 3

below. As stated previously, the removal of the Residential Disconnect OIR impacts from the historical 4

average assumes that the provisions of the Residential Disconnect OIR will sunset on December 31, 5

2013. 6

64 See Table IV-54 above.

136

Figure IV-24 Uncollectible Factor Five-Year Average

2008 through 2017

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017OIR impact 0.004% 0.023% 0.044% 0.034% 0.017%

0.217% 0.242% 0.242% 0.227% 0.222% 0.221% 0.221% 0.230% 0.230% 0.230%

0.000%

0.050%

0.100%

0.150%

0.200%

0.250%

0.300%

Recorded Uncollectible Factor Forecast Uncollectible Factor

5 yr avg = 0.230%

0.246% 0.250%

0.266%0.255%

0.240%

(2) Adjustments to Historical Average 1

The following adjustments are specified relative to the outcome of the 2

Commission’s Decision regarding reasonableness of the RSDMA. The adjustment specified in the 3

fourth bullet below is based on the portion of the Uncollectible Expense included in the RSDMA that 4

the Commission finds to be reasonable. For Test Year 2015, we forecast a total uncollectible factor 5

based on the five-year recorded average of 0.244 percent, plus additional adjustments as specified 6

below: 7

1) Minus 0.002 percent for the expected reduction in uncollectible 8

expense of $206,000 resulting from the reduced Service Connection 9

137

charge and elimination of the Field Assignment Charge OOR that was 1

present during the five-year recorded history. 65 2

2) Minus 0.003 percent for reduced Uncollectible expense identified as a 3

benefit of the Prepayment Program = $338,000.66 4

3) Plus 0.015 percent for other residual impacts the Residential 5

Disconnect OIR has on future uncollectible expense = $1.7 million.67 6

4) Plus an adjustment to remove from the FERC Account 904 recorded 7

history any amount of uncollectible expense found by the Commission 8

to be reasonable and thus allowed to be collected under the provisions 9

of the RSDMA. This adjustment is minus 0.014 percent if full 10

recovery of the OIR impact is found to be reasonable.68 11

The 2012 uncollectible expense forecast including the above adjustments 12

is summarized in Table IV-54. 13

Table IV-54 Calculation of Uncollectible Factor

65 See workpapers for derivation of OOR impact on uncollectible expense.

66 See Chapter IV Section 2.g. of this Volume for a description of the Prepayment Program and its benefits. This adjustment would not apply if SCE’s proposed Prepayment Program is denied by the Commission or removed by SCE.

67 See workpapers for derivation of the residual impact of the provisions of the Residential Disconnect Decision.

68 This adjustment will remain unknown until the final decision relating to the RSDMA is rendered by the Commission.

138

(a) Adjustment to Reflect the Elimination of the OOR Field 1

Assignment Charge 2

In past GRC proceedings, SCE has added an adjustment to reflect 3

the impact of the increase of service fees on the uncollectible expense forecast. In SCE’s 2012 GRC, the 4

Commission authorized the elimination of the Field Assignment Charge. This change became effective 5

in January 2013, resulting in a significant decrease in service fees that will no longer be a part of 6

uncollectible expense starting in 2013.69 For this reason we have removed an additional 0.002 percent 7

from the adjusted five-year average to reflect the anticipated reduction in uncollectible expense of 8

$206,000 in 2013. 9

(b) Adjustment to Reflect the Prepayment Program Savings in 10

Uncollectible Expense 11

As discussed above in Section g) of this Chapter, SCE’s proposed 12

Prepayment Program is expected to result in a reduction in Uncollectible expense of $338,000 on 13

average annually, increasing from $45,000 in 2015 to $282,000 in 2016 and $686,000 in 2017. This 14

reduction is based on the assumption that the Prepayment Program disconnect procedures will be 15

approved by the Commission as proposed by SCE. Modification of SCE’s proposed disconnect 16

procedures could result in a reduction of this adjustment. An additional downward adjustment of 0.003 17

percent was removed from the adjusted five-year average to reflect the anticipated reduction in 18

uncollectible expense of $335,000 for the 2015 Test Year. 19

(c) Adjustment to Reflect Residual Disconnect OIR Provisions 20

SCE expects that not all of the impacts of the Residential 21

Disconnect OIR will be discontinued prior to the 2015 Test Year. As described earlier in this Exhibit, 22

changes in the method of calculating the re-establishment of credit deposit, more lenient disconnect 23

policies for medical baseline customers, self-certification of medical conditions that could be life-24

threatening if service is disconnected, and several other more lenient policies will all contribute to 25

increased uncollectible expense that are not fully reflected in the recorded data used to forecast the Test 26

Year Uncollectible Factor. An adjustment of $1.7 million of 0.015 percent was based on the impact that 27

the policy change affecting re-establishment of credit had on Uncollectible Expense in 2012. 28

69 SCE’s Service Fee changes are discussed in Chapter X of this Volume.

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(d) Adjustment to Reflect RSDMA Allowed by the Commission 1

Any portion of Uncollectible Expense recorded in the RSDMA 2

that the Commission finds to be reasonably the result of the provisions of the OIR will be removed from 3

the five-year average used to forecast the Test Year Uncollectible Expense. Full recovery of the $7.7 4

million expense for the three years equals a factor reduction of 0.014 percent. Any lesser amount 5

authorized for recovery in the RSDMA would reduce this adjustment proportionately. 6

(3) Recorded Uncollectible Expense for 2005 and 2006 Should Not be 7

Used to Predict Future Levels. 8

In its last two GRC proceedings, SCE has provided evidence showing that 9

the recorded levels of uncollectible expense in 2005 and 2006 were anomalies because of the credit 10

excesses in 2005 and 2006. This assertion was supported by a research paper presented at the Fall 2008 11

Conference on Economic Activities by several members of the Federal Reserve Board, specifically 12

identifying subprime lending in 2005 and 2006 as a key reason for the economic crises that soon 13

followed: 14

Had market participants anticipated the increase in defaults on 15 subprime mortgages originated in 2005 and 2006, the nature and 16 extent of the current financial market disruptions would be very 17 different. Ex ante, investors in subprime mortgage-backed securities 18 would have demanded higher returns and greater capital cushions, as a 19 result, borrowers would not have found credit as cheap or as easy to 20 get as it became during the subprime credit boom of 2005–2006.70 21

In light of this, the 2005 and 2006 recorded levels of uncollectible expense 22

should not be used to predict future levels; those levels are statistical “outliers” and unlikely to reoccur 23

for another 25 to 30 years. The probability that two such annual results would reoccur in the next 30 24

years is even less likely. The results of this analysis are presented in Table IV-55 below.71 25

70 Brookings Papers on Economic Activities, Fall 2008 Conference Draft “Making Sense of the Subprime Crisis,”

Kristopher Gerardi, Federal Reserve Bank of Atlanta, et al., p. 2.

71 The analysis of the 2005 and 2006 statistical results is included in the workpapers.

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Table IV-55 Statistical Probabilities that Recorded 2005 and 2006 Uncollectible Levels Will

Be Repeated in the Future

Line No.

Probability that 2015 uncollectible factor

will be - % chance Probability

Likely to re-occur in

1 lower than 2005 recorded 0.036 = 3.6% 27.69 Years*

2 lower than 2006 recorded 0.032 = 3.2% 30.98 Years* * Denotes less than 5 percent probability of repeating

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V. 1

CUSTOMER CONTACT CENTER (CCC) 2

The CCC responds to customer requests and inquiries 24 hours a day, seven days a week. The 3

CCC handles over 15 million inbound contacts annually and is also responsible for the fulfillment of 4

customer requests for service, web support, credit and billing inquiries. To handle the variety of 5

inbound and outbound transactions, the CCC is staffed by over 700 Customer Service Representatives 6

(CSRs) and support personnel. SCE also serves customers with speech and hearing disabilities through 7

Teletypewriter (TTY). SCE is committed to providing TTY customers the same level of care as those 8

who use our traditional toll-free numbers.72 9

Historically, the CCC has used the Interactive Voice Response (IVR) and automated call routing 10

technologies to effectively deliver calls to the appropriate CSR. These technologies have promoted 11

contact center accessibility in a cost-efficient manner, while still meeting SCE’s Commission-adopted 12

service level goal of answering 75 percent of the calls within 50 seconds, 90 percent of the weeks in a 13

calendar year. In the 2012 GRC, SCE proposed to meet our customers’ preference to initiate and 14

complete many routine customer service transactions on a self-service basis using technology such as 15

the IVR. For the 2015 GRC period, SCE proposes to continue to leverage these technologies to meet 16

our customers’ increasing preference to initiate and complete routine customer service transactions on a 17

self-service basis. For example, our customers now expect the ability to conduct customer service 18

transactions, such as routine web access transactions, billing and payment verifications, and routine 19

orders currently performed through a live agent. For those customers with complex requirements, the 20

CCC will continue to use the automated call routing technologies so that the customer’s service 21

transaction is handled by a trained and knowledgeable CSR. 22

SCE handles inbound calls through in-house bilingual representatives in six languages: English, 23

Spanish, Cambodian, Chinese (Mandarin and Cantonese), Korean, and Vietnamese. In 2007, SCE 24

began using a vendor translation service, which has enabled support of customer inquiries in over 180 25

languages. 26

72 D.12-11-051, Decision on Test Year 2012 General Rate Case for Southern California Edison Company, approved a

settlement agreement between SCE and DisabRA. This settlement agreement requires training and refresher training regarding procedures on handing TTY calls. See 2012 SCE/DisabRA Settlement Agreement, Section IV.C for more information.

142

The CCC functions described in this Volume are critical to deliver the programs and services 1

that are available as a result of the completion of the ESC meter deployment and to support the 2

Commission’s Smart Grid policies. For example, as new hourly energy usage information and more 3

complex tools and rates become available to our customers in 2015 and beyond, the CSR will function 4

as an energy advisor who will educate customers about their options and handle more complex issues. 5

This will also require the CCC to enhance our existing channels for customer service delivery resulting 6

in new intelligent delivery channels that enable customers to enroll in and take advantage of energy 7

solutions. 8

Additionally, in D.10-06-047, the Commission found that the state’s Smart Grid policies rely on 9

customers who are informed about the Smart Grid and empowered and able to use electricity more 10

efficiently.73 To achieve this objective, the Commission directed that SCE’s Smart Grid Deployment 11

Plan include customer education.74 Supporting the Smart Grid objectives requires not only marketing 12

and outreach, but also well-trained employees who have the appropriate knowledge to provide 13

information regarding a wide range of Smart Grid and ESC-enabled programs and services. As 14

described in this testimony, supporting the Commission’s policy and assisting customers with such 15

complex programs and services increases Average Handle Time (AHT) which results in a forecast 16

increase for CCC operations. In addition, the complexity of programs and services necessitates 17

restructuring the supervision for the CSRs in the CCC. 18

A. Customer Contact Center Functions 19

1. Description of Customer Contact Center Functions 20

This section describes the primary functions delivered by the CCC including handling 21

inbound calls via IVR and CSRs, making outbound calls, using other contact channels, such as web, e-22

mail and web chat, and overall CCC operations support. Inbound calls relate to a wide variety of 23

subjects, such as service establishment and transfer of service, payment arrangements, billing inquiries, 24

credit extensions, power outages, and other miscellaneous inquiries. Inbound calls include service to 25

our customers with special needs, such as hearing or sight impairment, critical care, or low income. In 26

these cases, the CSRs will provide information regarding special rates and programs for which these 27

73 See D.10-06-047, p. 125 (Finding of Fact 21 states, “A presentation of a Smart Grid Vision Statement that shows that the

proposed deployment plan promotes a ‘Smart Customer’ who is informed, empowered and able to use electricity efficiently and in ways the promote environmental goals would be consistent with SB 17 policies and initiatives”).

74 See D.10-06-047, pp. 35-36.

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customers would qualify (e.g., Medical Baseline, CARE, FERA, and enlarged format bill). Outbound 1

calls utilize the IVR system to contact customers for credit and collection, power outage and service 2

restoration notifications. The majority of these outbound calls are used to remind our customers of 3

overdue billings along with reminders of pending planned outages that will affect their power. In 4

addition, our capabilities provide customers the option to hear these outbound call updates in English or 5

Spanish. 6

Operations support includes functions performed by CSRs that cannot feasibly be 7

performed as part of the inbound customer call and are more efficiently processed offline. Accordingly, 8

many of the CCC functions will involve the use of intelligent delivery methods, such as mobile 9

communications, web chat, social media, and eChannel services to meet our customers’ needs and 10

preferences. The eChannel Services include CSRs who respond to e-mail and online web requests for 11

service, credit inquiries, payment options, rate questions, SCE.com password re-sets, and billing 12

inquiries. As customers continue to move toward self-service and migrate to the web, the CCC has seen 13

consistent growth in eChannel services and eChannel CSRs needed to support these customers. As 14

such, it will be necessary to increase the staffing in 2015 to support customers for other contact channels 15

inquiries. In addition, the CCC will continue to perform support services such as inbound and outbound 16

correspondence, billing inquiry, field dispatch, and assistance for special needs customers. 17

Inbound correspondence from customers via U.S. mail includes requests for itemization 18

of billing statements, maintenance of customers’ accounts, letters of credit, and submissions of 19

supporting documentation following up on previous calls. Outbound correspondence includes 20

responding to billing inquiries, providing payment option information, faxing letters of credit, and 21

fulfilling customer requests for brochures and other information. Currently, the CCC also has a 22

specialized group of employees who provide resolution of complex billing inquiries that require billing 23

research, consumption and rate analysis, and customer education. Operations support also includes the 24

field dispatch function, which is performed by a group of 18 employees who are trained to coordinate 25

and dispatch field service and trouble orders with field representatives. The group handles incoming 26

911 calls from local police and fire agencies and processes turn-offs, streetlight out orders, and other 27

offline service requests. Field dispatch also handles time-sensitive orders and monitors and responds to 28

the TTY used by hearing- or speech-impaired customers. Field dispatch has dedicated TTY specialists 29

available 24 hours a day, seven days a week. Customers can contact these CSRs via a special toll-free 30

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number that is listed on the back of SCE’s bill and other customer communication materials. In 2012, 1

SCE handled 87 TTY system-assisted calls, a decrease of 73 percent from 2008. 2

2. Operating Results 3

The historical activity levels for the CCC functions are summarized in Table V-56. The 4

operating results for the CCC functions from 2008 through 2012 Base Year are described below. 5

Table V-56 Functions and Activity Levels for the CCC

2008 – 2012

Function 2008 2009 2010 2011 2012

1 Live Agent Call Volume Handled 9,288,153 9,710,875 9,163,683 8,880,232 8,377,067

2 IVR Call Volume Completed 4,912,026 4,767,380 5,403,542 5,631,192 5,930,381

3 Outbound IVR Credit Calls 7,623,119 7,895,116 7.862,924 8,683,684 8,361,922

4 Outbound IVR Outage Calls 418,649 460,197 650,531 496,734 460,714

5 Outbound IVR Planned Outage Calls 488,229 1,175,619 1,705,900 2,107,233 2,444,126

6 eChannel Services Orders Processed 190,909 248,819 276,789 280,327 304,743

7 Web Chat - - - - 13,440

8 Inbound Correspondence 466,087 466,952 471,343 491,269 517,567

9 Outbound Correspondence 208,818 236,725 208,861 175,715 117,256

10 Outbound Brochures 497,034 515,160 365,498 332,319 422,811

11 Billing Inquiry Investigations Completed 85,382 98,166 86,388 72,627 47,453

12 Teletypewriter (TTY) 324 83 120 166 87

a) Functions and Activity Levels 6

(1) Inbound Calls 7

Through our toll-free numbers, the CCC handled 14.3 million live agent 8

and IVR inbound calls in 2012. In 2012, live agent call volumes decreased by 6 percent. The primary 9

contributor to this decrease is the increased customer use of self-service contact channels, such as the 10

web and IVR for basic customer service transactions. Another key factor affecting call volume decrease 11

is SCE’s improved outage systems and communications. The CCC has enhanced its interactions by 12

notifying our customers within the first hour with an estimated restoration time. These outage 13

notifications are communicated via text, text telephone (TTY), e-mail, or automated phone message to 14

keep our customers informed, which, in turn, reduces the number of phone inquiries for power 15

restoration. With the greater number of the routine customer service transactions successfully handled 16

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by the web or IVR self-service options, the AHT has increased. The remaining more complex calls and 1

interactions need significantly more CSR time to resolve. 2

The CCC uses call forecasting and workforce management technology to 3

assist with call volume projections, expected call durations, and staffing to meet customer demand and 4

SCE’s service level goal adopted by the Commission. Quality assurance practices, CSR, and service 5

delivery satisfaction surveys are used to monitor quality service delivery for representative-handled 6

inbound calls. 7

(2) Outbound Calls 8

The CCC made approximately 11.3 million outbound call attempts in 9

2012 related to credit and collections, planned maintenance outages, as well as unplanned outage 10

notifications. Of these outbound call attempts, approximately 8.4 million were related to credit and 11

collections to keep customers informed of potential service disconnections for nonpayment, available 12

payment options, and resources available for obtaining payment assistance. These calls were attributed 13

to the Commission’s Residential Disconnection OIR75 discussed previously in Chapter IV of this 14

Volume. Unplanned power outage call volume, which is primarily driven by weather and storm 15

conditions, will vary from year-to-year. However, an ongoing base level of outbound call attempts is 16

expected at or near the 2012 level of 460,000. Planned outage maintenance notification outbound call 17

attempts increased from 1.2 million in 2009 to 2.4 million in 2012 primarily due to additional customers 18

in association with planned maintenance outages impacting residential customers and keeping customers 19

informed of schedule changes. These planned outage maintenance notifications helped to increase 20

customer awareness of planned maintenance outages and improved satisfaction with the planned outage 21

process. 22

(3) Other Channels and Operations Support 23

As described earlier, the CCC uses intelligent delivery methods such as 24

eChannel services to allow customers to conduct customer service transactions with SCE. In 2012, the 25

eChannel Services Group saw increases in the various channels supported, including internet-related 26

orders, support calls, and customer web chat interactions. Nearly 305,000 Internet orders were 27

processed in 2012, an increase of 9 percent compared to 2011. The group also answered over 66,000 28

Internet Gate calls from an 800 number for customer web support offered on SCE.com. In addition, the 29

75 See R.10-02-005 for SCE’s requirements related to electric service disconnections.

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CCC introduced its web chat service in April 2012, offering a new additional contact channel to our 1

customers. From April 2012 to December 2012, the eChannel Services Group engaged in 13,440 2

customer web chats that were prompted from the chat button offered on several SCE.com pages. 3

From 2008 to 2012, inbound correspondence from customers via U.S. 4

Mail increased from 466,087 to 517,567 pieces. The most significant factors were owner-tenant 5

agreement activities that were transitioned to the CCC from the district in late 2009, and approximately 6

33,000 owner addendum agreement mailings for customer acknowledgment of SCE’s safety message 7

regarding the use of the RSS for service connection orders. As a result of system automation, outbound 8

correspondence and brochure quantities decreased from 706,000 to 540,000 pieces from 2008 to 2012. 9

In 2012, 47,000 customer billing inquiries were resolved by CSRs. The 10

number of billing inquiries has decreased by 44 percent from 2008 to 2012, primarily due to improved 11

usage and billing accuracy from ESC meters that eliminated inquiries driven by manual meter reading 12

errors. However, the amount of time to resolve billing inquiries has increased, thus reducing CSR 13

productivity from 4.6 to 2.9 billing inquiries per hour. This is driven in part by new tools, such as 14

Budget Assistant, and the amount of interval usage data that is available on SCE.com, which is more 15

complex for customers as CSRs can now discuss customers’ usage patterns and help identify solutions 16

to their energy usage and billing inquiries. Today the CSR and customer have 720 data points of hourly 17

interval usage available on the web that enables the CSR to assist the customer in pinpointing exactly 18

when during the month the customer’s usage increased and how to troubleshoot the cause. In turn, more 19

time is taken to educate our customers about usage during specific hours of the day so that our 20

customers can be empowered to make the necessary changes to lower their consumption. Our CSRs 21

guide our customers to the right mix of rates, products, and energy solutions. 22

b) Performance Metrics 23

The CCC’s performance measures achieved by the CCC from 2008 through 2012 24

are shown in Table V-57 below. 25

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Table V-57 CCC Performance Metrics

2008 – 2012 Line No. Performance Metric 2008 2009 2010 2011 2012

1 Average Response Time (ART) 56 seconds 42 seconds 34 seconds 37 seconds 63 seconds

2

Service Level Goal (answer 75% calls within 50 seconds, 47 weeks/year)

50 weeks 52 weeks 52 weeks 52 weeks 50 weeks

3 Service Delivery Satisfaction 73% 74% 76% 75% 74%

4 Call Volume Handled

5 CSR Handled 9,288,153 9,710,875 9,163,683 8,880,232 8,377,067

6 IVR Handled 4,912,026 4,767,380 5,403,542 5,631,192 5,930,381

7 Total Call Volume Handled 14,200,179 14,478,255 14,567,225 14,511,424 14,307,448

8 Average Handle Time (AHT) by CSRs 278 sec 270 sec 273 sec 293 sec 304 sec

The average response time measures the amount of time in seconds before a 1

customer call is handled. From 2010 through 2012, the average response time rose because of lower 2

staffing levels and an increase in AHT per call, while the Customer Service Organization continued with 3

the temporary hiring cap while awaiting the final decision for the 2012 GRC. From 2008 to 2012, SCE 4

has been able to meet the adopted service level goals. 5

The call volume handled, defined as the successful connection of a customer’s 6

call to a CSR or the completion of a customer’s call by the IVR, increased steadily from 2008 to 2010 7

and then began to decrease in 2011 because of the availability of eChannel services and the outbound 8

notifications for credit and collections, customer outages, and unplanned outages. 9

The AHT is the average total amount of time spent by a CSR in handling the 10

customer call. The AHT grew 11.4 percent from 2010 to 2012 as calls related to routine customer 11

service transactions migrated to self-service platform, such as IVR and SCE.com. The result was an 12

increase in complex customer calls related to service or new programs and services being handled by 13

CSRs. See the testimony in SCE-05, Volume 2, Part I for more information regarding the systems 14

necessary to support the Digital Customer Program and the migration of customer calls to self-service 15

channels. 16

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3. Analysis of Historical Data 1

The recorded/adjusted costs shown below in Table V-58 were derived after analyzing the 2

recorded costs for this activity and adjusting them to reflect ongoing operations. 3

Table V-58 Customer Contact Center


Line No. Category 2008 2009 2010 2011 2012

1 Labor Expense 34,130 34,123 36,280 35,665 34,217

2 Non-Labor Expense 12,058 12,852 12,909 12,575 12,156

3 Other - - - - - 4 Total Operations Expense 46,188 46,975 49,189 48,240 46,373

a) Year to Year Variances – 2008 through 2012 4

Operating expenses and telephone bills are two major cost components for the 5

CCC recorded in FERC Subaccount 903.800. From 2008 through 2009, the total costs of these two 6

components increased from $46.188 million to $46.975 million primarily due to the increase in utilizing 7

third-party services to handle live calls. From 2009 through 2010, total expenses increased from 8

$46.975 million to $49.189 million attributed to a CSR wage increase to address competitive labor 9

market issues, an increase in project management resources to support call center productivity 10

improvement projects, and an increase in third-party services to handle live calls. From 2010 to 2011, 11

expenses decreased from $49.189 million to $48.240 million because of a $1.4 million decrease in 12

operating expense and an offsetting $462,000 increase in the phone bill component of CCC costs. We 13

estimate that approximately $217,000 of the operating expense decrease in 2011 was due to more 14

accurate billing data accessed from the ESC meters and being processed through the MDMS, which 15

made 14.4 percent of all SCE accounts “available for billing”76 on average in 2011. The remaining $1.2 16

million of the decrease in 2011 was due to a temporary hiring cap pending the results of the 2012 GRC. 17

The $462,000 increase in telephone bills resulted from technology costs incurred in 2011 with the 18

stabilization of CCC systems. Finally, from 2011 through 2012, operating expenses decreased by 19

76 Most residential customer accounts with ESC meters became “available for billing” (using cumulative monthly meter

reads) before they were officially “Cut Over to Operations” (COTO) with full availability of hourly interval usage data.

