Customer Service Volume 3 - Customer Service and ......SCE-04: Customer Service Volume 03 - Customer Service and Information Delivery Table Of Contents (Continued) Section Page Witness

Application No.: Exhibit No.: SCE-04, Vol. 3 Witnesses: L. Cagnolatti

K. Devore J. Lim C. Prescott T. Walker

(U 338-E)

Customer Service Volume 3 - Customer Service and Information Delivery

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SCE-04: Customer Service Volume 03 - Customer Service and Information Delivery

Table Of Contents

Section Page Witness

-i-

I. OVERVIEW OF BUSINESS CUSTOMER SERVICES..................................1 L. Cagnolatti

A. Overview of Business Customer Services .............................................1

1. Business Customer Division ......................................................1

2. Customer Programs and Services ..............................................2

3. Operating Unit Management and Support .................................2

B. Impact of a Fully Deployed Edison SmartConnect® System ....................................................................................................2

C. Customer Engagement for Non-Residential Customers ........................3

1. Account Management Provides Essential Customer Engagement for SCE’s Non-Residential Customers .................4

2. Customer Engagement Requires Energy Information and Tools ................................................................5

3. Engaging Customers Is Crucial to the Implementation of Dynamic Pricing ..........................................5

D. Productivity and Operational Excellence ...............................................5

II. SUMMARY OF REQUEST FOR BUSINESS CUSTOMER SERVICES .........................................................................................................7

III. BUSINESS CUSTOMER DIVISION ...............................................................8 K. Devore

A. Description of Business Customer Division Activities .........................8

1. Account Management Services ..................................................9

a) Descriptions of Account Management Services Activities .........................................................9

(1) Rate Analysis Information and Education .........................................................13

(2) Billing and Metering Inquiries .........................14

(3) Credit Issue Information ..................................14


Table Of Contents (Continued)


-ii-

(4) Power Quality Information ..............................15

(5) Energy Advisor / Marketplace Communication ................................................16

(6) Demand Response Information ........................16

(7) Outage Communications ..................................17

(8) Plug-In Electric Vehicle Support .....................18

(9) Customer Relationship Management System ..............................................................18

b) Account Management Services Base Year Operating Results .........................................................19

c) Analysis of Historical Data ..........................................19

d) Test Year Expectations ................................................20

(1) Optimizing Account Management Support Activities Will Result in Reduced Account Management Cost ...............21

(2) Customer Growth .............................................21

2. Technical Services ...................................................................22

a) Descriptions of the Technical Services Activities ......................................................................22

(1) Rate and Data Analysis Services .....................22

(2) Field Engineering Services ..............................22

(3) Special Contract and Tariff Administration Services ...................................23

(4) Education and Communications ......................23

(5) Customer Requests for Assistance with Distributed Generation Projects ...............23




-iii-

b) Technical Services Base Year Operating Results ..........................................................................24

(1) Rate Analysis Services .....................................24

(2) Customer Requests for Assistance with Distributed Generation Projects ...............25

(3) Other Technical Services Activities .................26


d) Test Year Operating Expectations ...............................28

3. Energy Education Centers ........................................................28

a) Descriptions of the Energy Education Centers .........................................................................28

(1) SCE Energy Education Center–Irwindale ..........................................................29

(2) SCE Energy Education Center–Tulare ...............................................................29

b) Energy Education Centers Base Year Operating Results .........................................................31


d) Energy Education Center Test Year Operating Expectations ................................................33

4. Customer Choice Services .......................................................33

a) Description of the Customer Choice Services ........................................................................34

(1) Contract Management ......................................34

(2) Account Management ......................................35

(3) Service and Support .........................................35




-iv-

b) Customer Choice Services Base Year Operating Results .........................................................36

(1) Electric Service Provider and Direct Access Activities ..............................................36

(2) Customer Choice Aggregation Activities ..........................................................37


d) Customer Choice Services Test Year Expectations .................................................................38

5. Economic Development Services ............................................38

a) Descriptions of the Economic Development Services Function .........................................................38

(1) Project Management ........................................39

(2) Business Development .....................................39

b) Economic Development Services Base Year Operating Results .........................................................39

(1) Project Management ........................................39

(2) Business Development .....................................40

(3) Ratepayer Impact Measurement (RIM) Test .......................................................42

(4) Economic Benefit in California .......................43


d) Economic Development Services Test Year Operating Expectations ................................................44

B. Business Customer Division Recorded Cost Summary .......................44

C. Test Year Expectations (FERC Account 908.600) ..............................46




-v-

1. Determination of Test Year Estimating Methodology ............................................................................47

2. Test Year Adjustments .............................................................47

a) Account Management Services (Summary) ................48

b) Economic Development Services (Summary) ...................................................................48

3. Test Year Forecast ...................................................................48

D. Business Customer Division Capital ...................................................49

1. Introduction ..............................................................................49

2. Structures and Improvements – Energy Education Centers (CCS-00-SI-BC-CT-00001 and CCS-00-SI-BC-AT-00001) .........................................................................49

a) Energy Education Center – Irwindale ..........................50

b) Energy Education Center – Tulare ...............................50

3. Specialized Equipment (CCS-00-SE-BC-PT-00001 and CCS-00-SE-BC-TS-00001)...............................................50

a) Engineering Tools and Equipment ...............................51

E. Business Customer Division Other Operating Revenues (OOR) ..................................................................................................51

1. Introduction ..............................................................................51

2. Estimating Method for OOR ....................................................52

3. FERC Account 456.924 – Energy Related Services ...............52

4. FERC Account 456.945 SCE – EnergyManager® ...................54

IV. CUSTOMER PROGRAMS AND SERVICES ...............................................57 J. Lim




-vi-

A. Consumer Affairs, Customer Satisfaction, Marketing, Communications and Digital Delivery of Customer Services ................................................................................................57

B. Customer Programs ..............................................................................58 T. Walker

1. Description of Customer Programs ..........................................58

a) Energy Information and Management Programs ......................................................................58

b) Dynamic Pricing Programs ..........................................59

c) Other Customer Service Related Programs .................60

2. Base Year (2012) Operating Results ........................................61

a) Energy Management and Information Programs ......................................................................61

(1) Web Presentment of Interval Data ...................61

(2) Web Presentment of Cost Information ......................................................61

(3) Budget Assistant ..............................................62

(4) SCE EnergyManager .......................................66

b) Dynamic Pricing ..........................................................67

(1) Time-of-Use (TOU) Rates ...............................67

(2) Critical Peak Pricing (CPP) .............................68

(3) Real Time Pricing (RTP) .................................69

c) Customer Service Related Programs ...........................69

(1) Renewable Tariffs and Interconnection Programs ................................69

d) Other Programs and Services .......................................71




-vii-

3. Analysis of Historical Data (FERC Account 908.640) ...................................................................................71

4. Customer Programs Test Year Expectations (FERC Account 908.640) .....................................................................73

a) Determination of Test Year Estimating Method .........................................................................73

b) Customer Programs Test Year Expectations ...............73

(1) Implementation of Dynamic Pricing ................74

(2) Renewable Tariffs and Interconnection Programs ................................76

c) Summary of FERC Account 908.640 Forecast ........................................................................76

V. OPERATING UNIT MANAGEMENT AND SUPPORT ..............................78 C. Prescott

A. Description of Operating Unit Management and Support ...................78

1. Finance and Administration .....................................................78

a) Description of Finance and Administration Functions ......................................................................78

(1) Planning and Performance Reporting ..............78

(2) Regulatory Finance and Long-Term Planning ...........................................................79

(3) Internal Controls ..............................................79

(4) Timekeeping ....................................................79

(5) Payment Processing .........................................80

2. Business Planning ....................................................................80

a) Description of the Business Planning Function .......................................................................80




-viii-

3. Customer Service Regulatory and Tariff Program Support .....................................................................................81

a) Description of the Regulatory and Tariff Support Function ..........................................................81

B. Operating Unit Management and Support Base Year Operating Results .................................................................................81

1. Summary of Recorded Costs (FERC Account 907.600) ...................................................................................81

2. Analysis of Historical Data (FERC Account 907.600) ...................................................................................81