149

$1.867 million. We estimate that approximately $826,000 of this decrease in operating expense was 1

attributed to the reduced number of billing inquiries to more accurate billing data coming from ESC 2

meters and the MDMS billing exception process. An additional $1.303 million reduction occurred as 3

the CCC continued with the temporary hiring cap while awaiting the final decision for the 2012 GRC. 4

The decrease in operating expenses caused by the temporary hiring cap, however, resulted in an 85 5

percent increase in customer wait times for live agents from 34 seconds in 2010 to 63 seconds in 2012. 6

A $236,000 increase in the telephone bill was the result of longer wait times and increased AHT. 7

b) ESC Costs and Benefits 8

Without any further adjustments, the 2012 recorded data does not include any 9

ESC costs or future benefits because all incremental ESC costs were charged to the ESC Balancing 10

Account (ESCBA) through the end of 2012. Charges to the ESCBA included not only deployment and 11

“start-up” costs, but they also included costs that were ongoing and considered to be “steady-state” costs 12

that would continue into the 2015 Test Year. A 2012 Base Year increase adjustment of $1.202 million 13

was made to account for the 37 percent steady-state portion of the $3.244 million in CCC costs that were 14

charged to the ESCBA in 2012. 15

We estimate that the CCC will realize a total $1.517 million in reduced operating 16

costs due to more accurate and timely billing data as a result of the ESC meters and the MDMS billing 17

exception processes. The 2012 recorded costs include approximately $1.044 million in ESC benefits 18

that have already been realized in 2010 through 2012. As discussed previously, a significant reduction 19

in billing related calls and billing complaint investigations occurred from 2010 through 2012. These 20

benefits accrued as the result of more accurate ESC metering, and billing data became available in those 21

years. Because only 69 percent of SCE meters were operational for billing on average in 2012, the 2012 22

recorded data was not fully reflective of future benefits that will be realized in 2013 through 2014, as the 23

savings from the final 31percent of SCE’s ESC meters affect recorded costs in those years. To account 24

for those “yet-to-be-realized” benefits, a 2012 Base Year “nonrecurring cost” decrease adjustment of 25

$473,000 was made. With these two ESC-related adjustments, the 2012 recorded/adjusted Base Year 26

costs are considered to be a reasonable starting point to which the future Test Year adjustments 27

discussed below can be added. 28

4. Test Year Operating Expectations 29

Figure V-25 shows the recorded/adjusted historical and forecast expenses for the CCC. 30

Details regarding the forecast O&M expenses for this function are described below. 31

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Figure V-25 Customer Contact Center FERC Account 903.800 (Constant 2012 $000s)

The CCC forecast 2015 expenses are based on the Last Recorded Year 2012 1

recorded/adjusted expense levels discussed in the previous section, plus specific adjustments for future 2

incremental ESC costs, customer growth, program changes, and operational efficiencies due to enhanced 3

self service capabilities and a decrease in support personnel 4

5. Determination of Test Year Estimated Method 5

In 2012, the CCC adjusted/recorded costs were $46.373 million in total operating 6

expenses and telephone bills. The recorded/adjusted history for this account as described in the previous 7

section is shown in Figure V-25 above. The ESC system was 68 percent operational on average in 2012, 8

and 98 percent operational by the end of 2012. Because of the influence of ESC and interval usage data 9

on CCC operations, the Last Recorded Year was selected as the base for the Test Year forecast for both 10

labor and non-labor expenses. Recorded costs prior to 2012 are not representative of future expectations 11

and thus were not suitable to support historical averages or trends to forecast future costs. 2012 was the 12

first year in which the ESC systems approached the full steady-state level, and we were able to forecast 13

151

future expectations based on the 2012 recorded/adjusted results. To that base we have added the 1

increments discussed below and elsewhere in our testimony and workpapers 2

6. Test Year Adjustments 3

Figure V-26 below illustrates the relative levels of the 2012 Base Year expense to the 4

2015 Test Year forecast and the adjustment components used to arrive at the forecast cost for CCC in 5

2015. 6

Figure V-26 Comparison of 2012 Base Year to 2015 Forecast


a) Incremental ESC Costs 7

The CCC will experience continued increases in call volume and AHT due to 8

customer inquiries related to interval usage, new web tools, more complex rates, and other ESC 9

programs and services. As discussed above, these increased costs were partially realized in 2012 when 10

the ESC data collection and the MDMS exception processing programs were available for billing at a 11

152

rate of 68 percent of all bills produced in 2012. By the end of 2012, approximately 98 percent of SCE’s 1

total of 4.98 million ESC meters were available for billing. In addition to the $1.202 million of 2

incremental cost already added to the 2012 Base Year as discussed above, we have forecast that the 3

CCC will experience an additional $4.031 million in incremental ESC costs by 2015. As the ESC 4

systems and related MDMS programs approached the full steady-state level of operations by the end of 5

2012, we have accounted for the remaining portion of incremental ESC costs with upward 2015 Test 6

Year adjustments of $3.091 million for the increase in AHT, $693,000 for the increased Supervisor to 7

Specialist ratio, and $247,000 for increased phone bill expense resulting from longer AHT. These 8

incremental ESC cost increases are addressed more specifically in the following sections. 9

(1) Impacts of ESC to Average Handle Time 10

Additional CCC resources will be required in 2015 to provide adequate 11

customer support of ESC-enabled programs and services and to comply with the Commission’s Smart 12

Grid policies. Such customer support is necessary to assist with complex customer inquiries and 13

necessitates live support from a CSR. 14

(a) Compliance with Commission Policies Requires Customer 15

Support of More Complex Smart Grid Enabled Programs and 16

Services 17

In D.10-06-047, the Commission directed SCE to develop a Smart 18

Grid77 vision statement that would include a section addressing the “Smart Customer.” In describing the 19

Smart Customer, the Commission stated that SCE “will enable customers to become more informed 20

about the Smart Grid and allow customer to use electricity more efficiently and save money.”78 D.10-21

06-047 also provides guidance that such efforts “must also involve a detailed education and marketing 22

of why the Smart Grid is beneficial to the individual customer.” As described in the following 23

testimony, in support of the Commission’s Smart Grid policies, the CCC is an integral part of providing 24

education on Smart Grid-enabled programs and services. Many of these programs rely on interval usage 25

data or on emerging technologies (e.g., Home Area Network, Plug-in Electric Vehicles, Green Button) 26

and are, therefore, inherently more complicated than provided basic electric service using cumulative 27

77 The Smart Grid includes Advance Meter Infrastructure projects, such as SCE’s ESC program.

78 See D.10-06-047, p. 36.

153

usage data. Thus, in offering such Commission-encouraged contact center support while maintaining 1

service levels, the CCC requires additional funding increases related to increases in AHT. 2

(b) ESC-Enabled Programs and Services Are More Complex Than 3

Basic Electric Service 4

ESC-enabled technologies have greatly increased the complexity 5

of the programs and services provided by SCE. Time-differentiated rates, new interval usage 6

information, and new programs and services such as SCE’s proposed prepayment program all create 7

new opportunities for customers to learn about their energy usage and their bill impacts. These 8

programs and services are inherently more complicated compared to traditional, basic customer service 9

based on cumulative usage data. As such, as described in Volume 1 of this Exhibit, our CSRs provide 10

energy advisory services to our customers. CSRs will use customer data, information about our energy 11

solutions, and industry expertise to advise customers on energy solutions that make sense for their 12

homes, business, and institutions. CSRs will be trained to use their industry knowledge and thorough 13

understanding of customer preferences and needs to guide our customers to the right mix of solutions. 14

For example, in the past there were two customer usage data points (starting and ending meter reads) 15

that the customer and CSR could refer to in order to validate usage for questions about the bill. Today, 16

the CSR and customer have 720 data points of hourly interval usage that is available on the web that 17

enables the CSR to assist their customer in pinpointing exactly when during the month their usage 18

increased and troubleshoot the cause. 19

CSRs will now perform an energy advisor role as they can offer 20

rates, programs, and services to best fit the needs for particular customers’ usage patterns. Typically, 21

during a customer’s call for service, our CSRs would take general customer information and set the date 22

for their service to start. Now, our CSRs must complete this basic function but also obtain the 23

customer’s e-mail address, seek to enroll the customer in MyAccount and online billing and payments, 24

and inform the customer of SCE.com. CSRs must also address rate inquiries. For example, small 25

commercial and industrial (C&I) and residential customers may ask about the Critical Peak Pricing 26

(CPP) rate.79 All small C&I and residential customers with a communicating ESC meter are eligible for 27

CPP, which amounts to approximately 4.9 million customers eligible for CPP in 2015. In addition, on 28

79 CPP is marketed by SCE as the Summer Advantage Incentive program.

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January 1, 2016, approximately 580,000 small C&I service accounts will be defaulted to CPP.80 These 1

customers may have questions about what an “event” is (period of time during which SCE encourages 2

lower usage due to system constraints or higher electricity prices), when events may be called (only 3

from 2 p.m. to 6 p.m. weekdays, year-round, except holidays), the maximum duration of an event (four 4

hours), the amount of charges ($1.37/kWh81), types of credits (kWh energy credit for residential 5

customers and small C&I customers with demands less than 20, and kW demand credits for small C&I 6

customers with demands between 20 and 200 kW), bill impacts (dependent on usage during event and 7

non-event periods), if they can also be enrolled in SCE’s Peak Time Rebate (PTR)82 program 8

(residential customers may not be enrolled in both CPP and PTR), how will they be notified of events 9

(e-mail, text, phone), compatibility with CARE rates (CPP is compatible with CARE and non-CARE 10

domestic rates, as well as GS-1 and GS-2 rate schedules), and what causes a CPP event to be triggered 11

(generally high temperatures or system emergencies).83 Similar questions may be asked of all ESC-12

enabled programs and services, including PTR event notifications,84 Time-of-Use (TOU) rates,85 web 13

presentment tools,86 Budget Assistant,87 Home Area Network capabilities,88 data to authorized third 14

80 See D.13-03-031, Decision Addressing Settlements on Marginal Cost, Revenue Allocation, and Rate Design, March, 21,

2013. In this decision, mandatory Time of Use rates for commercial and industrial customers with demands less than 200 kW will be required on January 1, 2014 and January 1, 2015. In addition, in this decision, default Critical Peak Pricing rates for commercial and industrial customers with demands less than 200 kW will provided on a default basis beginning on January 1, 2016. Time-of-Use and Critical Peak Pricing rate assumptions were a key consideration of D.08-09-039, Decision Approving Settlement on Southern California Edison Company Advanced Metering Infrastructure Deployment, September 18, 2008.

81 See D.13-03-031, Decision Addressing Settlements on Marginal Cost, Revenue Allocation, and Rate Design, March 21, 2013. In this decision, the Commission authorized SCE’s CPP rates. As of July 2013, the current CPP rate is $1.37/kWh. See Schedule CPP for more information.

82 PTR is marketed by SCE as the Save Power Day Incentive program.

83 Generally, CPP events are triggered by high temperatures, electric system emergencies, and/or California Independent System Operator (CAISO) alert or warnings. See Schedule CPP for more information.

84 PTR Event Notifications are an optional service in which SCE provides event notifications to customers via e-mail or text.

85 See D.13-03-031, Decision Addressing Settlements on Marginal Cost, Revenue Allocation, and Rate Design, March 21, 2013. In this decision, the Commission ordered mandatory TOU rates for commercial and industrial customers with demands less than 200 kW on January 1, 2014 and January 1, 2015, as well as mandatory TOU rates for agricultural customers with demands less than 200 kW on February 1, 2014 and February 1, 2015. TOU rate assumptions were a key consideration of D.08-09-039, Decision Approving Settlement on Southern California Edison Company Advanced Metering Infrastructure Deployment, September 18, 2008.

86 See D.08-09-039, in which the Commission authorized SCE’s Web Presentment Tools as part of SCE’s Edison SmartConnect Program; see also D.11-07-056, Decision Adopting Rules To Protect the Privacy and Security of the

(Continued)

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parties,89 Green Button,90 and PEV rates.91 SCE’s CSRs need to be knowledgeable about all of these 1

programs in order to respond to customer inquiries and serve as energy advisors. In addition, see SCE’s 2

supplemental workpapers for customer call scripts, which provide examples of CSR-customer 3

interactions. 4

Given the Commission’s Smart Grid policies regarding supporting 5

Smart Customers, SCE is required to provide adequate customer support to respond to customer 6

inquiries regarding such programs and services. Because these programs and services are inherently 7

more complicated, SCE’s experience to date shows that CSRs are spending more time per call to answer 8

questions and explain the Smart Grid and energy savings benefits to its customers. As a result, SCE’s 9

AHT has increased steadily since the installation of its SmartConnect meters. In support of this analysis, 10

the CCC’s historical AHT demonstrates that, since 2009, AHT has increased at a rate of four percent 11

annually using a three-year historical trend and six percent annually using a two-year historical trend. In 12

Continued from the previous page Electricity Usage Data of the Customers of PG&E, SCE, and SDG&E, July 28, 2011, Ordering Paragraph 6 (“Pacific Gas and Electric Company and Southern California Edison Company shall continue to provide customers with price and usage data…including tariff changes to make price, usage and cost information available to its customers online and updated at least on a daily basis, with each day’s usage data, along with applicable price and cost details and with hourly or 15-minute granularity (matching the time granularity programmed into the customer’s smart meter), available by the next day”); see also SCE’s January 30, 2012 Advice Letter 2693-E Tariff Modifications to Facilitate Providing Price, Usage and Cost Data to Residential Customers for more information.

87 SCE’s Budget Assistant tool was developed to comply with the pricing and usage data requirements in D.11-07-056. Budget Assistant was included as part of SCE’s Edison SmartConnect Program (D.08-09-039).

88 See D.08-09-039 (Commission authorized and required Home Area Network capabilities as part of SCE’s ESC Program); see also Resolution E-4527, September 27, 2012 (Commission reaffirmed SCE’s HAN requirements in regards to HAN registration, infrastructure, collaboration, and interoperability).

89 See D.11-07-056, Decision Adopting Rules to Protect the Privacy and Security of the Electricity Usage Data of the Customers of PG&E, SCE, and SDG&E, July 28, 2011, Ordering Paragraph 8 (“Within six months of the mailing of this decision, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas and Electric must each file an application that includes tariff changes which will provide third parties access to a customer’s usage data via the utility’s backhaul when authorized by the customer.”); see also A.12-03-004, Application of Southern California Edison Company for Approval of Proposal to Enable Automated Access of Customer Usage Data to Authorized Third Parties and Approval of Cost Recovery Mechanism, March 3, 2012, for more information on SCE’s proposal to meet the Commission’s requirements.

90 Green Button provides interval usage data to customers in a downloadable format and is a White House initiative requesting electric utilities to provide their customers with direct access to their energy usage information electronically.

91 See R.09-08-009 for the Commission’s guidance on PEV rate issues.

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addition, for the first five months of 2013, SCE has experienced an AHT of 342, which represents a 13 1

percent increase compared to that in 2012. 2

Not only does CCC support for ESC-enabled programs and 3

services result in AHT increases, but the volume of such customer interactions for program enrollments 4

is expected to increase. SCE expects that, because of Commission policies on dynamic pricing, the 5

enrollment in complex programs and services will increase significantly from 2012 to 2015. For 6

example, the Commission’s mandatory TOU requirement will result in approximately 600,000 small 7

C&I and agriculture service account on a time-differentiated rate. Furthermore, the Commission’s 8

policy on CPP will result in default CPP rates provided to approximately 580,000 small C&I customers. 9

Such increase in AHT is not limited to dynamic rates. For example, consistent with the Commission’s 10

requirements to provide SmartConnect interval data to authorized third parties, SCE expects that the 11

number of customers requesting such new service will exceed 85,000 in 2015.92 These customer 12

enrollment increases are indicative of the expected increase in customer support and contacts required to 13

provide a basic customer service to meet the Commission’s Smart Customer objectives. 14

(c) Increases in Average Handle Time are Necessary to Support 15

the Commission’s Smart Grid Policy Direction and 16

SmartConnect Enabled Programs and Services 17

To comply with the CPUC’s Smart Customer direction SCE 18

requires funding for increased AHT to accommodate the increase in complex programs and services. 19

SCE’s increase in AHT is consistent with the CPUC Policy and Planning Division’s position: “If the 20

customer is to make the transformation into an energy manager, he/she will require a significant amount 21

of education, advice and other personalized resources that will help to facilitate and hopefully automate 22

many of the energy management actions.”93 SCE’s CSRs provide such education, advice, and 23

personalized resources to assist our customers with their energy needs. 24

92 See A.12-03-004, Application of Southern California Edison Company for Approval of Proposal to Enable Automated

Access of Customer Usage Data to Authorized Third Parties and Approval of Cost Recovery Mechanism, March 3, 2012. In A.12-03-004, SCE estimated participation to be 85,000 and 120,000 customers in 2013 and 2014, respectively. SCE’s 2015 participation is dependent upon a Commission decision, which has not yet been issued. As such, for the purposes of this GRC discussion, SCE estimates 85,000 customers in 2015.

93 See Customers as Grid Participants: A Fundamentally New Role for Customers, CPUC Policy and Planning Division, May 15, 2013.

157

As depicted in Figure V-27 below, AHT has steadily increased 1

since the initial deployment of the ESC meters. As of January 1, 2013, 4.9 million customers were 2

being billed using interval data and were therefore eligible for the ESC-enabled programs and 3

technologies described above. In addition, as mentioned earlier, mandatory TOU and default CPP are 4

expected to increase AHT during the 2015 GRC cycle. However, as a conservative assumption, SCE 5

estimates that the long-term trend of increasing AHT will subside. 6

Figure V-27 2009 to 2017 Average Handle Time

Although SCE estimates the number of enrollments in complex 7

programs and services will increase significantly, SCE proposes only a moderate increase in AHT of 8

four percent per year (from 2012 to 2015), which represents an increase of 38 seconds per call, to a new 9

AHT of 342 seconds per call during the 2015 GRC cycle. This forecast assumes that SCE’s CSRs will 10

become more efficient and knowledgeable in engaging our customers over the next three years. SCE’s 11

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proposed four percent per year growth in AHT will result in an incremental 57 FTEs94 in 2015 relative 1

to 2012. Accordingly, SCE proposes a $3.091 million increase in CSR AHT to support the 2

Commission’s Smart Customer objectives. The following two sections will address SCE’s Forecast of 3

an additional $693,000 increase for an increase in the Supervisor-to-Specialist ratio and $247,000 for 4

increased phone bill expense resulting from longer AHT and the forecast increase in call volume. 5

As discussed in Section (3) below, the CCC expects that productivity 6

savings through our Operational Excellence initiative is expected to result in a decrease of 950,000 live 7

agent calls as simpler transactions deflect to self-service channels through SCE.com and the IVR. This 8

will result in an efficiency savings of $2.953 million for reduced call volume. When combined with 9

increased AHT, the net forecast impact for call volumes and AHT is an increase of $385,000. 10

Complex calls caused by ESC-related programs and services also impact 11

SCE’s supervisor staffing levels and resource requirements. In 2012, SCE maintained a relatively high 12

CSR-to-supervisor ratio of 16-to-1. With simple basic service, this ratio was appropriate. However, 13

given the expected volume increase in more complex programs and services, the 16-to-1 ratio is not 14

appropriate to support the Commission’s Smart Customer objectives—according to the Customer 15

Contact Leadership Council, a ratio of 15.56-to-1 is third quartile performance. Thus, SCE proposes to 16

reduce the number of CSRs reporting to CCC supervisors from a ratio of 16-to-1 to a ratio of 12-to-1. 17

The proposed 12-to-1 ratio is consistent with first quartile performance levels defined by the Customer 18

Contact Leadership Council.95 19

By reducing the CSR to supervisor ratio, SCE will enable our CCC 20

supervisors to improve management of day-to-day contact center activities because of the increasingly 21

complex interactions between our customers and our CSRs. This will be accomplished through the 22

monitoring of frontline staff productivity, assisting with frontline staff training and development by 23

providing more individualized supervision of the CSRs as the CSRs provide increasingly more energy 24

advisory services. In addition, supervisors will also be more readily available to respond to the highest 25

level of call escalation, to resolve the increasing complex escalated customer issues and enhance 26

customer experience and improve overall customer satisfaction. To provide this level of customer 27

94 57 FTEs also represents four percent per annum growth in 2015 relative to 2012.

95 See SCE’s supplemental workpapers for “2011 Contact Center Benchmarking Data” provided by the Customer Contact Leadership Council.

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service to support the Commission’s Smart Customer objectives, the CCC will hire seven incremental 1

supervisors, which results in a $693,000 increase to the CCC’s Test Year forecast. 2

(2) Impacts of ESC on Increased Telephone Bills Due to Increased Call 3

Volumes and AHT 4

As AHT increases as described above, we forecast an increase of 5

$247,000 in the telephone bill. This is an increase of two percent per year as a result of the more 6

complex calls. 7

b) Customer Growth 8

SCE customer growth is forecast to increase by 2.06 percent from 2012 to 2015. 9

This adjustment was based on the cumulative annual increases as projected in SCE’s March 2013 10

Annual Retail Sales Forecast. Furthermore, the CCC is directly impacted by customer growth as our 11

CSRs handle the inbound calls or online requests for new service establishment and all other inbound 12

inquiries. As a result, SCE is forecasting a $956,000 increase. This cost increase recognizes that some 13

customer growth will directly impact costs related to automated channels, such as IVR. See the 14

discussion below for more information about self-service productivity assumptions that partially offset 15

SCE’s increase in customer growth. 16

c) Program Changes 17

Providing customer support for ESC-enabled programs and services and emerging 18

contact channels requires additional empowered employees to handle complex transactions; guide 19

customers to the right mix of rates, products, and services; and maintain SCE’s service levels. As 20

described below, SCE requires additional resources to support increases in AHT, increases in supervisor 21

staffing for improved customer education, emerging contact channels, and fair compensation for CSRs. 22

(1) Impacts of Evolving Customer Expectations on Other Contact 23

Channels 24

As technology rapidly advances and innovative practices in other service 25

industries become commonplace, utility customers’ needs and expectations for how their utilities serve 26

them are evolving. The number of customers using online tools and services to execute common utility 27

interactions (e.g., pay bill and turn-on service) continues to increase. Accordingly, consistent with 28

SCE’s Digital Experience program, as described in Chapter I of this Volume, SCE has forecast an 29

increase in other contact channel activities, which includes responding to SCE.com e-mail requests that 30

have grown at a three-year historical trend of seven percent. Web Chat is a newly introduced online 31

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channel that will be progressing as more customers who visit the web expect to have the same level of 1

service as provided by our CSRs. Web chat is one example of SCE’s expanding service using other 2

contact channels. In April 2012, SCE began to provide Web Chat service to assist customers who visit 3

the most frequently accessed SCE.com web pages. This channel is staffed with up to three CSRs who 4

also support live customer calls (which take precedence) and respond to customer e-mail requests. Web 5

chat was introduced with 2012 funding to examine demand and potential customer benefits. This 6

service is currently only available to SCE.com customers 37.5 percent of the time during business hours 7

Monday through Friday, 8:00 a.m. to 5:00 p.m. 8

Some customers will require additional support as they begin to utilize the 9

new tools and information available on the web, mobile, and social media channels. Providing a basic 10

level of other contact channel service and responding to customer inquiries during all normal business 11

hours requires additional staffing resources. SCE estimates that 12 additional CSRs will be required to 12

provide such basic Web Chat service, along with responding to customer e-mail inquiries during normal 13

business hours. This staffing is based on a forecast that 1.50 percent of customers who visit the most 14

frequently accessed SCE.com web pages select the web chat button for assistance. SCE forecasts 15

incremental costs of $755,000 for these resources. Without this funding, SCE will be unable to meet its 16

customers’ expectations of basic customer support. 17

(2) The Expanded Energy Advisory Role for CSRs Requires Fair 18

Compensation 19

As introduced in Exhibit SCE-04, Volume 1, Part III, one of our three key 20

components for engaging customers will be energy advisory services provided by the CCC. To comply 21

with the CPUC’s Smart Customer policy, SCE’s CSRs will expand their role from that of providing 22

traditional basic customer service to a role that provides “a significant amount of education, advice, and 23

other personalized resources.”96 As explained earlier, the number and complexity of new and emerging 24

programs and services is expanding. SCE’s CSRs must be intimately familiar with emerging programs 25

and rates, such as PTR, PTR event notifications, TOU rates, web presentment tools, Budget Assistant, 26

HAN capabilities, data to authorized third parties, Green Button, and PEV rates. Many of these 27

programs rely on interval usage data or emerging technologies and are, therefore, inherently more 28

96 See Customers as Grid Participants: A Fundamentally New Role for Customers, CPUC Policy and Planning Division,

May 15, 2013.

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complicated than providing basic service using cumulative usage data. Not only do SCE’s CSRs need to 1

know about each program’s features and requirements, but they must also act as energy advisors and 2

provide recommendations to our customers using the customers’ historical interval usage data, 3

information about our energy solutions, and industry expertise. CSRs will now be energy advisors as 4

they offer rates, programs, and customized services to best fit the needs for particular customers’ usage 5

patterns. This includes enrolling our customers into programs such as CARE, Direct Pay, and SDP, 6

while assisting them with online billing and payments, SCE.com, and other ESC-related programs. 7

As the CSR’s role evolves into that of energy advisor, the CCC must 8

provide adequate compensation to support this important expanded role. Table V-59 below shows the 9

modest increasing CSR wage trend from 2008 through 2012. 10

Table V-59 CCC Average Hourly Rate

Line No. Year CSR Average Hourly Rate 1 2008 $17.58 2 2009 $18.96 3 2010 $19.68 4 2011 $20.42 5 2012 $21.00

Even without considering the expanded role, the current average wages for 11

our CSRs continue to be significantly lower when compared to other California utilities’ average wages. 12

In fact, the SCE CSR wage is $8.81/hour lower than the average CSR wage of the other California 13

utilities. 14

As discussed above, our CSRs will perform an energy advisor role in 15

2015. The current market data for the Energy Advisor role through a Towers Watson Energy and 16

Towers Watson General Industry Survey shows that the average salary for a residential Energy Advisor 17

is $7.93 higher than our current CSR hourly salary. However, SCE is proposing a modest average wage 18

increase of $2.00 per hour for its CSRs in 2015. Without this increase, SCE will not be able to attract 19

and retain more highly skilled employees to effectively support the expanded energy advisor role and 20

provide the education, advice, and other personalized resources required to maintain satisfactory levels 21

of customer support and engagement. This modest wage increase will result in a $1.868 million increase 22

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in SCE’s Test Year forecast and is based upon an average of 449 CSRs who would qualify for a wage 1

increase.97 2

(3) Productivity - Operational Excellence 3

SCE is forecasting a total Operational Excellence reduction of $3.731 4

million by the 2015 Test Year as a result of the following two productivity initiatives. 5

(a) Self-Service Productivity is Dependent upon Customer 6

Adoption of Self-Service Channels 7

As described by in Exhibit SCE-05, Volume 2, Part I, SCE expects 8

to expand the volume of self-service transactions through SCE.com and the IVR. The forecast increase 9

in self-service transaction will offset call volumes and customer growth experienced by the CCC, as 10

customers will resolve simpler, routine-type transactions, such as account balances and payment 11

arrangements, using self-service options.98 The CCC’s productivity is directly dependent upon the 12

success in three areas: (1) capitalized software projects to ensure the self-service channels are enhanced 13

to meet customer needs, (2) effective customer marketing, and (3) customer adoption of these self-14

service channels. As a result, SCE is forecasting only 50 percent of its 2015 forecast decrease due to the 15

uncertainty of fully achieving all three elements, which will result in the reduction of approximately 16

950,000 fewer live agent calls in 2015. Accordingly, the CCC forecasts 2015 operational cost savings 17

of $2.953 million.99 18

(b) Streamlining of Support Work 19

SCE also identified $778,000 of operational efficiency savings in 20

2015. These savings reflect an analysis of administrative support, support analyst, and project 21

management work that will be streamlined. By increasing our administrative staff ratios, we have been 22

able to reduce administrative work and consolidate resource coordination efforts to support our highest 23

priority work. Through continuous project improvement efforts, we have consolidated strategic 24

initiatives while minimizing project support for these initiatives. As technology improves our processes, 25

97 $2.00/hour x 449 CSRs x 2080 hours/year = $1.868 million.

98 Customers will also be able to receive mobile text or e-mail alerts for billing, payment, demand response, and outage communications.

99 SCE’s forecast operational savings in 2013 and 2014 are approximately $156,800 and $893,700, respectively. SCE’s 2015 internal operational savings target is $5.906 million. SCE’s 2015 mid-point operational savings is 50 percent of the target or $2.953 million.

163

we will continue to address our support functions to optimize and gain efficiencies. SCE expects that 1

such savings will materialize in 2015 and will continue in future years. 2

164

VI. 1

PROGRAM MANAGEMENT ORGANIZATION (PMO) 2

A. Description of Program Management Organization Function 3

The Program Management Organization (PMO) is responsible for managing the Customer 4

Service Operating Unit’s project and technology portfolio in support of SCE’s Customer Engagement 5

model described in Volume I of this Exhibit. This includes identification, prioritization, and oversight 6

of system enhancements and technology investments to enable SCE to meet customers’ evolving needs 7

and to achieve operational excellence. The PMO also plays a key role in deploying SCE’s technology-8

enabled customer service model by providing program management of wireless communications and 9

internet-based services projects that have become a preferred method of customer interaction with SCE. 10

The PMO develops and maintains the CS long-term capital systems and business capabilities 11

plan, the portfolio planning, and governance process and assesses the sustainability of critical systems. 12

The group applies standard processes in planning, prioritizing, tracking of projects, and project 13

management, tools, and resources for large-scale, cross-functional, and process improvement projects. 14

Activities performed include a broad spectrum of project management duties, including conducting 15

business requirement sessions; defining scope, schedule, and budget; and obtaining business case 16

approvals while executing projects from strategy development through design, development, go-live, 17

and post-implementation triage and stabilization. The organization will expand its focus on optimized 18

data management and complex business analytics for improved operational and strategic decision-19

making. 20

With investments in technology-enabled service improvements, the size of the Customer Service 21

application systems portfolio has grown considerably. There has been a substantial increase in the 22

number of applications and function points supported, thereby increasing the governance responsibility 23

and portfolio complexity. As the technology portfolio continues to expand to support digital customer 24

experience channels and to assist customers in managing their energy needs, the role of the PMO to 25

manage the overall portfolio and oversee future automation projects remains critical. 26

B. Operating Results 27

During 2012, the PMO supported the Customer Service technology portfolio functions by (1) 28

processing, prioritizing, and tracking maintenance requests for Information Technology resources to 29

execute and (2) applying Enterprise Portfolio Management processes for project initiation, approval, 30

project development, and life cycle oversight. The organization supported numerous operational 31

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improvement projects in response to regulatory compliance or critical operational needs and provided 1

oversight of four capitalized software programs, to effectively manage the highly-complex projects from 2

initiation to successful implementation. 3

C. Analysis of Historical Data (FERC Account 907.700) 4

The recorded/adjusted costs for PMO’s activities are shown in Table VI-60 below and were 5

derived after analyzing recorded costs for this activity and adjusted to reflect ongoing business 6

operations. 7

Table VI-60 Program Management Organization

2008-2012 Recorded and Adjusted Expenses FERC Account 907.700



1 Labor Expense 2,015 1,948 2,980 3,316 3,056

2 Non-Labor Expense 786 2,093 3,981 5,075 2,922

3 Other - - - - -


Due to the cyclical nature of the projects supported, the organization has experienced various 8

cost fluctuations year to year, as shown in Table VI-60. The annual fluctuations noted are in line with 9

project life cycle trends based on timing, number of projects, and project size. Labor expenses in 2010 10

increased by $1.032 million as a result of additional project management personnel to provide oversight 11

for increases in the number and size of routine and complex system enhancement and capital software 12

projects. Labor expense increased again in 2011 by $0.336 million because of further increases in 13

projects managed by the organization. In 2012, labor expenses decreased minimally due to timing of 14

staff attrition and hiring. In 2009 non-labor costs increased by $1.307 million as a result of increased 15

activity including analysis, technical consultation, and oversight of an expanding number of projects. In 16

2010, non-labor expenses increased by $1.491 million due to growth in size and number of projects plus 17

$0.399 million for software licenses. In 2011, non-labor expenses increased by $1.095 million to 18

support technology strategy project planning, requirements analysis, and business case development of 19

major capital projects. In 2012, non-labor expenses declined by $2.153 million resulting from the 20

166

completion of fewer complex operational improvement projects, coupled with the conclusion of the 1

planning phase for several large technology projects. 2

D. Test Year Expectations (FERC Account 907.700) 3

Figure VI-28 shows the recorded/adjusted historical and forecast expenses for the PMO function. 4

Details regarding the forecast O&M expenses for this function are described below. 5

Figure VI-28 Program Management Organization


1. Determination of Test Year Estimating Method 6

As shown in Figure VI-29 below, SCE recorded $5.978 million for these activities in the 7

Base Year. While labor costs and non-labor costs have fluctuated during the period 2008–2012, the 8

most recent year accurately reflects expense levels associated with current activity levels and, therefore, 9

the Last Recorded Year was selected as the appropriate basis for forecasting labor and non-labor O&M 10

expenses for this FERC Account. 11

167


The PMO forecasts adjustments in three areas, totaling $1.437 million. Figure VI-29 2

below shows the Test Year forecast for FERC Account 907.700 compared to the Base Year. The areas 3

supporting the organization’s Test Year adjustments are described below. 4

Figure VI-29 Program Management Organization


a) Data Management 5

Changes to our future operational requirements include the development of 6

optimized data management and complex business analytics for improved operational and strategic 7

decision-making. The supporting framework will include data and information governance and 8

oversight, data conversion for use in predictive analysis, and identification of risks and opportunities for 9

improved data management. The organization requires funding to develop this area. To perform this 10

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necessary activity, two resources will be added in 2013, and three resources will be added in 2014 at a 1

cost of $630,000. 2

b) Portfolio Oversight Staffing 3

In the final quarter of the Base Year, three employees were hired to support and 4

align with increasing portfolio levels. At the time of filing this Application, the organization will have 5

achieved proper staffing levels to support current portfolio and future project activities. Therefore, 6

while the employees are part of current staffing levels, the total annual costs associated with the 7

employees hired late in 2012 are not reflected in the Base Year expense. An adjustment of $267,000 has 8

been added to the Base Year cost for these employees hired at the end of the Base Year to reflect the 9

annual expense of proper staffing levels. 10

c) O&M Related to Capital Programs 11

In support of the technology-enabled customer service model, various high-level 12

planning, pre-engineering, and other capital software-related expenditures precede and occur throughout 13

the development period of each capital software initiative. These expenditures, which are non-14

capitalizable and are properly charged to O&M include supplemental facilities expenses for 15

requirements gathering sessions, business process mapping and business case development meetings, 16

communication and training materials associated with business readiness activities, incidental meals, 17

and employee recognition expenses. The organization forecasts expenses to align to the planned 18

Customer Service capital software portfolio levels, as shown in Table VI-44 titled “Estimated 19

Capitalized Software Project Expenditures for 2013 – 2017” in SCE 05, Vol. 2, Part I. The O&M 20

expenditures related to capital programs represent less than three percent of capital software 21

expenditures. Based on CS capital software forecasts for 2014-2017 and historical O&M spend 22

recorded, the organization forecasts additional funding in the amount of $541,000 to support the capital 23

software project portfolio. 24

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VII. 1

CONSUMER AFFAIRS AND CUSTOMER SATISFACTION 2

The Consumer Affairs and Customer Satisfaction organizations receive and gather feedback 3

from SCE’s customers to answer customer inquiries, resolve consumer complaints, and improve their 4

interaction with SCE’s programs and services. These activities are described in detail below and costs 5

related to these activities are recorded in FERC Account 905.800.100 6

A. Consumer Affairs Function 7

The Consumer Affairs function, Base Year operating results, and Test Year expectations are 8

described below. The impact of Consumer Affairs activities on historic and forecasted O&M expenses 9

in FERC Account 905.800 are described in Sections VII.C. and VII.D. 10

1. Description of the Consumer Affairs Function 11

Consumer Affairs has two main areas of responsibility: (1) handling escalated customer 12

inquiries and complaints transferred from the Commission or received directly by SCE and (2) 13

administering and delivering programs and services available to our Medical Baseline (MBL) and 14

special needs customers. “Special needs customers” include critical care, elderly (seniors), and disabled 15

customers.101 16

2. Consumer Affairs Base Year Operating Results 17

a) Customer Inquiry and Complaint Handling 18

Consumer Affairs handles a variety of escalated inquiries and complaints. 19

Inquiries and complaints are transferred to us from the Consumer Affairs Branch of the Commission’s 20

Consumer Service and Information Division. Consumer Affairs also handles inquiries and complaints 21

received in SCE’s executive offices. The type of inquiries and complaints handled include telephone 22

inquiries/complaints, informal complaints filed with the Consumer Affairs Branch, and written 23

inquiries/complaints.102 As shown in Table VII-61, Consumer Affairs resolved 4,704 inquiries and 24

complaints in 2012.103 25

100 In SCE’s 2012 GRC Phase 1 Application, the costs associated with the Customer Satisfaction and Consumer Affairs

activities were included in FERC Accounts 905.800, 905.900, and 908.640.

101 For purposes of this testimony, SCE uses “physical disability” as defined in Cal. Gov’t Code § 12926(k); see workpapers for a list of programs and services administered by Consumer Affairs.

102 Informal complaints are written complaints transferred to SCE from the Consumer Affairs Branch for resolution. For each Informal Complaint, Consumer Affairs is required to conduct an investigation and provide written resolution to the

(Continued)

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Table VII-61 Inquiries and Complaints Resolved by Consumer Affairs

Line No.

Description 2008 2009 2010 2011 2012

1 Telephone Complaints 3,892 3,526 3,169 2,790 2,6042 Informal Complaints 1,239 1,594 1,192 1,262 1,4573 Written Inquiries 413 490 492 608 6434 Total Complaints and Inquiries 5,544 5,610 4,853 4,660 4,704

As shown in Table VII-61, the total number of inquiries and complaints has 1

declined over the past five years. Telephone complaints, which make up the largest portion of total 2

complaints, have dropped steadily over this period. Informal complaints and written inquiries, however, 3

have increased steadily since 2010. The CPUC’s implementation of the Residential Disconnect OIR, 4

which raised the requirements that must be met prior to SCE’s disconnecting a residential customer, has 5

contributed to an overall decline in inquiries and complaints.104 This decline, however, has been offset 6

by increases in written inquiries and informal complaints related to the NEM tariff and the deployment 7

of ESC in 2011 and 2012. 8

Table VII-62 Consumer Affairs Average Complaint Resolution Time105

Description 2008 2009 2010 2011 2012

Complaint Resolution Cycle Time (days) 7.9 7.1 8.3 9.6 13.9

Despite the decline in the total number of inquiries and complaints shown in 9

Table VII-61, SCE has seen an increase in the average complaint resolution time from 7.9 days in 2008 10

to 13.9 days in 2012 as shown in Table VII-62. Many factors have contributed to this increase. First, 11

informal complaints and written inquiries received by SCE’s executive offices are typically more 12

Continued from the previous page customer and written documentation to the Consumer Affairs Branch. Consumer Affairs provides a response to all written inquiries or complaints that are received by SCE’s executive offices.

103 See workpapers for additional historic inquiry and complaint information.

104 The Commission initiated the Residential Disconnect OIR (R.10-02-005) in February 2010.

105 Complaint resolution time is the time from receipt of complaint through issue closure, including actual presentation of a new statement delivered to the customer. Closure with the customer may occur much earlier, but Consumer Affairs considers an issue open until all relevant activities have been completed.

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complex and take more time to resolve than those initiated through telephone calls. The issues 1

addressed by Consumer Affairs have become more complex due to introduction of more complex rates 2

and programs enabled by advances in meter technology. In addition, issues relating to NEM have 3

increased, particularly with regard to the rate and mechanism for compensating customers for their 4

excess generation and are more complex than those encountered in non-NEM billing issues. Inquiries 5

and discussions regarding Edison’s Smart Meter program, particularly relating to customer privacy, 6

health concerns, and meter options, are also more challenging and time-consuming compared to 7

traditional consumer complaints. In order to meet the growing complexity of customer inquiries and 8

complaints, the Consumer Affairs staff has received training to acquire greater knowledge about the 9

issues customers are facing. Cycle times were also impacted because the department experienced some 10

resource issues in 2012 due to turnover and short-term vacancies. These vacancies have been filled, 11

improvements have been implemented, and more senior Consumer Affairs representatives may focus on 12

informal complaints. 13

b) Outreach Programs 14

Consumer Affairs communicates with SCE’s special needs customers, especially 15

those with financial difficulties or medical conditions, in a number of ways. One way is through the 16

MBL program for customers who require electricity-powered medical life support equipment in the 17

home. Customers enrolled in the MBL program are granted a greater supply of the lowest-cost 18

electricity (Baseline Allocation) each month. Consumer Affairs works with a number of Community 19

Based Organizations (CBOs), government agencies, and others, such as disability and senior 20

collaboratives, senior centers, and regional centers to educate customers and service providers about 21

SCE rates, programs, and services and help identify customers who might qualify for the MBL 22

program.106 As shown in Table VII-63, enrollment in the MBL program has grown steadily from 2008 23

to 2012 with the total participation in 2012 being approximately 41 percent higher than in 2008.107 24

106 In D.12-11-051, the Commission required SCE to provide a description of its efforts to include and work with CBOs in

all aspects of customer education and outreach in this GRC. See D.12-11-051, p. 352. This report is included in Appendix B of this Volume.

107 SCE’s Medical Baseline program is administered by SCE’s Program Services function as described in Section IV.A.1.a)(3) above.

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Table VII-63 Historical Medical Baseline Participants by Type108

Medical Baseline Enrollment Category 2008 2009 2010 2011 2012

Critical Care 9,200 10,913 12,261 12,870 13,790

Non-Critical Care 42,173 46,883 50,395 52,555 58,733

Total 51,373 57,796 62,656 65,425 72,523

SCE’s Consumer Affairs group also takes special precautions with these 1

customers in the case of an outage. SCE attempts to collect preferred alternate contact information for 2

each MBL Customer through the customer’s MBL application and renewal applications. MBL 3

customers may also request that information be updated when speaking with a call center representative. 4

In an annual letter sent to all MBL customers, SCE further reminds such customers to provide any 5

updates to their contact information. In 2012, SCE expanded its outage management communications to 6

MBL customers. These expanded efforts are described in Section VII.B.2.a) below. 7

Consumer Affairs also plays a role in SCE’s response to outages beyond that 8

described above for MBL Customers. For example, during an extended outage, Consumer Affairs may 9

distribute ice, water, flashlights, and safety information to customers who are without power.109 10

Historically, these distribution events occur once or twice per year and are usually in a single 11

geographical location. During the windstorm of November and December 2011, SCE set up seven 12

distribution sites in various cities within the San Gabriel Valley, where most of the windstorm damage 13

occurred. 14

SCE is also working to engage Regional Centers in its territory so that SCE may 15

use their outbound calling systems to communicate with customers with disabilities during disasters 16

resulting in extended power outages.110 Using these systems, SCE may inform affected customers of 17

108 Critical Care customers are those who are able to survive two hours or less without electricity.

109 SCE defines an extended outage as an outage expected to last 12 or more hours.

110 Regional centers are nonprofit private corporations that contract with the California Department of Developmental Services to provide or coordinate services and supports for individuals with developmental disabilities.

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sites providing supplies such as water, ice, and flashlights, as well as Cool Center locations during the 1

summer.111 2

Consumer Affairs also plays a role in helping special needs customers avoid 3

credit-related disconnects. Specifically, Consumer Affairs receives advance notice from our Corporate 4

Credit department of special needs customers’ accounts subject to disconnection. Consumer Affairs 5

attempts to reach these customers to alert them of possible disconnection and tries to secure payment, 6

make payment arrangements, or provide information regarding agencies able to aid the customer with 7

bill payment. Methods used to reach these customers include phone calls and direct mail. When we are 8

unable to contact customers through these means, we may request that Wellness Checks be performed 9

by Adult Protective Services. 10

SCE’s Consumer Affairs group also maintains a Good Neighbor Program, which 11

aims to connect SCE customers and members of the community with organizations whose mission it is 12

to provide them with social services. A referral to this program may take place when an SCE employee 13

encounters an SCE customer or community member who may need social services. In some instances, 14

Consumer Affairs may also contact Adult Protective Services and request that they conduct a Wellness 15

Check. During the period of 2010-2012, SCE employees referred 393 customers to the Good Neighbor 16

Program. Senior citizens comprised 67 percent of these customers, 76 percent were on the 17

CARE/FERA Income Qualified Programs, and 10 percent were registered MBL customers. 18

3. Consumer Affairs Test Year Expectations 19

SCE plans to continue to conduct Consumer Affairs activities in the Test Year within 20

existing funding levels. As noted in Section VII.A.2 above, over the past five years SCE has witnessed 21

a rise in the average cycle time for complaint resolutions addressed by the Consumer Affairs group. In 22

addition, when the provisions of the Residential Disconnect OIR expire, SCE expects a significant rise 23

in credit-related customer complaints. Similarly, SCE expects that the implementation of default 24

Critical Peak Pricing for small business customers with demands less than 200 kW and growth in 25

adoption of technologies, such as Home Area Network (HAN) and Plug-in-Electric Vehicles (PEV), will 26

also drive increases in inquiries and complaints. SCE expects that, by 2015, employees in Consumer 27

111 SCE’s Cool Centers are operated as a service to assist low-income and senior residential customers, provide respite from

the heat, and help them lower their utility bills. SCE’s Cool Center Program is funded through SCE’s California Alternative Rates for Energy (CARE) and Energy Savings Assistance (ESA) Programs and Budgets Application. See D.12-08-044, Ordering Paragraph 25.