C. Operating Unit Management and Support Test Year Expectations (FERC Account 907.600) ..............................................82

1. Determination of Test Year Estimating Methodology ............................................................................83

2. Test Year Adjustments .............................................................83

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


List Of Figures

Figure Page

-ix-

Figure I-1 SCE’s New Customer Service Model .........................................................................................4

Figure III-2 Business Customer Division Recorded And Adjusted 2008-2012/Forecast

2013-2015 FERC Account 908.600 (Constant 2012 $000) .................................................................47

Figure III-3 Business Account Services Comparison of 2012 Base Year to 2015 Test

Year FERC Account 908.600 (Constant 2012 $000s) .........................................................................49

Figure III-4 FERC Account 456.924 Energy Related Services (Nominal $000) ......................................54

Figure III-5 FERC Account 456.945 Forecasted SCE EnergyManager OOR (Nominal

$000) ....................................................................................................................................................56

Figure IV-6 Customer Programs and Rates FERC Account 908.640 (Constant 2012

$000s) ...................................................................................................................................................73

Figure IV-7 Customer Programs and Rates Comparison of 2012 Base Year to 2015 Test

Year FERC Account 908.640 (Constant 2012 $000s) .........................................................................77

Figure V-8 Operating Unit Management and Support FERC Account 907.600 (Constant

2012 $000s) ..........................................................................................................................................83

Figure V-9 Operating Unit Management and Support Comparison of 2012 Base Year to

2015 Test Year FERC Account 907.600 (Constant 2012 $000s) ........................................................84


List Of Tables

Table Page

-x-

Table I-1 Productivity Initiatives Impact to 2015 Test Year (Constant 2012 $ millions) ..........................6

Table II-2 Summary of Business Customer Services by FERC Account FERC Accounts

907-908 (Constant 2012 $000) ..............................................................................................................7

Table III-3 Account Management Resource Assignments ........................................................................12

Table III-4 Account Management Recorded/Adjusted Expenses (2008-2012) (Constant

2012 $000) ...........................................................................................................................................19

Table III-5 Rate Analyses Performed for Non-Residential Customers by Year .......................................25

Table III-6 Technical Services Recorded/Adjusted Expenses (2008-2012) (Constant

2012 $000) ...........................................................................................................................................27

Table III-7 Description of SCE’s Energy Education Center – Irwindale Facilities ..................................30

Table III-8 Description of SCE’s Energy Education Center – Tulare Facilities .......................................31

Table III-9 Energy Education Centers Recorded/Adjusted Expenses (2008-2012)

(Constant 2012 $000) ...........................................................................................................................32

Table III-10 Customer Choice Services Recorded/Adjusted Expenses (2008-2012)

(Constant 2012 $000) ...........................................................................................................................37

Table III-11 Economic Development Services Recorded/Adjusted Expenses (2008-2012)

(Constant 2012 $000) ...........................................................................................................................43

Table III-12 Business Customer Division Recorded/Adjusted Expenses (2008-2012)

FERC Account 908.600 (Constant 2012 $000) ...................................................................................46

Table III-13 Summary of Test Year Forecast Adjustments FERC Account 908.600

(Constant 2012 $000) ...........................................................................................................................48

Table III-14 Energy Education Centers Structures and Improvements (Nominal $000) ..........................50

Table III-15 Business Customer Division Specialized Equipment (Nominal $000) .................................51

Table III-16 Business Customer Division Other Operating Revenues FERC Accounts

456.924 and 456.945 (Nominal $000) .................................................................................................52

Table III-17 Current and Proposed SCE EnergyManager Fees, Monthly Service Fee Per

Account ................................................................................................................................................55

Table IV-18 Budget Assistant Program Statistics .....................................................................................64


List Of Tables (Continued)

Table Page

-xi-

Table IV-19 Summary of 2012 Budget Assistant User Survey .................................................................65

Table IV-20 Features and Benefits Available to Customers through the SCE

EnergyManager ....................................................................................................................................66

Table IV-21 SCE EnergyManager Usage Statistics ..................................................................................67

Table IV-22 Net Energy Metering (NEM) Applications Received by SCE (2008-2012) .........................70

Table IV-23 Customer Programs and Rates Recorded/Adjusted Expenses (2008-2012)

FERC Account 908.640 (Constant 2012 $000) ...................................................................................72

Table V-24 Operating Unit Management and Support Recorded / Adjusted Expenses

(2008-2012) FERC Account 907.600 (Constant 2012 $000) ..............................................................82

1

I. 1

OVERVIEW OF BUSINESS CUSTOMER SERVICES 2

A. Overview of Business Customer Services 3

This Volume addresses the activities performed by the Business Customer Division (BCD) and 4

portions of the Customer Programs and Services (CP&S) Division of SCE’s Customer Service 5

organization. Also included in this Volume are the capital expenditures and other operating revenues 6

(OOR) managed by BCD. This Volume also includes Customer Service’s Operating Unit Management 7

and Support (OUMS) activities. 8

1. Business Customer Division 9

The activities performed by BCD as described in this Volume are core to engaging and 10

serving SCE’s non-residential customers with programs and services that meet their needs and enable 11

them to be more knowledgeable and involved in managing their energy usage. These activities include 12

Account Management Services, Technical Services, Energy Education Centers, Customer Choice 13

Services, and Economic Development Services as summarized below. The O&M expenses associated 14

with these activities are recorded in FERC Account 908.600. 15

Account Management Services. This function provides service and information to 16

294,000 customers associated with 683,000 non-residential service accounts. The level of service 17

provided by Account Management Services ranges from that provided by highly experienced senior 18

account managers assigned to our largest customers to our Business Solutions group that serves our 19

smallest non-residential customers. 20

Technical Services. This function supports the Account Management Services 21

organization with technical expertise in the areas of rate analysis, field engineering, distributed 22

generation project analysis, and special contract and tariff administration. The Technical Services 23

organization also assists in developing informational and educational materials, and provides usage data 24

by customer group (residential, small business, large commercial and industrial, and agricultural) to 25

cities. 26

Energy Education Centers. This function manages SCE’s two Energy Education 27

Centers—one in Irwindale and one in Tulare—dedicated to providing residential, commercial, 28

industrial, and agricultural customers with information regarding energy efficiency, demand response, 29

renewable generation, environmental solutions, the safe use of energy, utility programs, electro-30

2

magnetic fields, and power quality. The Energy Education Centers host approximately 33,600 1

customers each year. 2

Customer Choice Services. This function facilitates Energy Service Provider (ESP) and 3

Community Choice Aggregator (CCA) participation in the Direct Access (DA) and potential 4

Community Choice Aggregation markets within our service territory and provides appropriate oversight 5

of ESPs’ and CCAs’ day-to-day interactions with SCE. 6

Economic Development Services. This function supports the regional economy and 7

benefits SCE’s ratepayers by helping to retain, grow, and attract commercial and industrial customers. 8

In addition to the O&M activities described above, BCD requires capital funding for 9

ongoing upgrades and improvements to the Energy Education Centers and specialized equipment to 10

support field engineering and activities such as pump testing. BCD is also responsible for the Other 11

Operating Revenues produced by the Energy Related Services and SCE EnergyManager® programs. 12

2. Customer Programs and Services 13

The Customer Programs and Services function is comprised of Consumer Affairs and 14

Customer Satisfaction (FERC Account 905.800), Marketing, Communication and Digital Customer 15

Services (FERC Account 905.900) and Customer Programs (FERC Account 908.640). Consumer 16

Affairs and Customer Satisfaction and Marketing, Communications and Digital Customer Services are 17

described in Volume 2 of this Exhibit, and their applicability to non-residential customers is summarized 18

in this Volume. Customer Programs, presented in this Volume, develops, implements, and manages 19

many of SCE’s programs and services including energy management and information programs 20

(including Edison SmartConnect®-enabled programs and SCE EnergyManager), dynamic pricing 21

programs, and renewable tariff and interconnection programs. 22

3. Operating Unit Management and Support 23

The OUMS function includes finance and administration (including planning and 24

performance reporting, internal controls, timekeeping, and payment processing), business planning, and 25

regulatory support activities. 26

B. Impact of a Fully Deployed Edison SmartConnect® System 27

In 2012, SCE was deploying Edison SmartConnect® (ESC) meters and enabling customer 28

participation in ESC-enabled programs and services. As such, SCE’s 2012 GRC integrated the ESC 29

program into a technology-enabled customer service model. In December 2012, the deployment of the 30

ESC system was completed. As a result, in 2013 and 2014, SCE will deliver the programs and services 31

3

now afforded by the availability of interval usage data so that customers can better understand and 1

manage their energy usage. 2

In this 2015 GRC, SCE’s Test Year forecast reflects its ongoing, steady-state, post-ESC 3

deployment operations. The impact of the deployment of ESC on Business Customer Services 4

operations is significant. For example, ESC provides the interval data to support the implementation of 5

dynamic pricing, as ordered by the Commission in D.13-03-031, which will impact an estimated 6

600,000 non-residential service accounts.1 In addition, residential and non-residential commercial 7

customers with demands less than 200 kW are able to take advantage of a suite of new tools and 8

services. These new tools leverage the interval data available from the ESC meter and provide this 9

information to customers, so they can better understand the correlation between energy usage and cost. 10

C. Customer Engagement for Non-Residential Customers 11

As described in Volume 1 of this Exhibit, in this GRC period, SCE’s Customer Service Model 12

includes three key components for engaging customers (Energy Solutions, Intelligent Delivery and 13

Energy Advisory Services, and Effective and Enabling Customer Interactions) supported by two 14

foundational elements (Technology and Empowered Employees). The three key components of the 15

model are interrelated. Energy solutions influence the intelligent delivery processes and energy advisory 16

services, which then drive the types and effectiveness of customer interactions, which provides feedback 17

and lessons learned that help SCE refine and optimize its portfolio of energy solutions. Figure I-1 below 18

illustrates these key elements of our Customer Service Model. 19

1 See D.13-03-031 for details of the implementation of dynamic pricing for the small commercial and industrial rate group

(pp. 21-24), medium and large power commercial and industrial rate group (pp. 31-33), and agricultural and pumping rate group (pp. 38-41).

4

Figure I-1 SCE’s New Customer Service Model

The functions described in this Volume are key to delivering the Customer Service Model and 1

helping ensure that the processes are in place to deliver customer programs and services. As described 2

below, the functions described in this Volume support the key elements of SCE’s Customer Engagement 3

Strategy. 4

1. Account Management Provides Essential Customer Engagement for SCE’s Non-5

Residential Customers 6

SCE’s energy advisory services will rely on empowered employees (i.e., account 7

managers) in BCD. The BCD account managers are knowledgeable of their customers’ needs and the 8

programs, rates, and services available to address those needs. Because of their day-to-day interactions 9

with many of our non-residential customers, including those customers who are the most active in 10

managing their energy consumption, BCD account managers play a key role in engaging our customers. 11

BCD achieves this goal using an account management model that reflects the diversity of our non-12

residential customer population by assigning account managers to those customers who have more 13

complex energy issues and more complex billing, rate, and other customer care issues and who are very 14

active in implementing integrated demand side management (IDSM) measures, while tailoring its 15

account management services to meet the needs of medium and small non-residential customers whose 16

5

customer service needs are not as intensive. To support its account managers, BCD has established 1

teams of IDSM specialists, rate analysts, field engineers, and other technical specialists. 2

2. Customer Engagement Requires Energy Information and Tools 3

The other critical component of SCE’s customer engagement model is providing 4

customers with information about their energy usage and cost so that they can make good energy usage 5

decisions and take appropriate actions. The Customer Programs and Rates function accomplishes this 6

by providing tools such as Budget Assistant, which offers proactive outbound cost information to help 7

customers more actively manage their energy budget. 8

3. Engaging Customers Is Crucial to the Implementation of Dynamic Pricing 9

As noted above, the implementation of dynamic pricing, including the defaulting of non-10

residential service accounts with demands less than 200 kW to Critical Peak Pricing (CPP) rates 11

beginning in 2016, as ordered by the Commission in D.13-03-031, will impact an estimated 600,000 12

non-residential service accounts. Addressing the needs of these customers will require a combination of 13

tailored education and outreach, and account management services. In addition, SCE plans to engage 14

these customers through multiple communication channels, including automated voicemail, text 15

messaging, and email to inform them of CPP events on a day-ahead basis in order to provide them with 16

sufficient opportunity to plan for CPP events. 17

D. Productivity and Operational Excellence 18

In Exhibit SCE-10, productivity is defined as simply doing more while using proportionately 19

less.2 Productivity initiatives must meet at least one of the following two objectives: (1) they must 20

improve the level of service without adding cost, or (2) they must reduce cost with no adverse effect on 21

service levels. Projects meeting both objectives receive the highest priority for implementation. 22

The Test Year forecast for Business Customer Services functions reflect operational 23

improvements that are either underway now or will be implemented by the 2015 Test Year. 24

Productivity initiatives underway for the functions presented in this Volume fall under the company-25

wide Operational Excellence program.3 The details of the cost savings to result from implementation of 26

the Operational Excellence program are addressed in each of the Business Customer Services functional 27

areas in which the savings are realized and are summarized in Table I-1. 28

2 See Exhibit SCE-10, Volume 2, Part 7, Chapter IV, Section A.

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

6

Table I-1 Productivity Initiatives

Impact to 2015 Test Year (Constant 2012 $ millions)

LineNo. Program Years

Estimated Cost Savings

Text Reference

FERC Acct

1 Future2 Operational Excellence3 Business Account Services 2015 $1.6 908.600

4Operating Unit Management and Support (Centralized) 2015 $0.7

907.600

5 Total Operational Excellence $2.3

6 Future Total $2.3

7

II. 1

SUMMARY OF REQUEST FOR BUSINESS CUSTOMER SERVICES 2

This Volume covers the operating requirements of the Business Customer Division, Customer 3

Programs and Services, and Operating Unit Management and Support functions. The O&M expenses 4

for these functions are recorded in FERC Accounts 908.600 (Business Customer Division), 908.640 5

(Customer Programs and Services), and 907.600 (Operating Unit Management and Support). In 2012, 6

SCE incurred $32.612 million in O&M expenses for these functions and forecasts O&M expenses 7

totaling $31.690 million in 2015. The Test Year forecast includes productivity initiatives, an increase of 8

$258,000 to reflect the impact of customer growth on the Account Management Activities included in 9

FERC Account 908.600, an increase of $825,000 to support marketing education and outreach for 10

dynamic pricing programs, and an increase of $246,000 for NEM application processing to support the 11

growing customer interest in this tariff. These O&M adjustments are described in detail in the 12

appropriate Test Year Expectations in Chapter III below. Table II-2 summarizes the Test Year forecast 13

by FERC Account for this Volume. 14

Table II-2 Summary of Business Customer Services by FERC Account

FERC Accounts 907-908 (Constant 2012 $000)

FERC RecordedDescription Account 2012 2013 2014 2015

1 Business Customer Division 908.600 20,219 19,660 19,268 18,879 2 Customer Programs 908.640 5,584 5,637 5,891 6,655 3 Operating Unit Management and Support 907.600 6,809 6,375 6,198 6,156 4 Total Operating Expense 32,612 31,672 31,357 31,690

Line No.