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Affairs will have gained experience in dealing with the increasingly complex customer issues they are 1

likely to encounter. This, combined with increasing customer adoption of online tools, such as Budget 2

Assistant, and proactive efforts to address customer billing inquiries, will enable SCE to address these 3

issues using existing resources. Therefore, SCE does not forecast an increase in O&M expenses for 4

Consumer Affairs activities in the Test Year. 5

B. Customer Satisfaction Function 6

The Customer Satisfaction function, Base Year operating results, and Test Year expectations are 7

described below. The impact of Customer Satisfaction activities on historic and forecasted O&M 8

expenses in FERC Account 905.800 are described in Sections VII.C and VII.D. 9

1. Description of Customer Satisfaction Function 10

SCE’s Customer Satisfaction function leads the identification, prioritization, and 11

management of customer service improvement opportunities to continue to meet evolving base level 12

customer service expectations. Customer feedback and satisfaction benchmarking studies provide 13

insight to inform these improvement opportunities, as well as a means to measure the level of customer 14

satisfaction with the services that SCE provides on an ongoing basis. 112 Examples of specific Customer 15

Satisfaction improvement activities are described in Section 2 below. 16

2. Customer Satisfaction Base Year Operating Results 17

SCE continuously works to improve the quality of the programs, processes, services, 18

channels, and transactions it provides to all customers. Based on customer feedback and benchmarking 19

studies, SCE focused heavily on two critical process improvements: (1) outage management and 20

communications and (2) high bill inquiries. Results achieved from these efforts are described in detail 21

below. 22

a) Improving Outage Management Communications 23

When customers experience an outage, one of the most important factors to their 24

satisfaction is communication about the outage. The J.D. Power 2012 Residential and 2013 Business 25

Electric Utility Customer Satisfaction Studies indicate that customer satisfaction scores are significantly 26

112 The customer-facing service processes that the Customer Satisfaction function monitors are the following: (1) Turn-

On/Transfers, (2) Questions About the Bill, (3) Credit and Payment Experiences—Final Call, (4) Trouble Orders—Area, (5) Planned Outages, (6) Program Sign-Up, and (7) Assigned Business and Government Customers. Customer service channels evaluated by the Customer Satisfaction function include customer service representatives at the CCC, account managers assigned to work with business customers, and SCE.com.

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higher when the utility provides and communicates multiple points of information related to an outage. 1

This includes information regarding when power will be restored, magnitude of the outage (e.g., the 2

number of customers affected), and status of repair (e.g., whether SCE is en route to fix the problem). 3

Additionally, research informs SCE that customers would like to receive communication through their 4

preferred channel(s), which may include email, text, web, phone, or social media. The J.D. Power 2012 5

Residential and 2013 Business Electric Utility Customer Satisfaction Studies indicate that over eight in 6

ten SCE residential customers and nine in ten SCE business customers want to be proactively contacted 7

with outage updates and information, and the vast majority of residential and business customers are 8

willing to provide their phone or email contact information to SCE for this purpose. Customers 9

receiving outage information through electronic/mobile forms of communication (including social 10

media) are significantly more satisfied than those obtaining information through more traditional 11

channels.113 12

Lessons learned from the experience of several East Coast utilities (Con Edison, 13

Pepco, PSE&G, and New Jersey Natural Gas) as a result of Hurricane Sandy demonstrate the 14

importance of managing customer expectations and multiple communication channels to provide critical 15

information prior to and during the aftermath of major storm events Their multi-pronged approach 16

made use of both traditional media (press releases, outbound and inbound calls, in-person meetings, and 17

direct mail) and newer digital media (website updates in general and on My Account, outage maps, 18

mobile apps, e-mail blasts with updates and global estimated response times (ERTs), and postings on 19

Twitter, Facebook, Flickr, and YouTube), among other things. These utilities indicate that social media 20

access and usage, in particular, grew dramatically during this emergency period.114 21

In 2012, SCE implemented a number of changes to improve how it communicates 22

to customers before and during outages. 23

(1) Accessing Outage Information Via Mobile Devices 24

SCE launched a mobile application in July 2012 that allows customers to 25

view outage information, report outages, and request status updates via e-mail, text, or phone, in 26

113 J.D. Power & Associates, 2012 Electric Utility Residential Customer Satisfaction Study (July 7, 2012), available at

http://www.jdpower.com/content/press-release/d7cFGW5/2012-electric-utility-residential-customer-satisfaction-study.htm; J.D. Power & Associates, 2013 Electric Utility Business Customer Satisfaction Study (February 13, 2013), available at http://www.jdpower.com/content/press-release/dTFT2FN/2013-electric-utility-business-customer-satisfaction-study.htm.

114 See workpapers for additional information on the role of social media in utility responses to Hurricane Sandy.

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addition to utilizing SCE.com. The mobile application received over 29,000 downloads in the six 1

months available in 2012, and the volume of outage map visits on SCE.com has doubled, from an 2

average of 30,000 per month to over 60,000 per month.115 3

(2) Reaching our MBL customers during an outage 4

SCE also enhanced its efforts to provide important information to MBL 5

customers during an outage. In accordance with our Settlement Agreement with Disability Rights 6

Advocates (DisabRA) approved in our 2009 GRC Decision (D.09-03-025), SCE implemented a system 7

to notify Medical Baseline customers via text, Teletypewriter System (TTY), or e-mail in the event of an 8

outage.116 In 2012, this system was expanded to include automated phone messages, which now 9

represents 71 percent of the notifications.117 In addition, in order to help ensure customer safety, SCE 10

implemented a new procedure to use field employees to make personal visits to impacted Medical 11

Baseline (MBL) customers should an outage be expected to last more than 12 hours and if SCE is unable 12

to make direct contact with someone in the home. A summary of SCE’s MBL outage communication 13

activity in 2011-2012 is shown in Table VII-64. 14

Table VII-64 Medical Baseline Outage Communication Summary

(2011-2012)

Line No.

Description 2011 2012

1 MBL Customer Outage Notifications 24,180 161,933 2 MBL Customer Extended Outage Notifications - 4,284 3 MBL Customer Extended Outage Field Orders - 1,969

(3) More Timely Outage Notifications 15

Another enhancement SCE implemented to improve communications with 16

customers during outages was providing them with a forecasted estimated restoration time (FERT) in the 17

115 From January through July, 2012, outage map visits totaled approximately 209,000 or 30,000 per month. From August

through December, 2012, outage map visits totaled approximately 303,000 or over 60,000 per month. Outage map visits totaled over 510,000 in 2012. See Table VIII-66 for additional online usage trends.

116 See D.09-03-025, Ordering Paragraph 26 and Southern California Edison Company (U 338-E) and Disability Rights Advocates Joint Motion for Approval of Settlement (May 23. 2008), Attachment A, p. 9.

117 See workpapers for additional information regarding MBL outage notifications. All MBL customers receive outage alerts by default and have the ability of opting out of such alerts.

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first hour of an unplanned outage, which helps customers to plan accordingly.118 Before the 1

implemented changes, restoration estimates were provided to customers only after a visual inspection by 2

the field crews, which typically occurred six hours into an outage. After the implemented changes, SCE 3

now provides its customers with estimates 84 percent of the time within the first hour of the outage.119 4

Additionally, business customers now receive automated messages for 5

both planned and unplanned outages. The launch of automated outage communications has resulted in 6

an increase of proactive outage communications, from fewer than 40,000 in 2011 to approximately 7

780,000 in 2012. During unplanned outages, business customers receive a message that SCE is aware 8

they are affected by an outage, status updates, and restoration notices. During planned outages, 9

customers receive automated alerts of the scheduled maintenance, a reminder the day before, and notices 10

of cancellations, reschedules, or delays. Prior to automated communications, customers received 11

notifications three to five days before the scheduled date. With the automated communications, 12

customers now receive notice 10 days before the scheduled date. 13

b) Proactively Addressing High Bill Inquiries / Questions About the Bill 14

The second focus area SCE worked to address is the customer’s experience with a 15

higher-than-normal bill. As more ESC meters were installed and customers began using the online tools 16

to monitor their usage, SCE experienced an overall reduction in billing complaints. The deployment of 17

ESC meters also reduced the number of easily-addressed billing inquiries caused by erroneous manual 18

meter reads. As a result, the remaining inquiries were more difficult to resolve, resulting in lower 19

satisfaction levels than in prior years. 20

To address this trend, SCE launched an effort in the fourth quarter of 2012 to 21

improve customer communications and customer service skills to resolve high bill-related issues more 22

effectively. To improve customer communications, SCE provided an early proactive alert to customers 23

with forecast increased usage and billing amounts. The goal was to reduce bill “sticker shock” at the 24

end of their bill period. The proactive email communication was sent to a subset of residential My 25

Account customers who, around day 11 of the billing cycle, were forecast to exceed their previous bill 26

amount by 30 percent and $50 as compared to either the prior month or same month in the prior year. 27

118 The FERT is calculated based on geographic historical data of outage restoration of the affected device and is updated

once field crews have completed their visual inspection.

119 The percentage of customers receiving estimated restorations times within the first hour of an outage are based upon data gathered in April 2013. See workpapers for additional information on FERT delivery times.

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To more effectively serve those customers who did call with a high bill inquiry, 1

customer service specialists received special training to more efficiently help customers identify the 2

cause of the high bill and provide customers with relevant solutions to better manage their bills in the 3

future. 4

This targeted effort yielded a 35 percent increase in customer log-ins to SCE.com 5

to see next projected bills and a 31 percent increase in customers satisfied with SCE’s efforts to help 6

them manage their bills, as compared to customers who were not included in the effort.120 SCE is 7

currently operationalizing such improvements to the wider customer base. 8

3. Customer Satisfaction Test Year Expectations 9

The Customer Satisfaction function will continue to identify, prioritize, and manage 10

improvements to SCE customer service operations. In 2015, SCE plans to continue to monitor and 11

manage the Outage Communications improvements implemented in the Base Year, while also 12

identifying additional opportunities to improve in this important area. As described above, SCE plans to 13

expand its initial Proactive High Bill Inquiries effort to a wider base of customers. As this is 14

accomplished, the Customer Satisfaction group will continue to monitor bill-related customer inquiries. 15

Continued monitoring and improvement of SCE’s customer service operations is required 16

in this GRC period due to the continuing introduction of new energy management technologies, changes 17

in the technologies that support our customer-facing processes, and anticipated changes in rates, such as 18

the implementation of dynamic pricing for non-residential customers and the Residential Rate OIR, all 19

of which require engaging our customers, so they can make informed decisions and benefit from these 20

anticipated changes. As described in Volume 1 of this Exhibit, SCE will build engagement with 21

customers to help them better manage their energy usage, take advantage of rates and programs that 22

benefit them, adopt new and emerging technology, and use energy safely. As a result, Customer 23

Satisfaction will need to continue to conduct customer feedback and satisfaction benchmarking studies 24

and introduce process improvement opportunities. This higher level of engagement will require more 25

responsive customer service processes that will succeed to the extent that the Customer Satisfaction 26

function can quickly identify, assess, and implement process changes. SCE expects to support these 27

activities with existing resources and is not forecasting an increase in O&M expenses for Customer 28

Satisfaction activities in the Test Year. 29

120 See workpapers for additional information regarding the results of SCE’s High Bill Inquiry effort.

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C. Analysis of Historic Data (FERC Account 905.800) 1

The recorded/adjusted costs for the Consumer Affairs and Consumer Satisfaction activities 2

shown in Table VII-65 were derived after analyzing recorded costs for these activities and adjusted to 3

reflect ongoing business operations. 4

Table VII-65 Consumer Affairs and Customer Satisfaction

Recorded/Adjusted Expenses (2008-2012) FERC Account 905.800

(Constant 2012 $000) Line No.

Customer Satisfaction and Consumer Affairs

2008 2009 2010 2011 2012

1 Labor Expense 3,087 3,041 3,165 2,940 3,181 2 Non-Labor Expense 3,374 2,763 2,800 2,518 2,052 3 Other - - - - - 4 Total Operation Expense 6,461 5,804 5,965 5,458 5,233

As shown in Table VII-65, labor expenses remained relatively stable for the period 2008-2009. 5

In 2009, non-labor expenses declined by $611,000 as a result of our efforts to identify efficiencies and 6

best practices through industry benchmarking of both utilities and non-utilities, consolidating the 7

Service Delivery Satisfaction (SDS) study to one research vendor (from the two suppliers used 8

previously), achieving significant cost savings through the competitive-bid vendor selection process, and 9

implementing other improvements in the data collection and analysis methods used in the SDS study. In 10

2010, labor expenses increased by $124,000 due to an increase in market research staffing levels to 11

support market intelligence and analytics. Non-labor during this period remained stable. 12

In 2011, labor expenses decreased by $225,000 due to a number of vacancies in market research 13

in 2011. SCE also began to review and streamline the way in which it conducts market research leading 14

to some immediate adjustments to study scope and specifications. As a result of this effort, combined 15

with the completion of SCE’s periodic residential research segmentation study, non-labor costs declined 16

by $282,000 in 2011. 17

In 2012, labor expenses increased by $241,000 due to the filling of vacancies and increased 18

outage communication support. In 2012, SCE continued to streamline its market research costs in 19

earnest by re-calibrating all of its core customer satisfaction measures, particularly the SDS study (again 20

by conducting industry benchmarking and holding internal discussions with key SCE operations 21

management). As a result, SCE made several cost-saving changes, maintaining (with some scope and 22

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sample size modifications) those measures with highest value to the company and eliminating others. 1

This major measurement re-design effort, combined with a reduction in contractor employees and 2

employee related expenses, resulted in a reduction in non-labor costs of $466,000. 3


Figure VII-30 shows the recorded/adjusted historical and forecast expenses for the Consumer 5

Affairs and Customer Satisfaction function. Details regarding the forecast O&M expenses for this 6

function are described below. 7

Figure VII-30 Consumer Affairs and Customer Satisfaction



As shown in Table VII-65 above, SCE recorded $5.233 million for these activities in the 9

Base Year. As described above, labor costs have been relatively stable over the last five years, making 10

the Last Recorded Year the appropriate trending method. Although non-labor costs have declined 11

during this period, the most recent year accurately reflects expense levels associated with current 12

activity levels and, therefore, the Last Recorded Year was selected as the appropriate basis for 13

forecasting non-labor O&M expenses for this FERC Account. 14

181


As described in Sections VII.A.3 and VII.B.3, SCE does not forecast an increase in O&M 2

expenses for these activities in the Test Year. Figure VII-31 shows the Test Year forecast for FERC 3

Account 905.800 compared to the Base Year. 4

Figure VII-31 Consumer Affair and Customer Satisfaction


$5,233 $5,233

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

2012 Recorded 2015 Forecast

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VIII. 1

MARKETING, COMMUNICATIONS AND DIGITAL 2

DELIVERY OF CUSTOMER SERVICES 3

The Marketing, Communications and Digital Delivery of the Customer Services function enables 4

SCE’s residential and non-residential customers to be aware of and make informed decisions about 5

rates, programs, and services that benefit them; helps customers with new technology, such as Home 6

Area Network (HAN) and Plug-in-Electric Vehicles (PEV); and facilitates safe energy usage.121 This 7

function is comprised of Marketing and Communications and Digital Delivery of Customer Services 8

activities, as described below. The costs associated with these activities are recorded in FERC Account 9

905.900.122 10

A. Marketing and Communications Function 11

The Marketing and Communications function, Base Year operating results, and Test Year 12

expectations are described below. The impact of Marketing and Communications activities on historic 13

and forecast O&M expenses in FERC Account 905.900 are described in Sections VIII.C and VIII.D. 14

1. Description of the Marketing and Communications Function 15

The Marketing and Communication function engages customers with energy 16

management solutions as described above. The primary customer engagement activities that comprise 17

this function include gaining an understanding of customer needs and information, matching customers 18

with SCE programs and solutions, and reaching customers with the right mix of delivery channels. SCE 19

utilizes a variety of channels (direct mail, bill messages, SCE.com, e-mail, social media, community 20

grassroots organizations, events, and third parties, including retailers, distributors, manufacturers, and 21

industry organizations) in multiple languages to enable SCE’s diverse customers to better manage their 22

usage; become aware of programs, services, and rates that benefit them; adopt new technology; and use 23

energy safely. 24

2. Marketing and Communications Base Year Results 25

In 2012, SCE conducted three main types of Marketing and Communication efforts: (1) 26

a comprehensive annual summer conservation campaign; (2) outreach for specific individual programs, 27

121 PEV education and outreach costs are included in FERC Account 588 and are discussed in Exhibit SCE-09, Chapter V.

122 In SCE’s 2012 GRC Phase 1, these activities were included in FERC Accounts 905.900, 908.640, and 916.600. In this GRC, these activities are consolidated in FERC Account 905.900.

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such as dynamic pricing, Budget Assistant, PEVs, and PGC-funded programs; and (3) rate 1

communication activities. These efforts are described below.123 2

a) Comprehensive Annual Summer Conservation Campaign 3

SCE conducts a comprehensive annual Summer Readiness Campaign with the 4

overall campaign objectives to (1) help customers to take steps to conserve electricity to maintain 5

reliability, (2) provide solutions to help customers manage their energy usage, (3) remind customers how 6

to prepare for the unlikely event of a rotating outage, and (4) stress the importance of safety and health-7

related topics during a heat storm. The 2012 Summer Readiness Campaign began in April 2012 as a 8

joint effort between Customer Service and Corporate Communications. The Corporate Communications 9

effort is described in Exhibit SCE-09, Volume 1, and the O&M-funded portion of the Customer Service 10

effort is described below. 11

SCE used a phased approach to reach customers over the course of the summer 12

and leveraged multiple channels and languages to reach SCE’s diverse customers. First, to enable all 13

customers to prepare before summer started, through various communications, SCE created customer 14

awareness of programs and services that would help customers conserve energy, manage their bills, and 15

understand safe actions to take in the event of an outage or heat storm. Second, during the summer, SCE 16

communicated with customers to enable participation in available programs to reduce or shift energy 17

usage. Customers received helpful information about energy management tools available, such as 18

interval usage data on My Account, alerts, and notifications, such as Budget Assistant alerts.124 SCE 19

communicated these solutions through a variety of channels to reach our customers, including direct 20

mail, e-mail, radio, online display ads, community events, local retail in-store merchandising, and in-21

store booths. Third, SCE placed special emphasis on reaching ethnic markets, at-risk communities (e.g., 22

senior citizens and MBL customers), and customers in the South of Lugo regions in Orange County who 23

would have potentially been impacted by reliability issues related to the SONGS outage. Such targeted 24

activities included (1) developing and providing a Summer Energy Guide made available to MBL and 25

123 Dynamic pricing and Budget Assistant education and outreach costs are included in FERC Account 908.640 and are

discussed in Volume 3 of this Exhibit. PEV education and outreach costs are included in FERC Account 588 and are discussed in Exhibit SCE-09, Chapter V.

124 SCE’s Budget Assistant tool enables customers to establish a monthly spending target and receive routine updates as to how they are performing against that target to avoid future high bill “surprises.” Users can also choose update frequency, either weekly or only when their costs are expected to exceed their spending goal. The Budget Assistant tool is described in detail in Exhibit SCE-04, Volume 3.

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senior customers in Orange County and to in-language ethnic audiences across SCE’s service territory, 1

(2) conducting outreach to senior citizens through community and faith-based organizations and city 2

partners, and (3) conducting additional in-language outreach through newspapers and SCE’s website. 3

In-language outreach was provided in English, Spanish, Chinese, Korean, and Vietnamese. SCE also 4

conducted outreach to small businesses through digital methods and outreach communications supplied 5

for sponsored community events. 6

Based on research conducted post-campaign, 83 percent of residential customers 7

and 73 percent of small business customers surveyed had read or looked at SCE’s targeted summer 8

communications. Additionally, the communication message was understood by 82 percent of residential 9

customers and 77 percent of small business customers.125 10

b) Program Specific Outreach 11

In 2012, SCE provided education and outreach efforts on several programs to help 12

customers utilize energy usage information available through ESC, make informed decisions about PEV 13

charging options and beneficial PEV rates, and understand SCE’s programs and services through 14

welcome postcards and e-mails during service sign-ups and marketing materials distributed at events. 15

These activities to deliver this outreach are described below. 16

(1) Enabling Customers to Utilize Energy Usage Information 17

The implementation of the ESC program provides customers with access 18

to their usage information and tools to help them better understand and manage their electricity usage.126 19

In 2012, SCE’s outreach efforts informed customers about web tools on SCE.com’s My Account to 20

view interval usage data, bill-to-date, and projected next bill budget information tools. Additionally, 21

SCE delivered information to customers about Budget Assistant with a choice of notification options 22

such as text, e-mail, and voice.127 These tools provide customers with information regarding a 23

comparison of their projected next bill and monthly spending goal. Education and outreach activities 24

also included introductory notifications through letters, bill onserts, e-mails, web banner ads, outbound 25

125 See workpapers for a summary of the effectiveness of the 2012 Summer Readiness Campaign.

126 Ordering Paragraph 6 of D.11-07-056 requires SCE to make price, usage, and cost information available to residential customers. In compliance with D.11-07-056, SCE’s Budget Assistant program notifications provide required information, including bill-to-date and bill forecast.

127 The Budget Assistant tool is described in detail in Exhibit SCE-04, Volume 3.

185

calls, events, and the production of animated tutorials displayed on YouTube and movie cinema ads.128 1

Education and outreach encouraged customers to call SCE or go to SCE.com to sign up for budget 2

management tools and to obtain their interval usage data. Because of these efforts, over 350,000 3

customers enrolled in the Budget Assistant program by the end of 2012, and 869,000 customers enrolled 4

in our web presentment tools.129 5

(2) Informing PEV Consumers of Charging and Rate Options 6

PEV education and outreach costs are included in FERC Account 588 and 7

are discussed in Exhibit SCE-09, Chapter V. Marketing and Communications outreach efforts enabled 8

customers to make informed decisions about PEV charging options and beneficial PEV rates by 9

providing the appropriate information to both potential and current PEV owners. Targeted education 10

and outreach efforts included messaging to help educate customers about the benefits of charging their 11

vehicles during off-peak hours, both for environmental considerations and to help minimize energy 12

costs, as well as grid reliability and safety in their neighborhoods. SCE’s PEV messaging was 13

communicated through digital ads, search engine marketing, SCE’s PEV microsite, social media, printed 14

materials, business customer seminars, and outreach at community events. Supporting this outreach 15

effort included training 220 dealership sales personnel and providing dealerships with SCE-developed 16

PEV information packets. SCE also developed a dedicated online site to provide customers with helpful 17

information and tools such as a rate calculator. 18

(3) Rate Communications 19

Rate communication activities are comprised of (1) informing customers 20

about Commission-approved rate changes and other mandated information and (2) developing and 21

delivering general rate-related information. In late 2012, SCE began working to develop 22

communications to inform customers of Commission-adopted rate changes and new rate structures 23

resulting from SCE’s GRC, Phase 2 proceeding, which affects both residential and business customer 24

rate plans. SCE solicited customer feedback to improve its messaging and to help customers make 25

informed rate choices. SCE produced residential and business rate communication marketing materials, 26

128 SCE’s Carl & Eddy vignettes are available on the SCE YouTube channel in both English

(http://www.youtube.com/playlist?list=PL7911CAA2F8BFBC77) and Spanish (http://www.youtube.com/playlist?list=PL181A3A5D461ED7FE).

129 Bill-to-date, projected next bill, and usage reports are also known as SCE’s Web Presentment Tools. See Compliance Filing of Southern California Edison Pursuant to D.08-09-039 dated April 30, 2013, Attachment A, Table II.

186

including letters, e-mails, rate fact sheets, brochures, and website content to help customers better 1

educate themselves on rate options. This activity would have occurred earlier in 2012, but the 2012 2

GRC Phase 2 design final decision was not adopted by the Commission until the first quarter of 2013. 3

Throughout 2012, SCE also developed and implemented 248 versions of bill onserts and produced 11 4

regulatory bill inserts, primarily supporting Notices of Intent, Public Participation Hearings, and other 5

required customer notifications. 6

Additionally, as part of SCE’s ongoing efforts to educate customers about 7

beneficial rates, programs, and services, SCE distributed 309,797 welcome e-mails and 150,000 8

welcome postcards to residential customers and 31, 265 welcome postcards to business customers at the 9

start of service that provided an overview of SCE programs and services. These welcome 10

communications introduce new customers to information about services, such as online billing and 11

payments, tools to manage energy usage, SCE’s privacy policy, and where to find additional information 12

through SCE.com or the CCC. As part of SCE’s ongoing efforts to educate customers about rates, 13

programs, and services that can benefit customers, SCE produces and distributes communication 14

materials through various events and field personnel. 15

3. Marketing and Communications Test Year Expectations 16

In 2015, SCE will continue to engage customers on energy solutions by communicating 17

with customers to help them better manage energy usage, take advantage of programs and services, 18

adopt new technology, and use energy safely. Therefore, SCE will continue to conduct activities stated 19

in its base year that include (1) a comprehensive annual summer conservation campaign; (2) individual 20

program-specific outreach, such as dynamic pricing, Budget Assistant, PEVs, and PGC-funded 21

programs; (3) and rate communication activities, as described below.130 SCE will improve its customer 22

engagement to yield productivity savings that will enable lower-cost Marketing and Communications. 23

a) Evolving Marketing and Communications through Intelligent Delivery 24

By 2015, the energy market will have experienced many changes. Customers will 25

continue to have choices about where to get energy, how to use energy, and how to manage energy. 26

Customers will need more information, options, and technology solutions to manage energy. Customers 27

will be faced with new rate structures and new market participants in energy management. All of this 28

130 Dynamic pricing and Budget Assistant education and outreach costs are included in FERC Account 908.640 and are

discussed in Volume 3 of this Exhibit. PEV education and outreach costs are included in FERC Account 588 and are discussed in Exhibit SCE-09, Chapter V.

187

may be overwhelming for customers. Consequently, it is critical to help customers respond to these 1

changes to better manage energy usage, enroll in programs and services, adopt new technology, and use 2

energy safely. SCE will help customers connect to energy solutions through an Intelligent Delivery 3

approach (see Volume 1 of this Exhibit) that will transform traditional education and outreach practices 4

from reliance on singular, disparate communication by program toward a portfolio of bundled program 5

solutions powered by customer intelligence and delivered through both SCE and third parties. This 6

approach will be implemented as follows: 7

(1) SCE will utilize customer segmentation to better understand customer 8

preferences and ensure SCE is providing solutions that meet their needs. Segmentation will be informed 9

by data analytics on customer behavior, energy usage information that is newly available via the smart 10

meter, demographics, and attitudinal information. We will target the right customers more effectively 11

and make more efficient use of funding with improved customer targeting efforts. The build-out of the 12

Customer Data Warehouse component of the Digital Experience Program, a capital software project 13

described in Exhibit SCE-05, Volume 2, Part 1, will enhance these targeting efforts. This project will 14

provide SCE information on the products and services already adopted by the customer and will enable 15

SCE to recommend next best options for managing energy usage. 16

(2) SCE will create and offer Lifestyle Plans that include bundled offerings 17

(tailored portfolio of rates, programs, and services) that match customer interests based on past or 18

intended behaviors captured through intelligence and customer feedback. Examples of Lifestyle Plans 19

include “Cost Cutter” to maximize savings, “Quick Start” for basic services, “Green Plan” to lower 20

carbon footprint, and “In Command” for new technology. The “In Command” plan may be marketed to 21

customers who want to utilize new technology like Nest’s Programmable Controllable Thermostat. This 22

technology combined with SCE’s Budget Assistant Program and Save Power Day program (which 23

signals the thermostat to reduce energy during peak times) can help customers manage their bills. With 24

the Lifestyle Plans approach, a customer can enroll in a single package (i.e., a pre-defined bundle of 25

rates and programs) that results in multiple program enrollments. Accordingly, SCE will gain 26

efficiencies and meet customer needs by marketing several programs through one Lifestyle Plan instead 27

of multiple campaigns for different programs. 28

(3) SCE will utilize an Offer Management approach, applying customer 29

segmentation intelligence to pair the right customer with the right offer and communicating with 30

customers on an individual, ongoing basis. For example, if a customer signs up for a particular Lifestyle 31

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Plan, SCE will send that customer a subsequent message regarding another beneficial solution or tip. 1

These subsequent messages or offers will be communicated across various channels and can include 2

third parties who will market to our mutual customer. 3

Customers will benefit from this Intelligent Delivery approach because they will 4

receive customized and relevant offerings that will enable them to take advantage of rates and programs, 5

adopt new technology, and receive information on issues that interest them. Using this Intelligent 6

Delivery approach in the Test Year, Marketing and Communications is forecasting a decrease to its Test 7

Year O&M expenses by $1.207 million. Intelligent Delivery provides cost efficiencies and allows SCE 8

to perform the necessary Marketing and Communication activities at the 2012 Base Year resource 9

levels. 10

B. Digital Delivery of Customer Services Function 11

The Digital Customer Services function, Base Year operating results, and Test Year expectations 12

are described below. The impact of Digital Customer Services activities on historic and forecasted 13

O&M expenses in FERC Account 905.900 are described in Sections VIII.C and VIII.D. 14

1. Description of Digital Delivery of Customer Services 15

The Digital Customer Experience has three key functions: (1) planning and managing 16

the continual growth and evolution of SCE’s digital presence and end-to-end customer experience to 17

meet our online customers’ needs; (2) design and development of SCE’s digital channels using customer 18

feedback to develop new, or to enhance existing, features and functions, including automated tools to 19

help customers make informed decisions, enroll in programs, conduct simple self-service transactions, 20

and access their energy usage information; and (3) internet maintenance to provide daily operational 21

support of SCE.com, digital devices, and emerging technologies. SCE also recognizes that its digital 22

tools and content are accessible and WCAG 2.0 AA-compliant.131 23

In performing these functions, Digital Delivery analyses the steps necessary to produce a 24

desired result and puts them together in a sequence that easily guides a customer through a transaction. 25

An example is “Receiving a Bill on line”. These steps result in a process flow that is mapped and 26

subsequently built into the online experience and becomes the basis for the development of the digital 27

131 See D.12-11-051, Ordering Paragraph 41; see also Southern California Edison Company (U 338-E) and Disability Rights

Advocates Joint Motion for Approval of Settlement (August 22, 2011), Attachment A, pp. 18-19.

189

tools used by our on line customers. The content that is designed and prepared to be accessed by these 1

tools, and the tools themselves, makes up the work that Digital Delivery maintains on the internet. 2

2. Digital Delivery of Customer Services Base Year Operating Results 3

As a continuation of the self-service approach introduced in the 2012 GRC and as a 4

critical part of our customer engagement approach, the Digital Customer Experience functions are 5

focused on delivering capabilities for our growing base of online customers who engage with SCE via 6

digital channels. As our online customers continue to increase in number and sophistication, SCE must 7

continue to transform its Digital Delivery Channel to meet the needs of our customers. 8

SCE has been modernizing its digital channels and the end-to-end customer experience in 9

order to meet the progressing base level of service for our online customers. Table VIII-66 shows 10

customer adoption statistics for the use of SCE’s digital channel and capabilities that are available 11

today.132 12

Table VIII-66 Key SCE Online Usage Trends in 2008-2012

Line No.

Metrics 2008 2009 2010 2011 2012

1 SCE.com Visits N/A N/A N/A 20,910,242 26,492,752 2 Smart Connect Energy Usage Visits N/A N/A N/A 926,228 4,195,711 3 Service Request 107,259 147,927 157,513 152,909 189,754 4 Online Billing Enrollments 230,203 204,666 199,387 195,288 270,627 5 Bills Delivered 5,347,992 6,445,536 7,961,329 9,474,140 10,565,658 6 Payments Transactions 4,053,956 5,219,290 6,467,201 7,330,999 7,877,682 7 Outage Center Pageviews* 98,110 102,493 195,465 703,225 558,258 8 Mobile App Downloads (7/12 Launch) N/A N/A N/A N/A 29,008 9 Report an Outage N/A N/A N/A 993 37,982

10 Password Reset 14,039 221,258 129,930 304,784 352,638 11 Username Retreival 19,791 465,449 594,708 1,520,421 1,973,808

* Outage Center Pageviews in 2011 are higher than in 2012 due to the November - December 2011 windstorm.

This Table VIII-66 indicates there is a rising dependency on electronic means for 13

communicating and transacting business with SCE. We continue to see growth in online customers 14

using self-service tools, such as Report an Outage, Electronic Billing and Payments, and SmartConnect 15

Energy Usage. Overall, the growth in customer visits to SCE.com has increased from nearly 20 million 16

132 For certain categories, data from 2008-2010 is available but due to an upgrade in web analytics software approved in

SCE’s 2012 GRC, the 2008-2010 statistics are not comparable to the 2011-2012 statistics presented in Table VIII-66.

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in 2011 to over 26 million in 2012, nearly a 27 percent increase. Moreover, the number of electronic 1

payments since 2008 has increased by a staggering 50 percent, while mail-in payments have decreased 2

by 30 percent.133 3

As described in Volume 1 of this Exhibit, SCE’s customer service delivery model 4

continues to advance with our customers’ needs and expectations. This is largely driven by the 5

availability of information and research tools about energy usage, new energy management programs 6

and services, and new rates for our customers. Customers in our industry are showing an escalating 7

preference for electronic interaction with their energy providers for information about new programs, 8

services, and basic business transactions.134 Table VIII-67 below shows, for nearly all categories of 9

business transactions with the utility, the method of interaction with the highest customer preference is 10

web-enabled channels.135 The one outlier is “Resolving Issues,” for which the “Over the Phone” 11

channel is the preferred method of contact. 12

133 See Exhibit SCE-04, Volume 2, Chapter IV p. 101, Table IV-41.

134 Accenture, Actionable Insights for the New Energy Customer - Accenture end-consumer observatory 2012, pp. 23-25, (2012), available at http://www.accenture.com/SiteCollectionDocuments/PDF/Accenture-Actionable-Insights-New-Energy-Consumer.PDF.

135 Id., p. 24. Figures cited for the line “Switch to a new electricity provider” are for de-regulated markets only.

191

Table VIII-67 Customer’s Preferred Method of Interaction with Electricity Provider

Line No.

MetricWeb-

enabled Channels

Paper Mail SMS/TextOnline Chat

Over the Phone

In Person (e.g. @

home or in store)

1 Receive Bill 71% 27% 2% - - -

2 Pay Bill 69% 15% - - 9% 7%

3Learn about new home energy services

52% 18% 1% 2% 10% 17%

4Learn about new energy packages

51% 18% 1% 2% 11% 17%

5 Get outage Information 54% - 13% - 33% -

6 Change your address/move 57% 10% - 4% 22% 7%

7Switch to a new electricity provider

50% 11% - 3% 21% 15%

8Sign-up for new electricity packages and services

45% 13% 1% 3% 17% 21%

9Resolve issues (e.g., billing issues)

40% - - 6% 44% 10%

Modernizing and upgrading SCE.com as a primary channel for customer self-service is a 1

major step in the evolution of our digital channels to prepare for this growing trend. In support of these 2

initiatives, Digital Delivery worked closely with Marketing and Communications and operating units to 3

define, plan, test and implement content, programs, services and new digital features required to support 4

this evolving channel. 5

In 2012, several key initiatives were implemented as described below. For each of these 6

new initiatives, Digital Delivery defined the process flows, determined the customer interactions, 7

incorporated feedback, and measured results to deliver an online experience for customers that is simple 8

and consistent. A critical goal of the Digital Delivery function is to develop an online experience that is 9

easy and convenient to use. 10

Work for each initiative implemented was completed and subsequently monitored for 11

customer usage and adoption. Through the use of the web data analytics system, website usage patterns 12

are analyzed to determine if program enrollment processes or content pages could be improved to drive 13

transaction growth by revising the design of the website. This is an ongoing effort to keep pace with 14

changing customer expectations and program changes that occur over time. 15

192

The Digital Delivery key initiatives implemented in 2012 to meet continual program 1

growth are as follows: 2

a) Improved content and information on SCE.com 3

Significantly upgraded content and information to improve legibility, ease of 4

use, and navigation, so customers can explore, evaluate, and enroll in 5

beneficial programs and services that will provide insight on how to best 6

manage their energy usage. Digital Delivery analyzed, planned, authored, 7

tested, and produced a completely new content framework in support of this 8

initiative. 9

b) Improved access for non-English speaking, low-income, and special needs 10

customers 11

Delivered 80 percent of content pages in four languages Chinese (Mandarin), 12

Vietnamese, Spanish, and Korean to support our diverse customer base. 13

Digital Delivery analyzed and determined which pages should be translated 14

for our audience, managed the translation process so that our non-English-15

speaking customers can find information that is relevant to them. 16

Met DisabRA Settlement requirements to be compliant with WCAG2.0AA for 17

our special needs customers. 18

Provided mobile options for accessing self-service transactions for Billing and 19

Payment options and for Reporting Trouble Orders, including customers 20

participating in income-qualified programs as research demonstrates low 21

income customers are increasingly using mobile devices for accessing the 22

internet.136 23

c) Improved Data Security and Customer Privacy 24

As part of the new SCE.com Platform, Digital Delivery-designed process 25

flows and enrollment interactions provided testing and validations and 26

incorporated user feedback to deploy a significantly upgraded My Account 27

process with more rigorous privacy and security questions. SCE also 28

136 The Pew Research Center’s Internet & American Life Project, “Digital Differences,” April 13, 2012, available at

http://pewinternet.org/Reports/2012/Digital-differences.aspx

193

implemented a Registration Confirmation Letter that, in conjunction with the 1

upgraded registration process, supports double validation for our customers’ 2

burgeoning online security expectations. In doing so, Digital Delivery worked 3

with legal, security operations, and marketing communications to ensure the 4

process was effectively delivered to customers across a variety of devices. 5

d) Added New Functionality for Self-Service 6

Designed, tested, and launched a mobile application with Report an Outage 7

functionality, Report a Streetlight Outage functionality, and Outage Map 8

Views, which are available through Android or Apple at no cost to SCE 9

customers. 10

Designed, tested, and launched a mobile website for customers who have 11

other digital devices with Report an Outage functionality, Report a Streetlight 12

Outage functionality, Outage Map Views, and an upgraded Outage Center. 13

3. Digital Delivery of Customer Services Test Year Expectations 14

As stated in Volume 1 of this Exhibit, as technology rapidly advances and as innovative 15

practices in other service industries become commonplace, utility customers’ needs and expectations for 16

utility service through digital channels is progressing. The number of customers using online tools and 17

services to execute common utility interactions (e.g., pay bill, Turn-On service, etc.) continues to 18

increase as does the evolution of new technologies for the consumers. Therefore, to drive the 19

advancement of our digital channels, we will continue to conduct activities in our base year that include 20

(1) planning and managing growth and engagement through SCE’s digital delivery channels; (2) 21

designing, defining, and developing SCE’s digital channels to support evolving Billing, Payment, 22

Outage, and Energy Information Tools; and (3) continuing to provide daily operational support of digital 23

channels and management of WCAG 2.0 AA compliance. The continued evolution of the digital 24

channels will depend on the Digital Delivery team planning and developing the digital experience to 25

ensure successful customer engagement and adoption in the future. 26

a) Evolving Digital Channels through Intelligent Delivery 27

Customer adoption of digital channels will continue into the future. Currently, the 28

digital channel is a series of separate programs and services for which a customer must enroll 29

individually. Our online customers expect to research easily and conveniently and compare and enroll 30

in programs and services through automated processes, consistent with their experiences in other 31

194

industries (e.g. travel, retail, energy management providers). For example, as part of the Lifestyle Plan 1

approach, SCE will design and implement bundled offerings and enrollment processes through digital 2

channels (tailored portfolio of rates, programs, and services) that will meet customers’ expectations for 3

intelligent delivery. As described previously, we will help customers adopt programs, rate options, and 4

services that benefit them and make it convenient to adopt the Lifestyle Plans. To help customers 5

participate in these plans, we need to build the capability for customers to research and compare plans; 6

enroll in multiple rates, programs, and services simultaneously; and sign up for and receive alerts and 7

notifications. These automated processes and integrated solutions do not exist at SCE today. 8

b) Evolve Billing, Payment, and Energy Information Access 9

The growth in technology use by SCE customers is expected to increase over time 10

based on trends shown in Table VIII-66 above, coupled with customers’ changing preferences for 11

interactions with their utility as shown in Table VIII-67 above. Customers need to understand these 12

technologies, how technologies affect their utility service, and how to take advantage of the 13

opportunities these technologies will bring to the delivery of utility service. The capital software Digital 14

Experience Program fully described in Exhibit SCE-05, Volume 2 is critical to the success of meeting 15

our customer expectations and will provide multiple benefits. Serving SCE’s growing number of online 16

customers through their preferred channel to help them manage their energy usage will benefit our 17

customers, advance public policy, and result in operational efficiencies for SCE’s operating 18

organizations. These benefits are more fully described in the Digital Experience Capital Program.137 19

We will add new payment and billing services, such as PayPal and Doxo, to 20

support our customers’ growing usage of online transactions. SCE will partner and integrate with 21

existing and emerging third-party energy information providers, such as Nest, ADT, and Google, 22

allowing customers to pair and troubleshoot their Home Area Network (HAN) devices with Smart 23

Connect meters, allowing greater customer choice to determine which particular service or combination 24

of services best meets their needs. 25

c) Optimize, Maintain and Deliver Web Accessible and In Language Services 26

SCE will continue to analyze, revise, publish, and maintain content in multiple 27

languages to support the needs of our diverse customer population. In addition, as new services are 28

delivered, the content and tools will be analyzed, maintained, tested, and translated. SCE will continue 29

137 See Exhibit SCE-05, Volume 2, Part 1 for a description of the Digital Experience Capital Program.

195

to analyze, monitor, and maintain DisabRA Settlement requirements to be compliant with WCAG 1

2.0AA and will also continue to support our low-income customers who are also adopting mobile 2

devices at increasing rates to conduct business through digital channels. 3

d) Increased Digital Notifications to Support Self Service Transactions and 4

Engagement 5

SCE forecasts an increase of $1.941 million in non-labor O&M expenses for an 6

increase in the volume of self-service digital notifications. By 2015, SCE expects the upgrade of 7

proactive notifications and reminder services will shift to support broader access through more channels. 8

By 2015, SCE expects to send 35.1 million e-mail, text, and voice notifications, related to online billing 9

and payments, turn-on, turn-off, transfer, payment arrangements, and rate analyses; 7.3 million proactive 10

alerts and notifications; and 4.8 million automated outage communications. This increase in activity is 11

beyond the ongoing work required to accomplish the functions described in the beginning of this 12

Chapter.138 13

SCE also forecasts significant growth in Budget Assistant enrollment, which will 14

drive an increase in Budget Assistant notification costs. SCE forecasts that, during this GRC period, an 15

average of over 513,000 customers will be enrolled in Budget Assistant compared to the 350,000 16

customers enrolled as of the end of 2012.139 The forecast also includes the cost of implementing 17

periodic Budget Assistant notification enhancements. 18

C. Analysis of Historical Data (FERC Account 905.900) 19

The recorded/adjusted costs for Marketing, Education, and Communications activities are shown 20

in Table VIII-68 and were derived after analyzing recorded costs for this activity and adjusted to reflect 21

ongoing business operations. 22

138 See Section VIII.B.1 of this Volume.

139 The Budget Assistant program is described in Chapter IV of Exhibit SCE-04, Volume 3.

196

Table VIII-68 Marketing, Education and Communications

Recorded/Adjusted Expenses (2008-2012) FERC Account 905.900


Line No.