Forecast

8

III. 1

BUSINESS CUSTOMER DIVISION 2

SCE’s Business Customer Division (BCD) has an important role in SCE’s efforts to engage and 3

serve our business customers. For most of SCE’s 4.4 million customers corresponding to 5.0 million 4

service accounts, helpful interaction and communication is provided through a variety of channels, 5

including monthly bills, SCE.com, mobile applications, the toll-free, 24-hour-a-day Customer Contact 6

Center, and in-person services. Using these channels, SCE can address most service-related issues, 7

billing inquiries, and other routine customer service inquiries as described in Volume 2 of this Exhibit. 8

BCD serves the needs of the non-residential customers, many of whom have more complex energy 9

issues, more complex billing, rate, and other customer care issues, and are very active in implementing 10

integrated demand side management (IDSM) measures. In order to meet these needs, BCD is staffed 11

with experienced professionals who are knowledgeable of the needs of non-residential customers; 12

familiar with the wide array of rates, products, and services designed for these customers; and maintain 13

and leverage strategic relationships with many of our larger customers. Engaging these customers is 14

essential to meeting state and federal energy policy goals as described above and in Volume 1 of this 15

Exhibit because non-residential customers—while comprising only about 294,000 customers 16

representing 683,000 service accounts—account for approximately 66 percent of the electricity 17

delivered over SCE’s distribution system. 18

In this Chapter, we describe the functions performed by BCD, describe the Base Year activities, 19

analyze the historical O&M expenses, and forecast the Test Year O&M expenses. As described in 20

Chapter I, beginning in the Base Year, we have reviewed and, where possible, optimized the way in 21

which we deliver our services to non-residential customers. In this Chapter, we describe the impact of 22

these actions on our Test Year forecast. We also present forecast capital expenditures for our Energy 23

Education Centers and specialized equipment used by BCD engineers and test personnel. Finally, the 24

forecast of Other Operating Revenues managed by BCD is described in this Chapter. 25

A. Description of Business Customer Division Activities 26

Business Customer Division Activities comprise an array of activities performed by SCE’s 27

Business Customer Division, including Account Management Services, Technical Services, Energy 28

Education Centers, Economic Development Services, Consumer Choice Services, and related support 29

9

activities. These activities are described in additional detail below. Costs associated with these 1

activities are recorded in FERC Account 908.600.4 2

1. Account Management Services 3

Account Management Services provides service and information to the 294,000 non-4

residential customers associated with 683,000 non-residential service accounts. The information 5

provided involves utility and energy-related matters that have financial and/or operational impacts on 6

our customers’ businesses. Approximately 3,600 customers representing 158,000 service accounts are 7

assigned a senior account manager or account manager because they are highly engaged in demand-side 8

management activities and encounter a higher degree of rate, metering, and billing complexities. These 9

assigned account managers are segmented according to industry, and where feasible, are located in SCE 10

facilities near the majority of their customers. These assigned customers account for approximately 44 11

percent of the electricity delivered over the SCE distribution system.5 The services and information 12

provided by the Account Management Services function are described in more detail below. 13

a) Descriptions of Account Management Services Activities 14

Account Management Services Activities consist of providing information and 15

account services to about 294,000 non-residential customers representing 683,000 service accounts, 16

including day-to-day responses to customer service needs on billing, tariffs, outages, distribution service 17

requirements, and other issues. Account managers also provide marketplace education, promotion and 18

delivery of demand response programs, and assistance in understanding and assessing the feasibility of 19

distributed generation. The Account Management Services function also assists customers with 20

identifying and implementing energy efficiency measures. The costs of these activities are charged to 21

energy efficiency programs and collected through the Public Goods Charge and are not included in this 22

General Rate Case request. 23

Account Management Services assigns resources as shown in Table III-3 below. 24

For medium and large customers, account managers are assigned to a designated group of customers and 25

4 In prior rate cases, activities described in the Business Customer Care section were presented separately in FERC

Accounts 903.700 (Customer Choice Services), 908.600 (Account Management), 906.610 (Energy Centers), 908.620 (Technical Services), and 908.630 (Economic Development Services). In this rate case, SCE has combined these activities into a single FERC account, consistent with how these activities are managed, in order to reduce the volume of O&M workpapers. Detailed descriptions are presented in this Volume consistent with our practice in prior General Rate Cases.

5 See workpaper entitled “SCE Customers, Accounts, Usage, and Revenue Summary By Account Description.”

10

serve as the first point of contact for customer communications and information. This communication is 1

made through educational mailings, faxes, e-mail, and in-person meetings and presentations. 2

These assigned customers are medium or large commercial and industrial 3

businesses or government and institutional entities. These customers include large retailers, property 4

owners and managers of office buildings, regional cold storage facilities, pharmaceutical firms, cement 5

companies, aerospace manufacturers, hospitals, schools, colleges and universities, and local, state and 6

federal governments, among others. These 3,600 assigned customers representing 158,000 service 7

accounts represent approximately 44 percent of the electricity delivered by SCE annually. 8

Customers are assigned to account managers based on several factors, including 9

IDSM activity and potential, complexity of rates, service arrangements involving customer substations 10

or advanced metering or interconnection requirements, geographical location, and type of industry. 11

Within market segments, the assignment of specific customers to account 12

managers is based on business and electric service complexity, with the most complex customers being 13

assigned to more experienced account managers. SCE’s practice is for newly hired account managers to 14

undergo four to six months of training before being assigned to specific customers. This training period 15

includes both classroom instruction and opportunities to work side-by-side with experienced account 16

managers and field engineers. This allows the knowledge transfer with existing personnel on customer-17

specific information and has resulted in providing customers with more knowledgeable and proficient 18

account managers who are then able to provide better service and more accurate and timely information. 19

To effectively match service delivery to customer needs, SCE established a mid-20

market account management team to provide service to medium and large customers who do not 21

extensively participate in IDSM activities but continue to have complex customer service needs. For 22

example, medium and large customers with service accounts with demand of 200 kW or greater are 23

required to default to Critical Peak Pricing (CPP) or select another rate and may have additional needs 24

for information and assistance as a result of the transition to mandatory Time-of-Use (TOU) rates. 25

These customers want to better understand how the CPP rate works and want to determine if it meets 26

their needs or if there are other rate options that might better meet their needs. Many demand response 27

programs and rates are targeted to these customers, such as the Base Interruptible Program (BIP), 28

Capacity Bidding Program (CBP), and Demand Bidding Program (DBP). 29

The mid-market account management team combines certain aspects of the 30

existing account management structure for larger customers with optimized delivery methods to cost-31

11

effectively meet the needs of their customers. The mid-market account managers provide customer care 1

to mid-market customers through SCE.com and targeted marketing materials and then engage these 2

customers by phone, e-mail, and mail whenever possible, using targeted face-to-face interactions based 3

on customer needs. 4

SCE also established the Business Solutions organization to provide service to 5

small to medium customers. These customers typically require limited customer care engagement and 6

have less complex rates and lower complexity in terms of business operations and energy needs. 7

Business Solutions account managers contact these customers by phone, e-mail, mail, and fax to 8

communicate rate changes, discuss the availability of optional rates and demand response programs, and 9

assist these customers with other questions or concerns. Business Solutions leverages customer specific 10

mailings and e-mail to introduce customers to their new account manager and to help them better 11

understand the programs and services available for their participation. 12

To support the activities of the account managers in the mid-market team within 13

Business Solutions, SCE established the Integrated Demand Side Management (IDSM) specialist team, 14

a group of technical experts assigned to provide customer care for specific IDSM opportunities. These 15

specialists do not have assigned customers in the traditional sense, but, when customers need assistance 16

with energy audits or specific energy efficiency projects, these specialists provide technical assistance, 17

while the mid-market and Business Solutions account managers continue to handle other customer care 18

needs. 19

BCD also has a group of account managers that use mass-market customer 20

outreach through ethnic, faith-based and community forums, special business events, energy walks, 21

strategic business organizations, and organized signature events in order to effectively reach our 22

customers.23

12

Table III-3 Account Management Resource Assignments

Line No.