Marketing, Education and Communications

2008 2009 2010 2011 2012


As shown in Table VIII-68, labor expenses increased in 2009 by $256,000 due to an increase in 1

rate communication and e-commerce activities. Non-labor expenses increased in 2009 by $3.967 2

million due to a variety of factors, including online payment design activities, promotional campaign, 3

consumer electronics campaign, and rate communications in preparation for the 2010 rate shift for GS-1 4

customers. In 2010, labor costs declined by $241,000 due primarily to a number of unfilled vacancies. 5

Non-labor costs declined by $979,000 during this period due to a number of factors, including 6

reductions in the consumer electronics campaign, paperless billing efforts, and SCE.com system 7

enhancements. These non-labor reductions were partially offset by an increase in contingent worker 8

costs to offset the vacancies noted above and an increase in rate communication costs. In 2011, labor 9

costs increased by $575,000 due to filling vacancies that existed in 2010 and increases in strategic 10

alliance and ESC steady-state support. Non-labor costs increased by $168,000 largely due to increased 11

costs associated with the SCE.com upgrade and ESC steady-state activities. In 2012, labor costs 12

declined by $947,000 as a result of a decrease in SCE.com system enhancement support. Non-labor 13

costs declined by $231,000 in 2012 due primarily to a reduction in contract labor and contracted system 14

enhancement support activities. 15


Figure VIII-32 below shows the recorded/adjusted historical and forecast expenses for the 17

Marketing, Education and Communications function. Details regarding the forecast O&M expenses for 18

this function are described below. 19

197

Figure VIII-32 Marketing, Communications, and Digital Customer Services



As shown in Table VIII-68 above, SCE recorded $10.763 million for these activities in 2

2012. While labor costs and non-labor costs fluctuated during 2008-2012, the most recent year 3

accurately reflects expense levels associated with current activity levels. Therefore, the Last Recorded 4

Year was selected as the appropriate basis for forecasting labor and non-labor O&M expenses for this 5

FERC Account. 6


SCE’s Test Year forecast for FERC Account 905.900 includes a reduction of $1.207 8

million for operational excellence improvements in Marketing and Communications (described in detail 9

in Section VIII.A.3) and an increase of $1.941 million to support increased outbound e-mail and text 10

notifications to support increased customer demand for digital services (as described in detail in Section 11

VIII.B.3). These adjustments total $734,000 and result in a Test Year forecast of $11.497 million for 12

FERC Account 905.900. Figure VIII-33 shows the Test Year forecast for FERC Account 905.900 13

compared to the Base Year. 14

198

Figure VIII-33 Marketing, Communications, and Digital Customer Services


$10,763

$1,941 ($1,207)

$11,497

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

2012 Recorded Program Changes Operational Excellence 2015 Forecast

199

IX. 1

OPERATING UNIT MANAGEMENT AND SUPPORT 2

A. Description of Operating Unit Management and Support 3

This Chapter describes the centralized management and support activities that generally span 4

across multiple functional areas. These costs are recorded in FERC Account 901 and include the cost of 5

labor and non-labor expenses associated with support activities. Generally, the Operating Unit 6

Management and Support function includes the following activities: 7

• Finance Management and Administration 8

• Business Planning 9

• Regulatory and Tariff Program Support 10

• Training 11

These activities are described in the following sections. 12

1. Finance and Administration 13

a) Description of Finance and Administration Functions 14

Customer Service Finance and Administration is responsible for the Customer 15

Service Operating Unit’s budgets, accounting, financial performance reporting, financial planning and 16

analysis, internal controls, employee space planning, timekeeping, position maintenance, and payment 17

processing. These activities are described below. 18

(1) Planning and Performance Reporting 19

The Planning and Performance Reporting group is responsible for 20

providing budgeting, accounting, forecasting, reporting, financial planning, and analytical support to all 21

operational divisions in the Customer Service organization. This group prepares, monitors, and reports 22

budgets for Other Operating Revenue (OOR), Operations and Maintenance (O&M), and Capital 23

Expenditures of the Customer Service Operating Unit. The group works closely with the operating 24

divisions, providing staff support so that essential cost management processes are effective within the 25

operational divisions. It also monitors expense reporting on a routine basis through the corporate 26

accounting system and process accounting corrections as necessary. The group prepares detailed budget 27

variance reports, including year-end budget forecasts. 28

The Planning and Performance Reporting group works with Customer 29

Service project managers to ensure that proper accounting is established for all programs and services 30

that Customer Service provides to customers. In addition, it is also responsible for the Customer Service 31

200

Operating Unit’s project-specific financial analysis. Project analysis involves gathering and analyzing 1

cost and operational data for proposed and ongoing projects to determine cost-effectiveness. Performing 2

these activities allows Customer Service management to have consistent and accurate evaluations of the 3

financial effects of the projects and programs delivered by Customer Service. 4

(2) Regulatory Finance and Long-Term Planning 5

The Regulatory Finance and Long-Term Planning group is responsible for 6

preparing, leading and directing others across Customer Service in the preparation of financial forecasts 7

and other information as they relate to the development of testimony and workpapers for the General 8

Rate Case and FERC filings. Also, the group leads the effort in providing historical data analyses and 9

researching regulatory issues. Furthermore, the group provides support in witness preparation and data 10

request responses on behalf of Customer Service. In addition to managing regulatory matters, the group 11

leads a cross-functional team effort in the annual benchmarking on behalf of Customer Service. 12

(3) Internal Controls 13

Internal Controls is responsible for assisting Customer Service 14

management in fulfilling its responsibilities regarding the adequacy and effectiveness of the system of 15

internal controls within the organization by responding to management’s requests concerning internal 16

control issues, providing input on controls in new or changing areas; reviewing the effectiveness of 17

existing control processes within the organization, performing management testing of Sarbanes Oxley 18

controls, coordinating Customer Service’s response to Enterprise Risk Management activities, and 19

coordinating with other audit entities to minimize duplication of effort. The Internal Controls group is 20

also responsible for coordinating Customer Service’s involvement in and compliance with the corporate 21

Business Continuity and Resiliency efforts associated with ensuring the timely return to business in the 22

event of natural disaster. 23

(4) Timekeeping 24

The timekeeping organization is responsible for conducting a variety of 25

compensation-related activities for the Customer Service Operating Unit. On a bi-weekly basis, the 26

group processes Customer Service employee timesheets in coordination with the Corporate Payroll 27

department. In addition, the group coordinates the annual salary planning process; maintains employee 28

personnel records; handles daily inquiries from Customer Service; performs required maintenance for 29

employee positions, organizational changes and personnel change requests; requisition off-cycle 30

201

employee paychecks; performs payroll adjustments; coordinates the annual performance evaluation 1

process; and provides ad hoc reports concerning vacation time and absence histories. 2

(5) Payment Processing 3

The Payment Processing group is responsible for conducting a variety of 4

activities to support the Customer Service Operating Unit. The group works with Corporate Accounts 5

Payable to ensure appropriate reviews and processes are followed for all external vendor invoices and to 6

provide assistance with purchase orders from management personnel requesting new equipment or 7

services. This group also completes monthly reconciliations of business travel activities and other credit 8

card transactions, processes system access requests, and administrates business-level policies regarding 9

computing tools, employee expenses and approval authorization matrices. 10

2. Business Planning 11

a) Description of the Business Planning Function 12

A function of the Business Planning group is to develop the Customer Service 13

Operating Unit’s Business Plan, which sets operational unit priorities and key areas of focus over a 14

rolling five-year period, refreshed annually. This plan sets forth Customer Service’s mission, values, 15

performance goals and objectives, and actions to be taken to achieve our Customer Service objectives. 16

It also describes the necessary coordination between Customer Service and other SCE departments. The 17

plan is used to inform Customer Service employees about the Operating Unit and corporate goals and 18

help them understand how their individual contributions help support these goals to provide high-quality 19

customer service. 20

A critical part of the business planning process is to ensure that the business plan 21

can be implemented and results can be measured. Business Planning monitors Customer Service’s 22

progress and performance on goals, objectives, and action items identified in the plan. Performance 23

updates on progress toward meeting goals are regularly provided to management and Customer Service 24

employees. 25

Business Planning also provides a variety of organizational management and 26

resource planning-related support for Customer Service. Such functions include facilitation of Customer 27

Service leadership and management meetings; internal communication of Customer Service policies, 28

goals and objectives; maintenance of organizational charts and payment approval matrices; processing 29

access orders; credit card expense reconciliation; and facilitation of management approval for employee 30

onboarding. 31

202

This group also regularly performs a variety of other specialized staff support 1

activities. Examples include providing project management and analytical support for customer service-2

wide operational excellence efforts, leading development of Customer Service staffing forecast needs, 3

and managing Customer Service participation in corporate wide planning efforts. 4

3. Customer Service Regulatory and Tariff Program Support 5

a) Description of the DSM and Customer Service Regulatory and Tariff 6

Support Function 7

The Regulatory group supporting Customer Service, is responsible for 8

maintaining and monitoring Customer Service’s compliance with regulatory and legislative mandates, 9

rules, and standards. This group is also responsible for providing regulatory support to Customer 10

Service for all CPUC or SCE-initiated regulatory efforts or proceedings. Specific activities include 11

preparing Customer Service-specific portions of regulatory filings and monitoring compliance of 12

Commission compliance commitments. Recent examples of the proceedings include Smart Grid OIR, 13

Residential Rate OIR, Distributed Generation OIR, Smart Meter Opt-Out, Smart Grid Deployment Plan, 14

and various cost recovery proceedings such as the GRC, ERRA, and ESPI Application (A.12-03-004). 15

Compliance activities of the group include Affiliate Transactions, Essential Use and Service Guarantee 16

programs. The group also coordinates the input of other Customer Service employees in the 17

Commission, California Energy Commission and legislative processes. 18

The Tariff Program Support group is responsible for the management oversight of 19

special contract or nonstandard pricing options and provides rotating outage project management 20

support. These activities address more complex rate options such as SCE’s Base Interruptible Program 21

or CPP rate options, which require involved implementation and interpretation issues. 22

4. Training 23

a) Description of the Training Function 24

As described in this Volume, employees in Customer Service Operations provide 25

the majority of customer contact for our 4.9 million customers. As the primary point of contact, our 26

employees need to provide a level of service that meets our customers’ needs and expectations. Our 27

employees need to be trained in the business operations and subject matter associated for their job 28

function and in communication and interpersonal skills so they can interact effectively with customers. 29

The Training group conducts classes and develops and updates training materials for all employees 30

working in the operational areas of Customer Service. This requires substantial training for our new hire 31

203

employees as well as ongoing training for existing employees. The group designs training modules that 1

educate employees on essential company policies, procedures, and the business operations specific to 2

their particular job. Training curriculum will vary based upon the organization or position. 3

As our business environment and processes evolve, it is necessary to continually 4

develop the skills and knowledge of our employees. In addition to the training our employees receive 5

when they are hired, they need to be trained on changes in technology applications and business 6

operations processes so they can continue to perform their jobs effectively. When a new system is 7

implemented, a current system is enhanced, or when changes are programmed into current systems to 8

reflect new regulatory requirements, work processes are modified and retraining is necessary. 9

B. Base Year Operating Results 10

1. Summary of Recorded Costs (FERC Account 901) 11

In 2012, SCE recorded a total of $10.751 million in O&M expenses for Operating Unit 12

Management and Support with recorded labor expenses of $8.535 million and non-labor expenses of 13

$2.216 million. These operating results provide a reasonable base to forecast the 2015 Test Year for this 14

FERC Account. 15

2. Analysis of Historic Data (FERC Account 901) 16

The recorded/adjusted costs shown in Table IX-69 below were derived after analyzing 17

recorded costs for this activity and adjusting them to reflect ongoing business operations. The various 18

accounting, operational, and reclassification adjustments are discussed in the workpapers for this 19

Volume. The ratemaking adjustments are discussed further in Exhibit SCE-10, Results of Operations 20

testimony. 21

204

Table IX-69 Operating Unit Management and Support Recorded / Adjusted Expenses (2008-2012)

FERC Account 901 (Constant 2012 $000)

Line No.

Operating Unit Management and Support

2008 2009 2010 2011 2012


Recorded operating expenses for the Operating Unit Management and Support function 1

have fluctuated over the historical period. In 2009, labor expenses declined by $1.460 million primarily 2

due to a reduction in training following the implementation of SAP and a shift in finance and 3

administrative workload to non-O&M funded activities. In 2010, labor costs decreased an additional 4

$139,000 primarily due to vacancies in the training organization. In 2011, labor costs in FERC Account 5

901 increased by $472,000 due to increased staffing to support Customer Service Operations planning 6

and the backfilling of vacancies in finance and administration. In 2012, labor expenses increased by 7

$566,000 due primarily to an increase in tariff support activities and process improvement initiatives 8

associated with Customer Service’s storm response practices. 9

Non-labor expenses were relatively stable from 2008 to 2009. In 2010, non-labor 10

expenses increased $1.164 million due to a combination of factors, including an increase in contractor 11

expenses to support various regulatory activities (including SCE’s 2012 GRC), Customer Service 12

Operations planning activities, and vacancies in the Job Skills Training group. In 2011, non-labor 13

expenses increased by $589,000 primarily due to increased training, employee development activities 14

and consultants within the Job Skills Training organization. In 2012, non-labor expenses declined by 15

$2.474 million due to a number of factors, including a reduction in employee-related expenses such as 16

training, employee development, and a reduction in contractor expenses supporting various regulatory 17

activities. 18

C. Test Year Expectations (FERC Account 901) 19

Figure IX-34 below shows the recorded/adjusted historical and forecast expenses for the 20

Operating Unit Management and support function (FERC Account 901). Details regarding the forecast 21

205

O&M expenses for this function are described below. Figure IX-35 below shows the Test Year forecast 1

for FERC Account 901 compared to the Base Year. 2

Figure IX-34 Operating Unit Management and Support

FERC Account 901

1. Determination of Test Year Estimating Methodology 3

The 2012 Base Year activities for the Operating Unit Management and Support functions 4

are described above. In 2012, SCE recorded $10.751 million for these activities and the 5

recorded/adjusted history for this functional group is shown in Table IX-69 above. Although expenses 6

for these activities have fluctuated over the five-year historical period, the Last Recorded Year was 7

selected as the base for our 2015 Test Year forecast. The most recent year accurately reflects expense 8

levels associated with current activity levels. We have added increments or decrements to that base as 9

discussed below in our testimony and in workpapers. 10


The Test Year forecast for FERC Account 901 is shown above in Figure IX-34 and 12

includes adjustment resulting in a net reduction of $2.673 million, including an increase of $222,000 to 13

reflect the impact of customer growth and a reduction of $2.896 million associated operational 14

excellence improvements. These adjustments are described in more detail below. 15

206

a) Customer Growth 1

The number of customers served in SCE’s service territory is expected to increase 2

by a compounded rate of 2.06 percent from 2012 to 2015. Activities in OUMS are a direct result of 3

increases in activities with the client organizations, which, in turn, are impacted by customer growth. To 4

reflect the cost impact that customer growth will have on OUMS activities, an adjustment of 2.06 5

percent was applied to the labor and non-labor components of the 2012 Base Year adjusted/recorded 6

costs resulting in an adjustment of $222,000. 7

b) Operational Excellence 8

The Test Year forecast for FERC Account 901 includes a reduction of $2.896 9

million associated with operational excellence improvements SCE expects to achieve as a result of 10

consolidating and implementing process improvements in the finance and job skills training functions. 11

Figure IX-35 Operating Unit Management and Support



$10,751 $222 ($2,896)

$8,078

$0

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

2012 Recorded Customer Growth Operational Excellence 2015 Forecast

207

X. 1

OTHER OPERATING REVENUES (OOR) 2

A. Introduction 3

Customer Service Operations Division (CSOD) is responsible for assessing the fees to charge 4

individual customers and third parties who receive services that cause SCE to incur additional 5

operational expenses. These services are cost causation activities and above the standard operational 6

services provided by SCE. As such, SCE cannot fund these activities through general rates and must 7

charge for these services. The revenue received for these services is accounted for as OOR. These 8

services include service connection charges (fees) for establishment of service and reconnecting service 9

following disconnection for nonpayment of bills, returned check charge to offset costs associated with 10

the processing of checks that are returned from the bank due to insufficient funds, other services 11

associated with Direct Access (DA) and Community Choice Aggregation (CCA), and other special 12

services. In this GRC, as directed in D.12-04-018, SCE is providing for an ESC “Opt-Out” option and 13

has established fees for this option. 14

Revenue derived from these activities is recorded as OOR associated with FERC Account 450 15

and a portion of the OOR in FERC Accounts 451 and 456. In this Chapter, we define the functional 16

subaccounts associated with the FERC Revenue Accounts and describe the analyses and estimating 17

methods used to forecast our 2015 Test Year OOR. 18

The combined total of these revenues is estimated to be $32.8 million in Test Year 2015 based 19

on our proposed service fees, compared to $31.2 million per year based on currently authorized fees. 20

The proposed increase in OOR is primarily the result of an increase in the Opt-Out Program Fees to 21

reflect fully compensatory rates. Minor changes in some OOR categories result from updated cost 22

studies and an adjustment in some of the current fees to better reflect the costs incurred by SCE to 23

provide these services. Table X-70 presents the annual recorded OOR from 2008-2012 and forecast 24

from 2013-2015 based on current fees, and the 2015 proposed fees. 25

208

Table X-70 Other Operating Revenue – Customer Service Operations

Recorded 2008 – 2012 and Forecast 2013 – 2015 (Nominal $000s)

Proposed

Line No.

FERC Account Account Name 2008 2009 2010 2011 2012 2013 2014 2015 2015

1 450.100 Late Payment Charge - Non-Residential $6,759 $6,512 $6,707 $6,173 $6,262 $5,701 $5,612 $5,653 $5,6532 450.150 Late Payment Charge - Residential $10,404 $10,107 $10,486 $10,079 $10,849 $9,355 $9,365 $9,501 $9,5013 450.200 Collection Agency Interest $11 $8 $0 $0 $0 Eliminated Eliminated Eliminated Eliminated

4 Subtotal 450 $17,174 $16,627 $17,193 $16,252 $17,111 $15,056 $14,977 $15,154 $15,1545 451.110 Returned Check Charge $1,764 $1,550 $1,355 $1,442 $1,623 $1,424 $1,433 $1,446 $1,2656 451.200 Reconnection Charge $6,718 $7,065 $6,230 $6,133 $4,862 Eliminated Eliminated Eliminated Eliminated

7 451.250 Service Establishment Charge $16,607 $17,748 $16,672 $15,838 $15,794 Eliminated Eliminated Eliminated Eliminated

8 451.300 Connection Charge - Residential $0 $0 $0 $0 $0 $7,112 $7,159 $7,222 $6,0199 451.310 Connection Charge - Non-Residential $0 $0 $0 $0 $0 $4,029 $4,055 $4,091 $2,623

10 451.320 Connection Charge - at Pole $0 $0 $0 $0 $0 $13 $13 $13 $2211 451.600 Field Assignment Charge $6,688 $8,051 $7,042 $6,882 $3,154 Eliminated Eliminated Eliminated Eliminated

12 451.780 Misc. Revenue - Recovery Unauthorized Use Non-Energy $404 $378 $367 $246 $205 $205 $205 $205 $20513 451.820 Opt Out CARE-Initial $0 $0 $0 $0 $50 $9 $9 $9 $5114 451.820 Opt Out NON-CARE-Initial $0 $0 $0 $0 $1,114 $203 $203 $203 $19215 451.820 Opt Out CARE-Monthly $0 $0 $0 $0 $101 $350 $368 $368 $1,43316 451.820 Opt Out NON-CARE-Monthly $0 $0 $0 $0 $662 $2,097 $2,205 $2,205 $5,56417 Subtotal 451.820 $0 $0 $0 $0 $1,927 $2,659 $2,785 $2,785 $7,24018 Subtotal 451 $32,181 $34,792 $31,666 $30,541 $27,565 $15,441 $15,650 $15,762 $17,37219 454.100 Meter Leasing $6 $6 $6 $0 $0 Eliminated Eliminated Eliminated Eliminated

20 Subtotal 454 $6 $6 $6 $0 $0 Eliminated Eliminated Eliminated Eliminated

21 456.401 Direct Access Services $674 $396 $501 $492 $484 $277 $277 $277 $27722 456.402 DirectAccessCustomerCharge $0 $0 $0 $0 $0 Eliminated Eliminated Eliminated Eliminated

23 456.948 Service Fee - Optimal Billing Period $0 $0 $0 $1 $0 $1 $1 $1 $124 456.412 Community Choice Aggregation $4 $1 $0 $4 $4 $4 $4 $4 $425 456.415 Manufactured Home Billing Service $1 $1 $1 $1 $2 $1 $1 $1 $126 Subtotal 456 $680 $398 $502 $498 $490 $283 $283 $283 $28327 TOTAL Customer Service Operations $50,041 $51,823 $49,367 $47,291 $45,167 $30,779 $30,910 $31,199 $32,809

Recorded Operating RevenueForecast

(Currently Authorized Fees)

B. Estimating Method for OOR 1

1. Estimating Process 2

In general, the process followed in estimating the 2015 Test Year revenues associated 3

with the OOR activities involves: 4

• identifying the processes and activities associated with each existing Subaccount; 5

• identifying the costs associated with these activities, including an update of the wage 6

rates and labor loadings; 7

• reviewing the historical record of activity levels and actual revenue collected from 8

these activities over the last five years; and 9

• determining the basis or method to be employed in estimating the transaction volumes 10

and resulting 2015 Test Year revenue forecast for each Subaccount. 11

The Table X-71 below provides the OOR Service Fee Summary showing the 2012 GRC 12

authorized fees, 2015 cost study results, and the 2015 proposed fees. Proposed fees greater than $5.00 13

are rounded up or down to the nearest dollar amount. Proposed fees greater than or equal to $1.00 but 14

less than or equal to $5.00 are rounded to the nearest ten cents. Proposed fees that are less than a dollar 15

are not rounded. 16

209

Table X-71 Other Operating Revenue Service Fee Summary

2015 Proposed Fees (Nominal $s)

2012 2015

FERC Account NameGRC

Cost StudyAuthorized

GRCCost Study

Proposed

1 450.100 Late Payment Charges – Non-Residential 0.80% 0.80% 0.80% 0.80%2 (% applied to account balance on accounts)3 Late Payment Charges – Residential 0.80% 0.80% 0.80% 0.80%4 (excluding CARE)5 (Proposed OOR)6 (% applied to account balance on accounts)7 451.110 Returned Check Charge $8.48 $8.00 $7.45 $7.008 451.300 Connection Charge – Residential $5.84 $6.00 $5.24 $5.009 451.310 Connection Charge – Non-Residential $39.15 $39.00 $24.77 $25.00

10 451.320 Connection Charge – at Pole $86.41 $86.00 $137.86 $138.0011 451.820 Opt-Out CARE – Res-Initial (a) $74.00 $10.00 $57.01 $57.00 12 451.820 Opt-Out CARE – Res-Monthly (a) $19.00 $5.00 $17.23 $17.00 13 451.820 Opt-Out NON – CARE-Res-Initial (a) $93.00 $75.00 $71.26 $71.00 14 451.820 Opt-Out NON – CARE-Res-Monthly (a) $24.00 $10.00 $21.54 $22.00 15 456.401 Direct Access Service Fees - See Table X-77 for 2015 Proposed Fees16 456.412 Community Choice Aggregation Service Fees - See Table X-79 for 2015 Proposed Fees

450.150

Line No.

FERC Acct.

C. Residential Service Charges 1

The Residential Late Payment Charge will remain unchanged, and Residential Service 2

Connection Charge will decrease from $6.00 to $5.00. Increases are being proposed for the Opt-Out 3

fees for the 2015 GRC. The reasons for these changes are discussed below as well as the forecast for 4

each fee. 5

1. FERC Account 450.150 – Residential Late Payment Charge (LPC) 6

This sub-account includes the forecast of revenues from the LPC for residential 7

customers who fail to pay their bill within 19 days of its receipt. In our 2003 GRC Decision, the 8

Commission authorized SCE to assess this fee to residential customers with the exception of customers 9

participating in the California Alternate Rates for Energy (CARE) program. In SCE’s 2012 GRC 10

Decision, D.12-11-051, the CPUC accepted SCE’s proposal to reduce the existing residential LPC from 11

0.9 percent per month to 0.8 percent per month.140 12

140 The current rate of 0.8 percent is still consistent with SCE’s current incremental cost of capital.

210

Figure X-36 below illustrates the annual revenue recorded from 2008 through 2012 for 1

this charge. To forecast the residential LPC revenue for the years 2013 through 2015, SCE used a three-2

rolling average plus customer growth of 2.06 percent from 2012 to 2015. This produced a forecast of 3

$9.5 million for Test Year 2015. In the 2012 GRC, SCE used a five-year rolling average that did not 4

produce accurate forecasts for the Test Year. By analyzing prior year recorded data and using different 5

forecast methods, the three-year rolling average plus customer growth produced the most accurate 6

estimate. The calculation is provided in the workpapers supporting this forecast. 7

Figure X-36 FERC Account 450.150

Residential Late Payment Charge Revenue Forecast (Nominal $000s)

Note – Recorded amounts 2008-2012 at 0.9 percent LPC and forecast at 0.8 percent LPC

2. FERC Account 451.300 – Residential Service Connection Charge 8

This sub-account is used to record revenues received from residential customers for all 9

service connections (i.e., new service establishment, transfer of existing service, or reconnection after 10

being disconnected for non-payment of a bill). Figure X-37 provides the forecast for 2013 – 2015 of the 11

Residential Service Connection Charge. This forecast is based on the three-year average volume of 12

211

service connections plus customer growth from 2012 to 2015 of 2.06 percent. Since this charge was 1

initiated in the 2012 GRC and not operational until 2013, there are no historical fees for this charge. 2

The Residential Service Connection Charge, which will mostly be activated remotely, is 3

based on a 95 percent utilization of the Remote Service Switch (RSS) function of the ESC meter, while 4

the remaining five percent is based on performing this task manually through a field visit. With the 5

exception of the ESC Opt-Out customers, the functionality of the RSS is dependent on technical 6

metering and communication issues. The cost per connection is derived as a weighted average of the 7

RSS and manual connection costs. 8


Residential Service Connection Charge Revenue Forecast (Nominal $000s)

A cost study was conducted to update activity duration, transactional costs, and loaded 9

labor rates. The weighted average of RSS connections and manual connections was based on 2012 10

experience. The cost study shown in Table X-72 below shows the Residential Service Connection 11

Charge of $5.24 that is rounded to $5.00 and will decrease $1.00 from the current charge. 12

212

Table X-72 FERC Account 451.300

Residential Service Connection Charge Cost Study (Nominal $s)

Line Position Activity Details Min. Per Cost PerManual/Field

VisitRemote Service Switch (RSS)

No. Trans. Minute%

Cost Per Trans. %

Cost Per Trans.

1 MSO-Field Orders2 FSR2A Set Priority Routing work 2.00 $1.32 100% $2.64 0% $0.003 FSR2A Summarize Input read into laptop 1.50 $1.32 100% $1.98 0% $0.004 FSR2A Regular Time 11.50 $1.32 70% $10.64 0% $0.005 FSR2A_OT Time and one half 22.50 $1.22 20% $5.51 0% $0.006 FSR2A_DT Double Time 120.00 $1.62 10% $19.39 0% $0.007 SFSR7871 Operator Download & Upload Orders using

Field Service Order System0.25 $1.52 100% $0.38 0% $0.00

8 CSR_A CCC-Dispatch 0.10 $0.91 100% $0.09 0% $0.009 CCC-Handle Calls10 SCE Rep $2.64 $2.6411 Third party vendor $0.10 $0.1012 Payment Processing13 n/a APA n/a $0.48 96% $0.48 96% $0.4814 CUS_A Rural Office 4.10 $0.65 4% $0.11 4% $0.1115 Total Cost Per Transaction (Unweighted) $43.96 $3.33161718 2015 Residential Connections Volume Forecast Manual/Field RSS Total19 2015 Residential Connections Volume Forecast 56,588 1,147,117 1,203,70520 % Manual and RSS Volume Split 4.7% 95.3% 100.0%212223 2015 Residential (Res) Connection Fee Calculation Manual/Field RSS Total24 Cost Per Transaction (Unweighted) $43.96 $3.3325 % Manual and RSS Volume Split 4.7% 95.3%26 Total Res Connection Fee Per Transaction (Weighted) $2.07 $3.17 $5.2427 2015 Proposed Fee (Rounded) $5.00

Energize Meter (field visit)

3. FERC Account 451.820 – Opt-Out Program Fee 1

On April 30, 2012, the CPUC issued D.12-04-018, requiring SCE to modify its ESC 2

program to provide for an opt-out option and established interim fees for this option. D.12-04-018 also 3

ordered a second phase (Phase 2) of the proceeding to further consider program costs, fees, and cost 4

allocation. At the time of filing this application, the Commission has not issued a decision on SCE’s 5

proposed Opt-Out Program fees to collect when customers elect to opt out of the ESC meter. 6

D.12-04-018, created four new interim fee types: Opt-Out Initial – CARE, Opt-Out Initial 7

– Non-CARE, Opt-Out Monthly – CARE, and Opt-Out Monthly – Non-CARE. The initial fee is 8

213

assessed when a customer elects to opt out of the ESC meter program and instead take service using a 1

legacy (electromechanical) meter.141 A non-California Alternate Rate for Energy (Non-CARE) 2

customer electing the opt-out option is assessed the initial proposed fee of $71.00 and a monthly 3

proposed fee of $22.00. A CARE customer electing the opt-out option will receive a 20 percent 4

discount on the Non-CARE fees resulting in an initial proposed fee of $57.00 and a monthly proposed 5

fee of $17.00. 6

SCE developed its forecast revenues based on the current number of customers enrolled 7

in the Opt-Out Program with an increase of 3,600 new participants into the program per year. This is 8

based on the average number of enrollments and disenrollments in a given year. The service fee was 9

determined based on updated cost studies submitted in SCE’s Smart Meter Opt-Out Cost Estimates and 10

Cost Recovery Proposal.142 As the decision regarding the Opt-Out Program fees is currently outstanding 11

as of filing this 2015 GRC application, SCE has updated the cost studies included in the above 12

mentioned testimony. The cost study was updated with 2012 loaded wage rates, and any fees associated 13

with program implementation were removed. These proposed fees represent fully compensatory and 14

should be utilized going forward in 2015. Table X-73 below shows a comparison of the Opt-Out 15

Program fees proposed in the 2012 testimony, the 2012 interim fees, and the 2015 GRC proposed fees 16

and the variance between them. 17

Table X-73 FERC Account 451-820

Opt-Out Program Fee Comparison (Nominal $s)

Line No.

FERC Account Account Name

2012 Filing Proposed

Fees

2012 Interim

Fees

2015 GRC Proposed

Fees

2012 Interim vs. 2015 GRC

Proposed Variances

1 451.820 Opt-Out CARE – Initial $ 74 $ 10 $ 57 $ 47 2 451.820 Opt-Out CARE – Monthly $ 19 $ 5 $ 17 $ 12 3 451.820 Opt-Out NON-CARE – Initial $ 93 $ 75 $ 71 $ (4)4 451.820 Opt-Out NON-CARE – Monthly $ 24 $ 10 $ 22 $ 12

141 D.12-04-018 established interim fees consisting of $75 initial/$10 monthly for Non-CARE customers, and $10 initial/$5

monthly for CARE customers.

142 See SCE Errata to Southern California Edison Company Smart Meter Opt-Out Cost Estimates and Cost Recovery Proposal, November 2, 2012.

214

D. Non-Residential Service Charges 1

To determine the service charges for non-residential accounts, updated cost studies were 2

developed. The Non-Residential Late Payment Charge is proposed to remain the same, while the Non-3

Residential Service Connection Charge will be decreasing. This decrease is due to SCE’s utilization of 4

the RSS on eligible Commercial customers for turn-on, turn-off, and service reconnections. Field 5

services personnel will still make a field visit prior to disconnection. 6

1. FERC Account 450.100 – Non-Residential Late Payment Charge 7

Subaccount 450.100 represents revenues collected from Late Payment Charges (LPC) 8

from non-residential customers who do not pay their bill within 19 days of receipt. A charge of 0.9 9

percent per month was originally implemented in March 1992, as authorized by the Commission in 10

Resolution E-3286. In SCE’s 2012 GRC Decision, D.12-11-051, SCE proposed reducing the existing 11

non-residential LPC to 0.8 percent per month. This rate, adopted in D.12-11-051, is consistent with 12

SCE’s current incremental cost of capital. 13

Figure X-38 below presents the annual revenue recorded from 2008 through 2012 for this 14

charge. To forecast the non-residential LPC revenue for the years 2013 through 2015, SCE used a three-15

year rolling average plus customer growth. This produced a forecast of $5.7 million for 2015 Test Year 16

forecast. The calculation is provided in the workpapers supporting this forecast. 17

215


Non-Residential Late Payment Charge (Nominal $000s)

2. FERC Account 451.310 – Non-Residential Service Connection Charge 1

RSS functionality is only available in 200 amp meters, which generally serve only 2

residential and small non-residential (GS-1) accounts under 20 kW. SCE has determined the ESC RSS 3

is safe to Turn-On and Turn-Off non-residential customers. For collection activities, an FSR will make 4

a field visit to the customer’s location to ensure it is safe to use the RSS to disconnect the customer. 5

This will allow the use of the RSS to reconnect the customer after the account is made current or 6

establishment of a payment arrangement has been made. Customers will be made aware that their 7

electricity will automatically be restored once their account is brought current. Sub-account 451.310 is 8

used to record charges incurred for all non-residential service connections, either resulting from new 9

service establishment, transfer of existing service or from reconnection of services previously 10

disconnected for non-payment of a bill. Because this fee was initiated in the 2012 GRC and not 11

operational until 2013, there is no recorded history for this fee prior to 2013. Figure X-39 below shows 12

the forecast of the Non-Residential Service Connection Charge based on the authorized rate from the 13

2012 GRC and the Test Year 2015 proposed rate. The volume of service connections was based on a 14

three-year average of non-residential volume plus customer growth. 15

216


Non-Residential Service Connection Charge (Nominal $000)

The proposed fees are based on a revised cost study to determine the cost per transaction 1

for all non-residential service connections. As discussed earlier, the ESC RSS will now be used for non-2

residential customers because safety concerns have been eliminated. The summary of this cost study is 3

shown below in Table X-74. 4

217


Non-Residential Service Connection Charge Cost Study (Nominal $s)

Line Position Activity Details Min. Per Cost PerManual/Field

VisitRemote Service Switch (RSS)

No. Trans. Minute%

Cost Per Trans. %

Cost Per Trans.

1 MSO-Field Orders2 FSR2A Set Priority Routing work 2.00 $1.32 100% $2.64 0% $0.003 FSR2A Summarize Input read into laptop 1.50 $1.32 100% $1.98 0% $0.004 FSR2A Regular Time 11.50 $1.32 70% $10.64 0% $0.005 FSR2A_OT Time and one half 22.50 $1.22 20% $5.51 0% $0.006 FSR2A_DT Double Time 120.00 $1.62 10% $19.39 0% $0.007 SFSR7871 Operator Download & Upload Orders using

Field Service Order System0.25 $1.52 100% $0.38 0% $0.00

8 CSR_A CCC-Dispatch 0.10 $0.91 100% $0.09 100% $0.099 CCC-Handle Calls10 SCE Rep $2.64 $2.6411 Third party vendor $0.10 $0.1012 Payment Processing13 n/a APA n/a $0.48 96% $0.4814 CUS2 Rural Office 4.10 $0.72 4% $0.12 4% $0.1215 Total Cost Per Transaction (Unweighted) $43.97 $2.95161718 2015 Non-Residential Connections Volume Forecast Manual/Field RSS Total19 2015 Non-Residential Connections Volume Forecast 55,812 49,094 104,90620 % Manual and RSS Volume Split 53.2% 46.8% 100.0%212223 2015 Non-Residential (Non-Res) Connection Fee Calculation Manual/Field RSS Total24 Cost Per Transaction (Unweighted) $43.97 $2.9525 % Manual and RSS Volume Split 53.2% 46.8%26 Total Non-Res Connection Fee Per Transaction (Weighted) $23.39 $1.38 $24.7727 2015 Proposed Fee (Rounded) $25.00

Energize Meter (field visit)

E. Other Service Charges 1

1. FERC Account 451.110 – Returned Check Charge 2

This sub-account includes the charge to customers for checks returned to SCE by the 3

bank for insufficient funds. The charge to the customer was authorized at $8.00 per returned check in 4

our 2012 GRC. SCE is proposing to reduce this charge to $7.00. The decrease is due to certain tasks 5

not taking as long to perform because of productivity. The volume forecast used a five-year average 6

recorded volume plus customer growth shown in Figure X-40 below. 7

218


Returned Check Charge Revenue (Nominal $000s)

The cost study analysis examines each function performed at its applicable loaded-labor 1

rate and then multiplies this rate by the estimated time required to complete the activities associated with 2

processing a returned check. The result was an average cost of $7.45 for each returned check comprised 3

of labor cost of $4.66 and non-labor cost of $2.79 for bank fees and Authorized Payment Agencies 4

(APA) charges. Table X-75 presents a summary of this cost study for the Returned Check Charge. The 5

volume of returned checks is based on a five-year average plus customer growth. 6

219

Table X-75 FERC 451.110

Cost Study-Returned Check Charge (Nominal $s)

LineNo. CIP Description Occurrence

Average Minutes Per Transaction

Cost Per

MinuteCost Per

Transaction

1 Average Bank Charges $2.3323 CSR3_R Credit Administration (Research and check for

payment process for collection)3.6% 7.0 $1.22 $0.30

45 In Person Payments6 APA (Receive and process payments) 96.0% $0.48 $0.467 CUS2 Rural Office (Receive and process payments) 4.0% 2.1 $0.72 $0.0689 ACA3_R Accounts Receivable (Research and post debit to the 0.5 $0.95 $0.44

1011 CSR_A Customer Contact Center (Customer Service

specialist inquiries and extensions)4.2 $0.91 $3.85

12Return Check Total Cost 13.8 $0.54 $7.45

2015 Proposed Fee (Rounded) $7.00

2. FERC Account 451.320 – At-Pole Service Connection Charge 1

At-pole service connections generally occur when normal access to the meter is not 2

available due to locked gates, indoor meters, or aggressive dogs. The frequency has decreased due to 3

the use of ESC RSS for residential accounts. Sub-account 451.200 historically recorded charges for 4

both residential and non-residential customers for the At-Pole Connection of electric service. Due to the 5

high cost of providing this extraordinary service and because it generally results from customers’ failure 6

to meet the access provisions of SCE’s service agreement, this type of charge is needed. The cost study 7

supporting the proposed rate of $138.00 for At-Pole Service Connection is shown below in Table X-76. 8

220


At-Pole Service Connection Charge Cost Study (Nominal $s)

Line Position Activity Details Min. Per Cost Per Manual/Field VisitNo. Trans. Minute

%Cost Per Trans.

1 Field Visit2 Non-Labor (Vehicle) Included in wage rate n/a n/a 100% $0.003 TM9501A Energize Meter (field visit) Regular Time 60.00 $2.00 100% $119.99

4 Dispatch

5 CUS_A Dispatch DOC Center: (Radio dispatch connection order)

1.58 $0.65 100% $1.03

6 CUS2 Issue Order 0.10 $0.72 100% $0.077 CSR_A Issue Order 4.23 $0.91 100% $3.858 CSR3_R Issue Order & Review 8 $1.22 100% $9.779 CCC-Handle Calls10 SCE Rep $2.6411 Payment Processing12 APA n/a $0.48 96% $0.4613 CUS_A Rural Office 2.07 $0.65 4% $0.05

14 Total At Pole Connection Fee Per Transaction $137.86

15 2015 Proposed Fee (Rounded) $138.00

The forecast At-Pole Service Connection Revenue for Test Year 2015 was calculated 1

based upon the service crew completing the service connection, including average drive time between 2

calls multiplied by the forecast volume of 156 at-pole connections in 2015. Figure X-41 below shows 3

the forecast At-Pole Service Connection charge of $22,000 for 2015 Test Year. 4

221


At-Pole Service Connection Charge (Nominal $000s)

F. Direct Access (DA) and Community Choice Aggregation (CCA) Fees 1

1. FERC Account 456.401 – Direct Access Service Fees 2

This Subaccount records the revenues we forecast in the Test Year for services pursuant 3

to the DA discretionary and non-discretionary service fees. These service fees were approved in D.08-4

05-003 and have been revised to reflect changes in process flows for providing the service as well as 5

labor costs and non-labor costs, such as postage and banking fees. 6

The forecast for OOR reflects the change in DA transaction volume due to the expected 7

decrease in customer-requested services, such as meter reads and meter maintenance and repair. With 8

the deployment of the ESC meter technology, customers are provided daily access to interval data at no 9

incremental cost. In the 2012 GRC, SCE requested to eliminate all meter reading fees for DA customers 10

(and for CCA, as discussed in the following section). This was approved in D.12-11-051. Universal 11

interval metering is expected to reduce the need for customer-owned meters and associated meter 12

maintenance and repairs. 13

The current and proposed 2015 DA Service Fees are shown in Table X-77 below. 14

222

Table X-77 DA Service Fees

(Nominal $s) Fee No. Fee Description

Current Fees

Proposed Fees

1 UDC Consolidated Billing, Bill by Mail 0.20$ 0.58$ 2 UDC Consolidated Billing, Bill by Internet 0.18$ 0.11$ 3 EDI VAN Charge 0.28$ 0.16$ 4 UDC Consolidated Billing, Additional Page Charge 0.21$ 0.08$ 5 Meter Data Posting 0.27$ 0.18$ 6 Miscellaneous Customer Notification 0.46$ 0.46$ 7 Special Services Request Fee T&M T&M8 Daily Check for Payment Charge 73.80$ 73.80$ 9 Electronic Data Interchange (EDI) Bank Processing 2.25$ 2.25$ 10 Electronic Data Interchange (EDI) Value Added Network (VAN) 2.75$ 2.75$ 11 Value Added Network (VAN) Transmission of Data 0.15$ 0.15$ 12 Hourly Rate to Assist ESPs with Rates and Systems 106.00$ 106.00$ 13 Billing Set-up and Ongoing Support T&M T&M14 Retrieval of Account Information Charge 6.25$ 6.25$ 15 Routine Account Analysis Charge 12.50$ 12.50$ 16 Complex Account Analysis Charge 56.30$ 56.30$ 17 Resend File/Report Charge 18.80$ 18.80$ 18 Investigate EDI Payment Charge 106.00$ 106.00$ 19 Refund account credits due to overpayment EDI charge 6.25$ 6.25$ 20 Involuntary Billing Change Charge 10.00$ 10.00$ 21 Acceptance Testing of Customer-owned Meter 47.10$ 53.00$ 22 Advanced I 291.00$ 178.00$ 23 Advanced I Maintenance Fee 2.56$ 1.40$ 24 Advanced I Maintenance Fee for Non-Billing Meter 3.65$ 1.40$ 25 Advanced I Modem Equipped Maintenance Fee 2.99$ 2.80$ 26 Advanced I Modem Equipped Maintenance Fee for Non-Billing Meter 4.08$ 2.80$ 27 Advanced I Pulse and Modem Equipped Maintenance Fee 3.01$ 2.80$ 28 Advanced I Pulse and Modem Equipped Maintenance Fee for Non-Billing Meter 4.10$ 2.80$ 29 Advanced I Pulse Equipped Maintenance Fee 2.73$ 1.90$ 30 Advanced I Pulse Equipped Maintenance Fee for Non-Billing Meter 3.82$ 1.90$ 31 Advanced I+M 449.00$ 437.00$ 32 Advanced I+P 353.00$ 286.00$ 33 Advanced I+P&M 491.00$ 437.00$ 34 Basic I 209.00$ 149.00$ 35 Basic I Maintenance Fee 2.34$ 1.20$ 36 Basic I Maintenance Fee for Non-Billing Meter 3.43$ 1.20$ 37 Basic I Modem Equipped Maintenance Fee 2.73$ 2.30$ 38 Basic I Modem Equipped Maintenance Fee for Non-Billing Meter 3.82$ 2.30$ 39 Basic I Pulse and Modem Equipped Maintenance Fee 2.85$ 2.60$ 40 Basic I Pulse and Modem Equipped Maintenance Fee for Non-Billing Meter 3.94$ 2.60$ 41 Basic I Pulse Equipped Maintenance Fee 2.47$ 1.40$ 42 Basic I Pulse Equipped Maintenance Fee for Non-Billing Meter 3.56$ 1.40$ 43 Basic I+M 354.00$ 359.00$ 44 Basic I+P 259.00$ 328.00$ 45 Basic I+P&M 397.00$ 402.00$ 46 Dual Socket Adapter Device Charge T&M T&M47 Dual Socket Adapter Device Installation Charge T&M T&M48 Engineering Estimate or Job Design 42.60$ 43.00$ 49 IDR Meter Installation 233.00$ 260.00$ 50 IDR Meter Modem Interface Installation 311.00$ 348.00$ 51 IDR Meter Pulse and Modem Interface Installation 362.00$ 402.00$ 52 IDR Meter Pulse Interface Installation 305.00$ 338.00$ 53 IDR Meter Test 176.00$ 198.00$ 54 Incomplete Trip Fee 89.00$ 100.00$ 55 Investigation and Scheduling Charge T&M T&M56 Material Handling Charge T&M T&M57 Meter Removal Service 120.00$ 134.00$ 58 Meter Replacement with Standard SCE Demand Meter 185.00$ 207.00$ 59 Meter Replacement with Standard SCE IDR Meter 228.00$ 257.00$ 60 Pulse Adapter Equipment and Installation 248.00$ 274.00$ 61 Third Party Return of an SCE Meter Penalty Replace cost

of meter Replace cost

of meter

223

To determine the Test Year forecast of DA Service Fee revenue, the 2012 recorded 1

volumes of transactions were used. The forecast of transaction volumes was applied to the level of 2

service fees to estimate the level of revenues expected in the Test Year. 3

Table X-78 below shows the categories of DA services and the forecast of revenues by 4

functional area. Revenues from DA services are forecast to total $277,000 in 2015. 5

Table X-78 DA Service Fee Revenues

(Nominal $s)

Line No. Direct Access Services

Proposed Fee

Forecasted 2015 OOR

($000s)1 UDC Consolidated Billing Various 121$ 2 EDI VAN Charge 0.16$ 33$ 3 Meter Data Posting 0.18$ 61$ 4 Metering Fees Various 60$ 5 Non-Discretionary Fees Various 1$

6 Total OOR Forecast 277$

Figure X-42 below shows the historical and 2015 Test Year forecast DA Service Fee 6

OOR. 7

224

Figure X-42 FERC 456.401

DA Service Fee Revenues (Nominal $000s)

2. FERC Account 456.412 – Community Choice Aggregation (CCA) Service Fees 1

This Subaccount records the revenues forecast in the Test Year for the CCA service fees 2

below in Figure X-43. The current services and commensurate fees were adopted as the result of D.04-3

12-046 and D.05-12-041, which implemented portions of Assembly Bill (AB) 117 concerning CCA. 4

AB 117 permits cities, counties, or Joint Power Authorities whose governing boards have decided to 5

acquire their own electric power needs and act as CCAs to purchase and sell electricity on behalf of 6

retail end-use customers within their jurisdictional area(s). The CCA service fees became effective in 7

December 2006. The 34 current CCA service fees are contained in Rate Schedule CCA-SF and CCA-8

INFO. We have no active CCAs and thus, have low recorded revenue based on the service fees 9

contained in that Rate Schedule. With the deployment of the ESC meter technology, customers are 10

provided daily access to interval data at no incremental cost. In the 2012 GRC, SCE proposed the 11

elimination of all meter reading fees for CCA customers. This was approved in D.12-11-051. The 12

forecast for CCA Service Fees were calculated using the last year recorded. 13

225


CCA Service Fee Revenue (Nominal $000s)