Basis of AssignmentTypical Account Manager Assignment

Examples Typical Issues

(~ 1,000 customers / ~ 55,000 service accounts)

2(~ 2,000 customers / ~ 110,000 service accounts)

3


4


5


Commercial customers and small to medium industrial customers

Bills, rates, power quality, economic development, outage communications, and demand response programs

Small to medium businesses that require limited customer care engagement through virtual channels

600-1,000 customers, 2,500 - 3,000 service accounts

Small and medium commercial and industrial customers

Bills, rates, economic development, outage communications, and demand response programs

Self-generation, Rule 18 sub-metering issues, requests for sub-transmission service, interruptible rates, service reliability, economic development, outage communications, power quality, environmental compliance, and demand response programs

Mid-Market Account Manager

Business Solutions Account Manager

Business Solutions Account Managers

Account Manager Large and medium businesses highly engaged in IDSM activities, complex business operations, but with less complex customer care issues, and less complex billing and metering requirements

40-110 customers, 250-3,000 service accounts

Fabricated metals, school districts, agricultural water agencies, large office buildings, medium retail chains, medium manufacturers, and regional cold storage facilities

Bills, rates, power quality, economic development, outage communications, and demand response programs

Medium and large businesses with less complex operations and fewer service accounts that require moderate customer care engagement through virtual or telephone-based interactions

Senior Account Manager

Unassigned small customers whose customer service needs can be met primarily through the Customer Contact Center

Unassigned Small and many medium businesses

Bills and rates, with much of the focus on reducing bills


Resource

1 Large and medium businesses highly engaged in IDSM activities, complex business operations, significant customer care, and complex billing and metering requirements


Federal, state, counties, and, cities, national retail chains, large manufacturers (including steel and cement), large hospitals and colleges

13

(1) Rate Analysis Information and Education 1

Approximately 135, or nearly 70 percent, of SCE’s electric rates apply to 2

the non-residential customers served by BCD, so these customers have a wide range of rate and billing 3

options from which to choose to best meet their business needs.6 Most demand response programs and 4

rates currently apply only to non-residential customers, with particular emphasis on agricultural 5

accounts and other non-residential service accounts with over 200 kW in energy demand. It is important 6

to assist these customers in understanding the impact that various rate options may have on their 7

operations and to help them make informed decisions about their energy usage, costs, and rate choices. 8

Although many commercial and industrial customers receive electric service on general service or basic 9

agricultural rates, customers who have accounts with demand of 200 kW and above are required to be 10

served on TOU rates. These customers also have a greater number of rate options and variations. With 11

the installation of ESC meters and the availability of 15-minute interval data, all non-residential 12

customers with at least 12 months of billing history after their ESC meter was installed will be required 13

to be served on TOU rates beginning in 2014. These customers will also be able to participate in a 14

wider range of demand response programs. SCE expects these non-residential customers with demands 15

under 200 kW will have questions and many of the same needs as those customers with demands 16

between 200-499 kW in 2009, when interval meters were deployed and TOU rates first became 17

mandatory for those customers. The numerous rate options, rate complexities, and changing rate 18

structures require SCE’s account managers to provide timely, ongoing communications, and rate 19

analysis information to meet the needs of our non-residential customers. 20

TOU rate options are designed to provide more accurate price signals to 21

enable customers to reduce or shift energy usage to lower-demand times of day. As a result of 22

implementing these time-differentiated rates and because of related billing factors such as facility-23

related and time-related demand charges, customers increasingly request assistance from their account 24

managers to better understand time-related energy usage concepts and how applicable rate schedules 25

may work within their operations. For example, customers with over 200 kW of demand may choose to 26

participate in demand response programs or rate options such as Real Time Pricing (RTP), Summer 27

Advantage Incentive (also known as Critical Peak Pricing or CPP), the Base Interruptible Program, the 28

Demand Bidding Program, or the Capacity Bidding Program, as well as various TOU seasonal options. 29

6 See workpapers for a list of SCE tariff schedules organized by customer sector.

14

With the full deployment of ESC meters, customers with service accounts with demands below 200 kW 1

now have access to the same demand response programs and rate options as larger customers. 2

Customers continually and increasingly rely on their account managers to 3

provide consultation and detailed rate analysis information, so they have the necessary information to 4

select the rate and program options optimally suited to their operations, and so they can better 5

understand the differences in rate and program benefits based on their energy usage. In most cases, 6

account managers are able to help customers make decisions by conducting account energy usage 7

reviews and by explaining tariff requirements and other factors, such as firm service levels and voltage 8

levels. In other cases, more complex rate analyses are performed as part of the Technical Services 9

function to give customers a more detailed, unbiased view of their rate options for business decision-10

making purposes. BCD’s Technical Services function is described below in Section III.A.2. 11

(2) Billing and Metering Inquiries 12

Billing and metering questions frequently arise for midsize and larger 13

customers. These questions are due in part to the variety of available metering, billing, rate options, and 14

programs for these customers. Most issues concerning metering options are generally identified in the 15

billing process. When billing and metering issues arise for non-residential customers, the process of 16

investigating and resolving issues is often time- and labor-intensive and cannot be effectively conducted 17

by a Customer Contact Center or field service representative. SCE account managers assist customers 18

with issues involving energy charges, usage calculations, billing factors, metering operations and 19

accuracy, and meter reads by initiating investigations and coordinating issue resolution. 20

Midsized and larger customers are generally more knowledable about 21

energy issues and are readily able to identify the impact of rate changes and increases on their 22

businesses. For example, one of SCE’s larger customers has over 20,000 service accounts. Due in part 23

to the proactive steps taken by BCD’s account management team, this customer has aggressively 24

pursued cost-effective rates, adopted energy efficiency measures, and participated in demand response 25

opportunities. In addition, most of this customer’s service accounts use electronic data interchange for 26

easier bill management and payment. 27

(3) Credit Issue Information 28

When credit issues emerge for non-residential customers, SCE’s credit 29

administrators and financial analysts depend on account managers to facilitate communications with 30

customer decision makers and provide specific knowledge of the customer to help make determinations 31

15

on credit issues and the appropriate actions to be employed. Account managers also serve as key 1

contacts for educating customers on the rules surrounding credit policies and the need to keep accounts 2

in good standing, negotiating deposits and financial security arrangements with financial decision 3

makers, and helping customers understand payment terms in order to ensure their business operations 4

are not adversely impacted. 5

SCE’s credit administrators may request assistance from account 6

managers in resolving credit issues, such as communicating changes in customer account status, 7

resulting in security deposit or collateral requirements, or assisting with negotiations to recover amounts 8

in arrears. Because of their ongoing relationships with customers, account managers have proven 9

effective in interacting with our customers’ senior financial officers to explain late payment charges, 10

security deposits, and other issues related to financial risk, and with assisting in developing solutions in 11

these situations. For example, in 2012, an account manager worked closely with SCE’s credit 12

organization in negotiating payment terms with a local medical facility to resolve an arrears balance in 13

excess of $200,000. Because of the strong working relationship between the account manager and the 14

customer, the hospital offered payment arrangements to pay off the arrears within 180 days. 15

Additionally, the hospital agreed to pay its electricity bills from SCE on a weekly basis going forward. 16

(4) Power Quality Information 17

In today’s digital age, it is increasingly important for customers to receive 18

dependable, reliable electricity service. Computerized controls are more sensitive than conventional 19

electro-mechanically controlled equipment. Generally, power quality problems tend to occur on the 20

customer side of the meter. Nevertheless, the customer often looks to SCE first to determine whether 21

the problem resides in SCE’s distribution system. The account manager can initiate and coordinate an 22

analysis of the power quality delivered to the customer and can help solve any problems discovered 23

from that analysis, whether the problem lies with SCE’s equipment or the customer’s equipment. 24

For example, in 2012, a circuit board manufacturer contacted its BCD 25

account manager about slight variations in electric service impacting its operations due to its production 26

equipment’s extreme sensitivity to power and voltage disturbances. Whenever a disturbance occurred, 27

the customer would incur significant quantities of damaged and unusable product. Frustrated by the 28

issue, the customer engaged the account manager, who partnered with the appropriate engineers and 29

transmission and distribution experts to help identify the problem. After performing a series of tests and 30

monitoring the production equipment, the team determined the disturbances were occurring sporadically 31

16

for microsecond durations and could not be eliminated from SCE’s distribution system. The engineers 1

recommended solutions to mitigate the problem, and the account manager worked with the customer to 2

help the customer understand the results of the tests and the potential options. 3

(5) Energy Advisor / Marketplace Communication 4

Account Management Activities focus on providing important and timely 5

information on a wide range of energy-related issues to assist customers in making informed energy-6

related business decisions. Larger customers with assigned account managers often employ “in-house” 7

energy managers or skilled personnel specifically designated to address energy-related issues. These 8

customers tend to be more knowledgeable about energy usage, require more frequent updates on the 9

energy marketplace, and want detailed information about energy supply-and-demand issues, forecast 10

reserve margins, and the impacts of regulatory proceedings and decisions. For these customers, as well 11

as those without in-house energy managers, SCE develops and delivers information at regular intervals 12

to address these concerns. These types of services will become increasingly important as all smaller 13

non-residential customers transition to mandatory TOU rates and begin to experience different rate 14

options. These publications and informational materials are produced within BCD’s Technical Services 15

organization and are discussed further in Section III.A.2. 16

(6) Demand Response Information 17

As outlined in the state’s Energy Action Plan II adopted by the California 18

Public Utilities Commission and the California Energy Commission, energy efficiency and demand 19

response have the highest priority in the loading order to meet increased electrical demands, ahead of 20

traditional generation or supply resources. 21

SCE’s demand response programs have undergone significant changes in 22

the past few years, including the Critical Peak Pricing program, Summer Discount Plan, Capacity 23

Bidding Program, Automated Demand Response, Aggregator Managed Portfolio program, Technical 24

Assistance and Technology Incentives, the Base Interruptible Program and Demand Bidding Program. 25

To increase customer engagement in these programs, it is necessary for account managers to receive 26

training and be equipped with up-to-date program materials, fact sheets, case studies, and rate analyses. 27

Specially developed seminars delivered by BCD employees familiarize customers with new programs 28

and changes to existing programs and help them better evaluate and understand how available programs 29

and technologies apply to their operations. Account managers make on-site customer visits to explain 30

17

demand response programs, conduct site evaluations to identify potential benefits to operations, and 1

answer customer questions. 2

Soon after new demand response programs are launched or changes are 3

made to existing programs, account managers receive training and then contact eligible customers to 4

explain program features, assist with evaluating which program options may best serve their operational 5

needs, and identify potential load reduction strategies. Rate analyses help customers identify possible 6

energy cost savings and help communicate these changes, as well as the excess energy charges or 7

penalties customers may incur if committed program load reductions are not achieved. 8

(7) Outage Communications 9

One of the most important and valued services SCE provides to its 10

customers is critical communication during planned and unplanned power outages. When an unplanned 11

outage occurs, non-residential customers often contact SCE’s Customer Contact Center or their account 12

managers with questions about the outage and restoration status. Non-residential customers receive 13

automated messages for both planned and unplanned outages that provide the estimated restoration time 14

and the status of the outage. The outage communications team provides follow-up e-mails to customers 15

as the status of the outage changes. 16

Coordinated planned and unplanned outage information is critical because 17

non-residential customers may need to alter production or work schedules or send employees or students 18

home for the duration of the outage. 19

The BCD outage communications team communicates thousands of events 20

and updates each month. Half of the nearly 25,000 planned outages in 2012 impacted non-residential 21

customers with assigned account managers. With the implementation of SCE’s automated outage 22

notification system, SCE was able to expand the number of electronic notifications sent to customers 23

with over 700,000 electronic outage notifications delivered in 2012. SCE also increased the planned 24

outage notification lead time to 10 days from the previous three to five day notification lead time. 25

Because SCE provides updates, reschedule information, and outage information, customers can better 26

plan the actions they need to take during an outage. Customers rely on this level of service to ensure 27

they receive the accurate and timely information necessary to meet their business needs. BCD’s outage 28

communications efforts will be impacted over the next few years as a result of a forecasted increase in 29

distribution equipment maintenance activities due to SCE’s aging infrastructure. To help customers, 30

BCD will increase its focus on before- and after-outage customer care. This outreach will include phone 31

18

calls to assigned customers at the time a planned maintenance outage is scheduled to help ensure the 1

customer is prepared for the event and follow-up calls to customers who have experienced a planned 2

maintenance outage to help ensure that power was fully restored. Outage schools are another form of 3

customer outreach that provides information to media representatives, customers, and employees about 4

SCE’s processes for planned and unplanned outages. Outage schools provide insights into why 5

planned/maintenance outages are essential to a healthy infrastructure, how we keep customers informed 6

of the status of outages, and our commitment to safe, reliable power. 7

BCD is also responsible for reviewing new service accounts to identify 8

those customers who provide essential use services. In addition, BCD coordinates the annual 9

recertification process to confirm the continued eligibility of existing essential use customers. Essential 10

use customers are those non-residential customers who provide essential public health, safety, and 11

security services. Circuits serving essential use customers who either do not have adequate back-up 12

generation or are within a category that is exempt regardless of the status of back-up generation (i.e., 13

hospitals and skilled nursing facilities) are exempt from rotating outages. 14

(8) Plug-In Electric Vehicle Support 15

BCD, in coordination with SCE’s Transportation Electrification group, 16

assists non-residential customers who express interest in building commercial or public charging 17

stations. PEV-related activities include providing basic and more complex PEV information and 18

performing customer requested rate analyses. 19

(9) Customer Relationship Management System 20

The Customer Relationship Management (CRM) function uses an 21

automated system to manage customer-related information for improved customer service. This 22

information management system enables BCD to provide consistent documentation, tracking, and 23

delivery of customer communications. The CRM system establishes a platform for IDSM program 24

managers, account managers, and other Customer Service employees to manage workflow, fulfill IDSM 25

requests, and sort and categorize customer contact attributes in order to expedite the delivery of 26

outbound customer education and information materials. CRM is the central repository for IDSM-27

related interactions and integrates with our on-line audit functionality. The CRM system contains 28

customer names, addresses, and other information, which helps BCD comply with required customer 29

notifications about rates and programs when directed to do so by the Commission and helps maintain 30

records of which customers were notified. This record-keeping includes copies of all correspondence, 31

19

interactions, and analyses, and enables BCD personnel to quickly respond to customer inquiries and 1

requests for information. In addition, in late 2013, the CRM system will be enhanced to improve the 2

efficiency and information flow among customer service stakeholders involved in customer care and 3

IDSM activities for non-residential customers. 4

b) Account Management Services Base Year Operating Results 5

As shown in Table III-4, in 2012, SCE recorded a total of $12.500 million in 6

O&M expenses for the Account Management Services Activities described above with recorded labor 7

expenses of $9.963 million and non-labor expenses of $2.537 million. 8

c) Analysis of Historical Data 9

The recorded/adjusted costs for Account Management Services Activities, as 10

shown in Table III-5, were derived after analyzing recorded costs for these activities and adjusting them 11

to reflect ongoing business operations. The various accounting, operational, and reclassification 12

adjustments are discussed in the workpapers supporting this Volume. In addition, the ratemaking 13

adjustments are discussed in Exhibit SCE-10 Results of Operations testimony. 14

Table III-4 Account Management

Recorded/Adjusted Expenses (2008-2012) (Constant 2012 $000)

Line No.

Account Management 2008 2009 2010 2011 2012

1 Labor Expense 11,919 12,130 11,371 11,072 9,963 2 Non-Labor Expense 3,822 4,111 4,439 4,145 2,537 3 Other - - - - - 4 Total Operation Expense 15,741 16,241 15,810 15,216 12,500

In 2009, the operating expenses for Account Management Services Activities 15

increased over 2008 due to an increase in labor associated with the formation of the Business Solutions 16

group and a non-labor increase for ongoing technology support costs for a forecasting tool utilized for 17

customer projects. Non-labor costs also increased for employee training and professional development 18

and for costs supporting the development of standardized account management processes to better 19

facilitate tracking and forecasting of customer projects. In conjunction with the formation of the 20

Business Solutions group, non-labor costs increased in 2009 associated with employee training and 21

professional development activities. 22

20

The operating expenses for the Account Management Services Activities function 1

have declined since 2009. From 2009 through 2011, labor costs decreased as a result of a shift in the 2

allocation of labor expenses from O&M activities to energy efficiency program activities, a reduction of 3

positions, and employee retirements. In 2010, non-labor expenses increased in conjunction with 4

employee training and professional development, and onboarding expenses associated with the 5

formation of the Business Solutions group. Since 2010, however, non-labor expenses have declined due 6

to a reduction in operational support costs, employee-related expenses, and the completion of the 7

onboarding and training efforts associated with the formation of the Business Solutions group. 8