In the Test Year, SCE is proposing to update the current CCA fees (see Table X-79 1

below) in Rate Schedule CCA-SF and CCA-INFO to reflect changes in process flows for providing the 2

service as well as labor costs and non-labor costs such as postage and banking fees. 3

226

Table X-79 CCA Service Fees

(Nominal $s)

Line No. Fee Description

CurrentFees

ProposedFees

1 CCA Provider Establishment 1,705.00$ 606.01$ 2 CCA EDI Testing T&M T&M3 CCA Credit Establishment 157.00$ 174.00$ 4 Customer Notification 1.70$ 1.70$ 5 Mass Enrollment - Per Event 2,991.00$ 3,041.00$ 6 Mass Enrollment - Per Service Account 0.13$ 0.13$ 7 Customer Contact Opt-out 0.46$ 0.46$ 8 VRU Opt-out 0.52$ 0.53$ 9 Internet Opt-out 2.07$ 1.90$ 10 CCASR 0.91$ 0.98$ 11 Customer Re-entry 1.37$ 1.30$ 12 Cancellation 1.31$ 1.30$ 13 New Customer 0.61$ 0.66$ 14 Opt-out CCASR 1.26$ 1.20$ 15 Standard Bill by Mail Charge 0.29$ 0.58$ 16 Standard Bill by Internet 0.26$ 0.11$ 17 Additional Page Charge 0.21$ 0.08$ 18 CCA Non-Energy Billing Receivable 8.79$ 9.00$ 19 Voluntary Termination - Per Event 2,991.00$ 3,041.00$ 20 Voluntary Termination - Per Service Account 0.13$ 0.13$ 21 Meter Data Posting 0.08$ 0.18$ 22 Special Requests T&M T&M23 Monthly Account Maintenance 1.13$ 1.50$ 24 Miscellaneous Customer Notification 0.38$ 0.38$ 25 Phase In - Per Event 2,991.00$ 3,041.00$ 26 Phase In - Per Service Account 0.13$ 0.13$ 27 Aggregate Annual Usage Report, by Customer Status 61.90$ 68.00$ 28 Aggregate Annual Usage Report, by Customer Status (15/15 Rule applied) 77.38$ 85.00$ 29 Aggregate Annual Usage Report, by Rate Schedule 61.90$ 76.00$ 30 Aggregate Annual Usage Report, by Rate Schedule (15/15 Rule applied) 123.80$ 161.00$ 31 Aggregate Annual Usage Report, by Zip Code 61.90$ 68.00$ 32 Aggregate Annual Usage Report, by Zip Code (15/15 Rule applied) 100.59$ 136.00$ 33 Aggregate Annual Usage Report, Standard File 197.82$ 161.00$ 34 Aggregate Annual Usage Report, Standard File (15/15 Rule applied) 197.82$ 246.00$

G. Other - Miscellaneous OOR Accounts 1

1. FERC Account 456.415 – Manufactured Home Billing Service 2

Subaccount 456.415 records the revenue SCE receives from customers that use the 3

Manufactured Home Billing Service. SCE’s Tenant Bill Calculation Service is an optional fee-based 4

service available to Manufactured Home Park owners/operators on a contractual basis. This service is 5

227

designed to offer the option of having SCE calculate the amount of each tenant’s monthly electric bill. 1

The individual tenant bill amounts are calculated based on input provided by the owner/operator after 2

receiving their monthly master bill from SCE. Each tenant bill is based on the Commission’s approved 3

domestic tariffs. This service provides a secure website to retain specific information regarding tenant 4

electric billing data, and performs the usage tenant bill calculations. 5

Figure X-44 below shows the historical and forecast OOR for the Manufactured Home 6

Billing service. The forecast for 2015 is based on a five-year average. There is no forecast for Bill 7

Calculation Presentation by Disc as SCE is proposing to eliminate this fee due to obsolescence and no 8

customer demand for this format. (See Fees to Eliminate at the end of this Section for more 9

information.) 10


Manufactured Home Billing Service (Nominal $000s)

2. FERC Account 456.948 – Optimal Billing Period 11

Subaccount 456.948 records the revenue SCE receives from customers that uses the 12

Optimal Billing Period Service. This special condition provides for the voluntary use of an Optimal 13

Billing Period (OBP), which allows for a customer’s billing cycle(s) to coincide with the customer’s 14

228

high seasonal production cycle. The customer designates the OBP by selecting a specific month and day 1

for the start of the OBP and a specific month and day for the end of the OBP. The start and end dates 2

must fall within the customer’s high seasonal production cycle. 3

To qualify for this option, the duration of the customer’s high seasonal production cycle 4

must be six months or less, and the average of the customer’s monthly maximum demand during the 5

OBP must be at least double the average of its monthly maximum demand during the non-OBP period. 6

Customers may not discontinue this option before the end date of their OBP. Prior to receiving OBP 7

service, the customer signs an agreement and pays an OBP fee of $160.00 per meter. To continue 8

service under this Special Condition the customer must sign a new OBP Agreement and pay the OBP 9

fee each year. 10

Figure X-45 provides recorded and forecast data associated with the OBP. The revenue 11

for this account is estimated to be $960 for the forecast period based on six customers paying fees of 12

$160 each. 13

229

Figure X-45 FERC Account 456.948 Optimal Billing Period

(Nominal $000s)

3. FERC Account 451.780 – Misc. Revenues-Recovered for Unauthorized Use / Non-1

Energy 2

This Subaccount records the non-energy costs that SCE recovers from the responsible 3

party for unauthorized use of electric service. These costs include the cost of the investigation (i.e., 4

investigator time), bookkeeping costs to re-bill the customer, overhead costs, and damages to SCE’s 5

property. 6

The historical data in Figure X-46 fluctuates due to the types of unauthorized use and 7

theft cases found in the field and the extent of the corrective action taken by the investigator and others. 8

SCE continues to see sophisticated, elaborate theft and unauthorized use conditions that require 9

extensive time and material to correct the infractions imposed by the customer. Further, it is difficult to 10

accurately predict the levels of future cost recovery associated with unauthorized use of electric service 11

because these numbers are driven by unlawful behavior. The estimate of 2015 revenue for this account 12

is $205,000 and is based on the 2012 last recorded year for this subaccount. This forecast is based on 13

230

the consistent downward trend of historical customer usage patterns and energy theft for residential, 1

commercial, and industrial customers. 2

Figure X-46 FERC 451.780

Miscellaneous Revenue from Unauthorized Use/Non-Energy (Nominal $000s)

4. Demand Response Provider Service Fees 3

On December 4, 2012, the Commission issued D.12-11-025, which establishes policies 4

for demand response resources to directly participate in the CAISO’s wholesale market. During 2013, 5

the IOUs are working with Commission staff and other stakeholders to finalize the direct participation 6

rules and service fees (e.g., Rule 24 and associated agreements), which are expected to be complete by 7

the end of 2013. Once Rule 24 is formally adopted by the Commission, SCE expects that the IOUs will 8

be directed to submit an application for the services and related fees to facilitate demand response 9

resources of their Bundled customers to integrate into the CAISO’s wholesale market. Such an 10

application will file in early 2014 with establishment of the service fees cost recovery mechanisms by 11

2015. 12

231

H. Fees to Eliminate 1

SCE is requesting to eliminate one service fee as described in Section F. Other - Miscellaneous 2

OOR Accounts, 1. FERC Account 456.415 – Manufactured Home Billing Service. SCE is proposing to 3

eliminate the use of compact disc billing as an option for the Manufactured Home Billing (MHB) 4

Service. This billing delivery is antiquated and no longer requested by any of SCE’s MHB customers. 5

SCE will continue to offer billing statements via the mail or e-mail correspondence. 6

Appendix A

Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF DAVID BERNAUDO 3

Q. Please state your name and business address for the record. 4

A. My name is David Bernaudo, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Principal Manager for the Meter Services Organization in the Customer Service 8

Operating Unit (CSOU). I am responsible for maintaining the integrity of SCE’s electrical 9

metering system and delivering field based customer service to SCE’s 4.8 million customers, and 10

includes meter technicians, field service representatives, revenue protection investigators and 11

support personnel. 12

Q. Briefly describe your educational and professional background. 13

A. I earned a Bachelor of Arts in Management degree from Villanova University and am a FEMA 14

certified Planning Chief. I joined SCE in 1980 and have over 30 years of utility experience. I 15

have held various positions within metering throughout my career, including positions as a Meter 16

Technician, Meter Shop Supervisor, Field Test Supervisor, Manager of Direct Access Metering 17

Operations, Manager of Revenue Protection, and Manager of Meter Engineering – Meter Shop. 18

I have been in my current position since 2012 19

Q. What is the purpose of your testimony in this proceeding? 20

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-04, 21

Volume 2, entitled Customer Service – Customer Service Operations, as identified in the Table 22

of Contents thereto. 23

Q. Was this material prepared by you or under your supervision? 24

A. Yes, it was. 25

Q. Insofar as this material is factual in nature, do you believe it to be correct? 26

A. Yes, I do. 27

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 28

judgment? 29

A. Yes, it does. 30

Q. Does this conclude your qualifications and prepared testimony? 31

A-2

A. Yes, it does. 1

A-3

SOUTHERN CALIFORNIA EDISON COMPANY


OF TRACY M. FELIX 2


A. My name is Tracy M. Felix, and my business address is 9500 Cleveland Avenue, Rancho 4

Cucamonga, California 91730. 5


A. I am the Director of the Customer Contact Center within the Customer Service Organization for 7

Southern California Edison. I am responsible for planning, strategy, and operations of Southern 8

California Edison’s Customer Contact Center. Our contact center responds to customer inquiries 9

and requests received over the phone and Internet 24-hours a day, 7 days a week for SCE’s end-10

use customers. 11


A. I received my Bachelor of Science Degree in Business Administration from the University of 13

California, Riverside. I have worked for Southern California Edison for 21 years. I have held 14

various positions within Customer Service primarily in Revenue Services Organization and 15

Customer Contact Center. 16






A. Yes, it was. 22


A. Yes, I do. 24


judgment? 26

A. Yes, it does. 27


A. Yes, it does. 29

A-4

SOUTHERN CALIFORNIA EDISON COMPANY 1


OF CHARLIE C. HU 3


A. My name is Charlie Hu, and my business address is 1551 W. San Bernardino Road, Covina CA 5

91722. 6


A. I am the Director for the Revenue Services Organization within Customer Service. I am 8

responsible for the planning, strategy and operations for Southern California Edison’s Revenue 9

Services Organization. Revenue Services Organization is responsible for billing, payment, credit 10

and collection, program service activities including postage oversight for all our customers. 11


A. I hold a Bachelor of Science (B.S.) degree in Computer Science from California State University 13

of Los Angeles. I completed the Management Program from Columbia University Graduate 14

School of Business and various graduate classes from Pepperdine University. I have worked for 15

Southern California Edison for over 23 years. I was in the Information Technology organization 16

the first six years where I held positions with increasing responsibility involving system 17

development and implementation of our current billing system. The last seventeen years include 18

leadership roles involving implementation of various major initiatives in Customer Service with 19

focus in the areas of customer service, metering, meter reading, field services, billing, and 20

revenue collections. I have also held leadership positions within Revenue Services Organization 21

including Credit and Payment Services and Usage and Billing Group. 22






A. Yes, it was. 28


A. Yes, I do. 30

A-5


judgment? 2

A. Yes, it does. 3


A. Yes, it does. 5

A-6


QUALIFICATIONS AND PREPARED TESTIMONY

OF SETH KINER


A. My name is Seth J. Kiner, and my business address is 2244 Walnut Grove Avenue, Rosemead, 2

California 91770. 3


A. I am the Vice President of Customer Programs and Services, in the Customer Service Business 5

Unit, at Southern California Edison. I have responsibility for leading SCE’s energy efficiency, 6

demand response and clean self-generation program portfolios and customer strategy, marketing, 7

market research, e-commerce and strategic alliances functions. 8


A. I received a Bachelor of Science degree in Business Administration, with a major in Marketing, 10

from Arizona State University in 1983. I have over 25 years of management experience leading 11

marketing, product management and communications efforts to reach diverse audiences, working 12

in a variety of industries including: utility, not-for-profit, financial services and 13

telecommunications. My three most immediate positions prior to SCE were: Director of 14

Marketing, KPMG, LLC; Vice President of Marketing, United Way of Greater Los Angeles; and 15

Director of Marketing and Marketing Communications, Transamerica Life Companies. 16



Volume 2, entitled Customer Service – Customer Service Operations, as identified in the Tables 19



A. Yes, it was. 22


A. Yes, I do. 24


judgment? 26

A. Yes, it does. 27


A-7

A. Yes, it does. 1

A-8



OF LORENE MILLER 2


A. My name is Lorene M. Miller, and my business address is 6060 North Irwindale Avenue, Suite 4

E, Irwindale, California 91702. 5

Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE). 6

A. I serve as Director of Business Transformation, responsible for leading major technology-7

enabled programs and overseeing the portfolio of system enhancement investments for the 8

Customer Service Operating Unit. 9


A. I hold a Bachelor of Science Degree in Computer Science from California State University at 11

Los Angeles and a Master of Science degree in Leadership and Management from the University 12

of La Verne. I have been employed at Southern California Edison (SCE) for over twenty-three 13

years. My experience at SCE includes systems analysis and application development in the 14

Information Technology department and over eighteen years of leadership experience in project 15

and operations management in the Customer Service and Information Technology areas. I was 16

the senior manager of the Billing Organization responsible for metering, billing, payment, and 17

credit management of SCE’s end-use customers from 2000-2003. In December 2003, I was 18

promoted to Director of Business Process & Technology Integration for Customer Service and 19

from 2006 through 2008. I was Director of the Program Management Office of the Enterprise 20

Resource Planning project responsible for project scope and deliverables for the largest utility 21

implementation of SAP software. From February 2008 through April 2013, I was Director of the 22

Customer Communication Organization responsible for planning, strategy and operations of 23

SCE’s Customer Contact Center. I assumed my current position in April 2013. 24



Volume 2, entitled Customer Service – Customer Service Operations, as identified in the Tables 27



A-9

A. Yes, it was. 1


A. Yes, I do. 3


judgment? 5

A. Yes, it does. 6


A. Yes, it does. 8

A-10



OF LAWRENCE M. OLIVA 2


A. My name is Lawrence M. Oliva, and my business address is 2244 Walnut Grove Avenue, 4



A. I serve as the Director of the Meter Services Organization in the Customer Service Operating 7

Unit (CSOU). This is the senior leadership position in the organization. The Meter Services 8

Organization is responsible for all aspects of the end-to-end meter process including: 9

Evaluating and monitoring the business environment 10

Planning, developing, and implementing meter process improvements 11

Performing meter evaluations and laboratory testing 12

Planning, testing and implementing new and efficient metering and associated technologies 13

Meter installation, change, maintenance, assessments and compliance 14

Field customer service requests, including turn-ons and turn-offs 15

Routine and non-routine meter reading 16

Investigating unauthorized use and recovery of revenue loss 17

Ensuring the accuracy and integrity of revenue billing 18


A. I earned a Bachelor of Science Degree in Civil Engineering from Southern Methodist University 20

in 1972. Prior to joining SCE as an employee in 2007, I was a business consultant in the energy 21

industry for over 30 years. I was a principal and director of an international economics 22

consulting firm, Putnam, Hayes and Bartlett, Inc., and a business consulting partner of Arthur 23

Andersen. In past several years, I provided consulting services to SCE in the areas of demand 24

response and advanced metering. 25



Volume 2, entitled Customer Service – Customer Service Operations as identified in the Table of 28

Contents thereto. 29


A-11

A. Yes, it was. 1


A. Yes, I do. 3


judgment? 5

A. Yes, it does. 6


A. Yes, it does. 8

A-12


QUALIFICATIONS AND PREPARED TESTIMONY

OF ABDOU TERKI-HASSAINE


A. My name is Abdou Terki-Hassaine, and my business address is 2244 Walnut Grove Avenue, 2



A. I am the Vice President of the Customer Service Operations Division within Customer Service 5

(CS). I am responsible for overseeing the billing and payment operations, revenue protection, 6

credit and collections, meter services, call center operations and the customer service technology 7

portfolio for Southern California Edison. 8


A. I received my Bachelors of Science degree in physics from the University of Tlemcen in Algeria; 10

a Masters degree of Science in Quantitative Business Method from Cal State University, East 11

Bay; and an MBA from Rice University in Houston. I was formerly the Vice President of 12

Customer Experience at MetLife Insurance Company overseeing call center operations. While 13

there, I led the implementation of leading-edge technologies and process improvements that 14

increased customer satisfaction, efficiency and employee engagement. Prior to joining MetLife, 15

I held executive positions at Fidelity Investments and JP Morgan Chase. In January 2013, I 16

assumed my current position with Southern California Edison. 17



Volume 2, entitled Customer Service - Overview of Customer Service Operations, as identified 20

in the Table of Contents thereto. 21


A. Yes, it was. 23


A. Yes, I do. 25


judgment? 27

A-13

A. Yes, it does. 1


A. Yes, it does. 3

Appendix B

SCE’s Efforts to Work with CBOs in all Aspects of Customer Education and Outreach

B-1

Background 1

On November 29, 2012, the Commission issued D.12-11-051 in SCE’s 2012 GRC Application 2

(A.10-11-015) that requires SCE to provide a description of its efforts to include and work with 3

Community Based Organizations (CBOs) in all aspects of customer education and outreach in this GRC. 4

This Appendix describes SCE’s partnerships with CBOs to conduct education and outreach activities. 5

These activities include O&M funded education and outreach efforts led by SCE’s Consumer Affairs 6

organization as well as PGC funded energy efficiency and low-income program efforts. 7

Overview 8

As trusted members of the communities they serve, CBOs are a valuable resource to facilitate 9

SCE’s efforts to outreach and inform residential and small business customers on SCE’s most current 10

service offerings and opportunities to manage and reduce their bills. Due to their roles in the 11

communities they serve, CBOs are particularly helpful in reaching the low-income, non-English 12

speaking, senior, and small business communities. 13

More than 50 CBOs participated in SCE’s CARE Capitation Program in 2012 and received fees 14

for enrolling more than 3,000 non-participating customers on the CARE rate. In SCE’s service area, 15

five CBOs provide limited English proficient (LEP) customers in-language education, needs and dispute 16

resolution, and outreach for energy issues through the CPUC Community Help and Awareness with 17

Natural Gas and Electricity Services (CHANGES) pilot program. 18

SCE contracts with ten CBOs to assess households for Energy Savings Assistance Program 19

eligibility, provide energy education, and install measures in qualified households. The SCE / SoCalGas 20

Community Language Efficiency Outreach (CLEO) program provides energy efficiency outreach to 21

communities by providing free energy saving seminars in Chinese, Vietnamese, Korean, Spanish and 22

Hindi. CLEO hosted 38 seminars and 35 booths in local communities within SCE’s territory in 2011, 23

reaching 10,869 customers and collecting 1,275 completed 5-minute energy surveys. 24

SCE convened eight community forums in 2012 to provide important information on SCE 25

programs and services to key nonprofit organizations. SCE’s experience the past few years is the 26

forums strengthen strategic relationships between underserved and low-income communities and SCE 27

through networking and partnerships. The forums allow SCE to explore ways to leverage opportunities 28

to better assist these communities and customers experiencing the worst effects of the economic 29

downturn. As one example, SCE’s August 2012 community forum in Pomona drew over 160 30

participants from 78 different nonprofit organizations, faith-based groups, and educational institutions. 31

B-2

In-language outreach and translation allowed SCE to achieve a broader and more inclusive participation 1

reflective of the community through questions, comments, and discussion throughout the program. 2

CBOs are key participants in SCE’s Consumer Affairs Division efforts to outreach and educate 3

seniors and customers with disabilities about programs and services that can lower electric bills and 4

provide payment assistance. SCE participates in collaborative efforts and provides information to key 5

agencies about CARE, Medical Baseline and other programs of interest to the clients served by member 6

agencies. One example of this outreach is SCE, SoCalGas, and the CPUC presented jointly to the Inland 7

Empire Disabilities Collaborative consisting of 480 member agencies. Also, SCE made presentations 8

about SCE programs and services and provided "training classes" to the Riverside Office on Aging (over 9

30 social workers), the Council on Aging-Orange County, and other agencies that serve SCE’s senior 10

population. 11

SCE has presented to the majority of Regional Centers within SCE’s service area. Regional 12

Centers are nonprofit agencies funded by the State of California to provide resources to people with 13

disabilities. Although SCE’s presentations and training to these agencies are in English, their client 14

population often is ethnically diverse. Agencies are empowered to communicate directly with clients on 15

services that may benefit them. SCE visits at least two senior centers per month, focusing on centers 16

with congregate meal programs where you are most likely to encounter low-income seniors. Some of 17

these centers are operated by CBOs, have a high ethnic population, and request materials in other 18

languages (primarily Spanish). 19

During the December 2011 San Gabriel Valley windstorm, CBOs were a vital conduit to getting 20

critical status updates during the restoration period out to LEP customers. SCE followed-up with 21

communications to 37 Community Investment and Philanthropy Nonprofit Partners and eight Energy 22

Assistance Fund (EAF) and CARE Capitation agencies with information on how to file claims and 23

information on in-language customer service. 24

In 2012, the Energy Efficiency Outreach Team (EEOT) partnered with numerous CBOs 25

including Chambers of Commerce, faith-based organizations, and ethnic business associations with the 26

objective of reaching small business customers to provide targeted messages about energy efficiency, 27

demand response programs, and newly available tools as a result of ESC. SCE’s small business 28

outreach group focuses on reaching diverse small businesses, often in-language, through ethnic business 29

organizations. An example of a collaborative effort in 2012 is the partnership between SCE’s EEOT 30

and the South Bay Environmental Services Center. This effort involved reaching out to Spanish 31

B-3

speaking small business owners by delivering an in-language presentation about implementing 1

conservation and energy efficiency to reduce electricity costs. This type of effort was duplicated with 2

other in-language presentations for Vietnamese, Cambodian, and Chinese organizations. 3

SCE also formed a Medium/Small Business Advisory Panel (MS BAP) in 2012 that includes 4

representatives from non-profit organizations including the National Association of Woman Business 5

Owners Inland Empire Chapter, the California Small Business Association, the Korean American 6

Chamber of Commerce of Orange County, the Orange County Chinese American Chamber of 7

Commerce, the Regional Hispanic Chamber of Commerce, and the Vietnamese American Chamber of 8

Commerce, as well as other small business organizations and individual small business owners. The MS 9

BAP educates leadership from small business communities about key programs, initiatives, and 10

upcoming rate impacts that will affect an organization’s constituents and peers. The MS BAP advises 11

SCE about effective and impactful ways to communicate such messages to minority small businesses. 12

SCE’s EEOT group also participates in SCE sponsored Community Forums and hosts five key signature 13

events: Black History Month, Asian American Pacific Islander Heritage Month, and Hispanic Heritage 14

Month. The events recognize and highlight small business owners and energy efficiency partnerships 15

among an audience of peers. SCE expects to continue all the activities outlined above into 2013 and 16

beyond. In addition, the MS BAP partnerships will be expanded to allow SCE the opportunity to 17

formulate messaging that can be shared with the non-profit organizations' constituents. 18