Beginning in 2012, BCD began implementing a number of productivity measures, 9

including consolidating account management support activities and reducing employee meeting and 10

travel expenses by increasing the use of audio and video conferencing, as well as the use of web-enabled 11

meetings. As a result of these initiatives, in 2012, BCD reduced the number of account management 12

support labor resources, resulting in a decrease in labor costs of $1.109 million compared to 2011. In 13

parallel with this reduction in labor expenses, in 2012, employee-related expenses, contract, and 14

operational support expenses were also reduced, resulting in a reduction in non-labor expenses of $1.608 15

million compared to 2011. 16

d) Test Year Expectations 17

SCE expects the business climate in California to continue to be challenging for 18

customers who are facing issues ranging from increased operating costs and regulatory mandates, such 19

as AB 32, which requires California to reduce its greenhouse gas (GHG) emissions to 1990 levels by the 20

year 2020 and will impact customers differently based on the amount of revenue that is returned to them 21

from the cap-and-trade program through their utility bills. In parallel with these challenges, SCE 22

expects that non-residential customers will face increasingly complex utility issues, including new 23

complex rates, rate options, and programs. For example, in January 2016, SCE will begin defaulting 24

non-residential customers with demands less than 200 kW to CPP in accordance with D.13-03-031. 25

SCE plans to conduct a number of activities to inform these customers of their choices and to help them 26

take advantage of the new rates. In the section below, we discuss specific account management support 27

activity adjustments. These adjustments are included in the overall forecast for BCD presented in 28

Section III.C.2 below. 29

21

(1) Optimizing Account Management Support Activities Will Result in 1

Reduced Account Management Cost 2

In 2013, BCD began a process of consolidating and optimizing its account 3

management support services functions to provide more effective support across the account 4

management organization. BCD was able to reduce labor costs in several areas, including management 5

and administrative support, project management services, and employee training and professional 6

development. BCD was also able to reduce non-labor costs by reducing or eliminating various customer 7

events and reducing employee meeting and travel expenses by increasing the use of audio and video 8

conferencing and web-enabled meetings. In addition, BCD reduced some account management costs by 9

more effectively aligning the services provided to the needs of customers and increasing the use of more 10

cost-effective delivery channels. Prior to 2012, BCD assigned account managers to non-residential 11

customers based primarily on customer size. We found, however, that some larger customers did not 12

necessarily require the services of an account manager. In 2012, BCD optimized the way in which we 13

serve some customers to more effectively offer the right types of programs and services at the right time 14

and through the right delivery methods, while leveraging technology to make account management more 15

streamlined and cost-effective, yet still provide customers a high-quality customer care experience. For 16

this customer engagement approach, instead of assigning customer account management resources based 17

primarily on customer size, we assigned these resources based on service needs, demand-side 18

management potential, and other customer-specific factors. This allowed BCD to lower some costs by 19

identifying about 1,000 customers who could be transitioned from being assigned to senior account 20

managers to mid-market account managers. As explained earlier in this testimony, mid-market account 21

managers provide customer care utilizing intelligent delivery channels, such as SCE.com, targeted 22

marketing materials, telephone, e-mail, and direct mail. 23

While SCE anticipates a number of challenges in addressing both existing 24

and emerging customer concerns and service needs, SCE also expects to be able to continue to reduce 25

costs and forecasts a reduction of $1.402 million in Account Management Services Activities costs by 26

further improving efficiencies in account management support activities and by more reliance on cost-27

effective, intelligent delivery channels. 28

(2) Customer Growth 29

SCE customer growth is expected to increase by 2.06 percent from 2012 30

to 2015, resulting in a $258,000 increase in costs. The Account Management Services function is 31

22

directly impacted by this expansion, as this represents an increase in the number of customers requiring 1

account management services. 2

2. Technical Services 3

a) Descriptions of the Technical Services Activities 4

The Account Management Services function is supported by a number of 5

activities that provide a higher level of technical and specialized expertise than exists within our front 6

line account management organization. The Technical Services organization described below provides 7

much of this expertise. 8

(1) Rate and Data Analysis Services 9

BCD’s rate analysis team supports the account management function by 10

performing rate analyses for individual customers and by comparing multiple complex rate options for 11

large groups of customers impacted by changes in rates or demand response rate options. Technical 12

Services also constructs rate models and load aggregation models to compare proposed rates to existing 13

rates and to compare bill impacts on individual service accounts or groups of service accounts on 14

multiple proposed rates at the same time. 15

When requested, Technical Services provides cities with city-wide usage 16

data and reports in compliance with Rate Schedule CCA-INFO. Cities use this information in a variety 17

of ways, ranging from exploring Community Choice Aggregation (CCA), to quantifying their existing 18

carbon footprints as first steps toward greenhouse gas reductions, to developing baseline energy usage 19

levels for their strategic planning efforts and participation in energy efficiency partnerships and 20

initiatives. 21

(2) Field Engineering Services 22

The engineers and technical specialists within Technical Services provide 23

support to customers through on-site visits and evaluations at customer facilities, recommendations 24

regarding energy and technology solutions, and assistance with energy and cost calculations for 25

customers considering equipment or operational changes. These engineers provide assistance in more 26

complex technical situations that may exceed the account manager’s level of expertise. Field engineers 27

routinely provide cost and savings estimates for larger-scale, multi-measure, or multi-site projects 28

involving equipment replacement and/or operational changes, combined with information on various 29

rate and demand response program options, to give customers the information they need to make 30

informed decisions about their electrical service and usage. 31

23

(3) Special Contract and Tariff Administration Services 1

Special contract and tariff administration activities involve preparing, 2

monitoring, and managing special contracts, including certain special contract rates, standby rates, and 3

assessment of departing load charges. Because of the complex and technical nature of these contracts, 4

specialized support to account managers is necessary so that all technical, economic, and regulatory 5

issues are properly considered and addressed. 6

(4) Education and Communications 7

Technical Services monitors and determines the potential customer 8

impacts of key regulatory and legislative proposals and evaluates the impacts on participating and non-9

participating customers. Based on the impacts, Technical Services facilitates the development of 10

internal and external education and communication materials and targets delivery of those materials to 11

the appropriate audiences. This work involves creating materials that address tariff and rule revisions, 12

bill impacts, customer marketplace information, regulatory and legislative information, new rates or 13

demand response programs, or regulatory decisions that affect direct access rules or procedures. 14

(5) Customer Requests for Assistance with Distributed Generation 15

Projects 16

Customers continue to express interest in self-generation and distributed 17

generation, especially photovoltaic systems. Technical Services provides customers with detailed 18

information and analyses to help customers evaluate the cost-effectiveness and feasibility of self-19

generation projects, so they will be able to make informed decisions about whether these projects may 20

reduce their operating costs or achieve other environmental or societal objectives. The majority of 21

information provided to customers pertains to utility tariffs, rates, customer load and usage profiles, 22

utility and Commission policies, and potential incentives. In addition, Technical Services may also 23

provide other information—such as economic factors, analysis methods, and equipment 24

characteristics—to assist customers in understanding the feasibility of proposed projects. 25

Customers must also be informed and educated about charges established 26

to recover departing load obligations and other non-bypassable charges that are the obligations of 27

customers participating in self-generation and distributed generation. Customers rely on SCE for 28

estimates of these costs because they affect overall project economics. While the ultimate decision 29

whether or not to proceed with a project rests with the customer, SCE’s economic analysis of projects 30

provides the customer with a basis for decision-making. When a customer decides to proceed with a 31

24

project, SCE assists the customer with interconnection, metering, and, if applicable, standby rate 1

administration. 2

b) Technical Services Base Year Operating Results 3

(1) Rate Analysis Services 4

Rate analysis activity for the 2008-2012 period is summarized in Table 5

III-5. These analyses reflect a wide range of studies ranging from complex, ad hoc analyses in response 6

to individual customer requests to proactive rate impact analyses similar to the examples listed below, 7

which were performed in 2012: 8

1. Identification of service accounts that would benefit from TOU rates 9

as a result of the deployment of ESC meters, and 10

2. An annual review of accounts on the Base Interruptible Program and 11

Agricultural and Pumping Interruptible program to determine the 12

potential annual bill impact of the various rate options available to 13

these customers. 14

During the 2008-2012 period, SCE performed an average of 15

approximately 95,300 rate analyses each year at the request of customers. Additional analyses are 16

provided when rates change significantly due to higher natural gas costs and when adjustments are made 17

in rate design, particularly as part of SCE’s GRC Phase 2 proceedings as in 2009.7 Account managers 18

use these rate analyses to help customers select their most beneficial rate options. A significant increase 19

in customer requests for rate analyses and communications occurred in 2009 as a result of SCE’s 2009 20

GRC Phase 2 proceeding (D.09-08-028), which implemented default CPP rates for customers with 21

demand over 200 kW, and the 2009-2011 demand response proceeding (D.09-08-027), which made 22

multiple changes to demand response program eligibility. SCE expects that rate analysis activities will 23

increase in 2013 as a result of the decision in our 2012 GRC Phase 2 proceeding (D.13-03-031) and will 24

continue to increase as remaining non-residential customers are transitioned to mandatory TOU rates in 25

2014 and defaulted to Critical Peak Pricing in 2016. As customers face these rate changes, they want to 26

better understand their usage patterns, as well as the potential cost impacts of making choices to shift 27

operations to maximize the benefits of dynamic pricing rates and demand response programs. 28

7 Note that, due to the delay in the decision for SCE’s 2012 GRC Phase 2 application, the number of rate analyses

performed in 2012 does not reflect the expected increase in rate analysis activity that SCE usually performs in its GRC Test Year.

25

Due to the minimal changes in rate factors and rate structures in 2012, the 1

mass rate analyses performed were significantly lower than in typical years. In a typical year when the 2

Energy Resource Recovery Account (ERRA), General Rate Case and other rate factor changes impact 3

customer service accounts, SCE expects to perform mass bill impact analyses for all 683,000 non-4

residential service accounts. In early 2013, with the implementation of GRC Phase 1, GRC Phase 2, and 5

ERRA in 2013, SCE experienced a significant increase in mass bill impact analyses and expects to 6

complete approximately 1.3 million bill impact analyses by year end. 7

Finally, in 2012, the Technical Services organization assumed 8

responsibility for implementing and updating the online rate calculation analysis tool, which enables 9

customers to view their costs on their current rate against cost comparison scenarios if they were to 10

choose to switch to another applicable rate option. 11

Table III-5 Rate Analyses Performed for Non-Residential Customers by Year

Rate Comparison Reports

Bill Impacts Reports

1 2008 93,000 11,000 175,000 279,0002 2009 121,000 56,000 355,000 532,0003 2010 108,000 90,000 445,000 643,0004 2011 73,000 23,000 203,000 299,0005 2012 92,000 14,000 - 106,000

Line No. Year Customer

Requested Rate Analyses

Proactive Reports (Mass)Overall Total

(2) Customer Requests for Assistance with Distributed Generation 12

Projects 13

In 2012, Technical Services completed 93 engineering economic analyses 14

for customers considering self-generation projects. The projects reviewed ranged in size from 15 kW to 15

100 MW and varied in complexity by the type of technology and the customer-specific application and 16

operating conditions. The projects included a variety of technologies such as solar, wind, fuel cells, and 17

combined heat and power applications.8 18

8 See workpapers summarizing the number of customer distributed generation projects reviewed by Technical Services.

26

(3) Other Technical Services Activities 1

The Technical Services organization also supports account management 2

customer education, training, and consulting efforts, described in Section III.A.1 above, by developing 3

and hosting the Electricity Outlook customer information and education seminars at various locations 4

throughout our service territory, and by assisting in the development of other BCD publications.9 5

The SCE Power Bulletin and the SCE Business Connection Newsletter are 6

publications designed to provide timely information to non-residential customers about marketplace 7

issues, rates, tariffs, programs, products, and services.10 These publications are delivered to customers 8

through the U.S. mail and e-mail and are available online. The newsletters announce changes in 9

programs and rates, provide general information about SCE’s business, and refer customers to account 10

managers and online resources for more detailed information. During regular face-to-face meetings with 11

customers, account managers can review and reinforce the information contained in these publications. 12

Electricity Outlook information and education seminars are marketplace 13

updates organized to provide in-person presentations to groups of non-residential customers. These 14

forums are held twice a year at multiple locations throughout our service territory and have been well-15

received. Electricity Outlook seminars are conducted at SCE facilities or regional meeting locations and 16

combine regulatory, legislative, and rate updates with information about new utility programs and rates, 17

as well as updates on the availability, benefits, and incentives of various programs. 18


The recorded/adjusted costs for Technical Services Activities shown in Table III-20

6 were derived after analyzing recorded costs for the activities and adjusting them to reflect ongoing 21

business operations. 22

9 See workpapers for an example of an Electricity Outlook presentation.

10 See workpapers for examples of the SCE Power Bulletin and the SCE Business Connection Newsletter publications.

27

Table III-6 Technical Services


Line No.

Technical Services 2008 2009 2010 2011 2012

1 Labor Expense 2,832 3,010 3,675 3,919 3,482 2 Non-Labor Expense 699 842 904 615 440 3 Other - - - - - 4 Total Operation Expense 3,531 3,852 4,579 4,534 3,922

Labor expenses in the Technical Services Activities increased in 2009 due to 1

filling vacancies in the rate analysis and field engineering organizations and due to increased Energy 2

Related Services (ERS) project development activities.11 During this same period, non-labor costs 3

increased by $143,000 due to an increase in employee training and professional development and market 4

intelligence costs to support demand response marketing efforts by the account management 5

organization. 6

In 2010, SCE increased staffing in Technical Services to oversee expanded 7

customer communications activities and to assist in the development of ESC-enabled online rate 8

analysis tools. Technical Services also experienced an increase in requests to perform various rate 9

analyses for customers and saw an increase in demand response activities, as well as an increase in the 10

paid time-off factor. As a result, labor costs in this activity increased in 2010 by $665,000. Non-labor 11

costs in 2010 remained relatively stable. 12

In 2011, labor costs remained relatively stable. Non-labor O&M expenses 13

decreased in 2011 by $289,000 due to a combination of a reduction in contract positions supporting 14

SCE’s market intelligence activities and a reduction in employee training and professional development 15

activities. 16

In 2012, labor costs decreased by $437,000 because of a decision to not fill 17

vacancies and a reduction in Energy Related Services project development activities. In 2012, non-labor 18

costs declined by $175,000 because of a reduction in contract labor and employee-related operational 19

costs. 20

11 Energy Related Services is described in Section III.E.4 of this volume.

28

d) Test Year Operating Expectations 1

In the 2015 Test Year, SCE expects to continue to perform Technical Services 2

Activities, as described above, at the same level as the Base Year. Therefore, SCE does not forecast a 3

change in O&M expenses for this activity in the Test Year. 4

3. Energy Education Centers 5

SCE operates two Energy Education Centers (EEC), one in Irwindale and one in Tulare. 6

Both EECs are dedicated to providing residential, commercial, industrial, and agricultural customers 7

with information regarding energy efficiency, demand response, renewable generation, environmental 8

solutions, electric safety, utility programs, electro-magnetic fields, and power quality. The Energy 9

Education Centers are also an essential component of SCE’s Workforce Education and Training 10

(WE&T) efforts. These centers provide customers the ability to view actual equipment in operation 11

while receiving information and education and product and service demonstrations by unbiased 12

technical specialists. The EECs host approximately 33,600 customers each year. 13

Historically, operational expenses for the Energy Education Centers have been jointly 14

funded through Public Goods Charges (PGC) and O&M funding. This funding is consistent with the 15

role of the Energy Education Centers in providing SCE customers with education and training on all 16

available SCE services, as well as providing IDSM—including energy efficiency, demand response, and 17

distributed generation—seminars, demonstrations, and programs. Only the O&M portion of the total 18

operating costs for the Energy Education Centers is included in this GRC application. During this 19

general rate case period, SCE’s Energy Education Centers will require capital funding to meet continued 20

customer demand and to upgrade the facilities, equipment, and capabilities to meet the increased 21

emphasis of the WE&T efforts. The capital forecast for these projects is presented below in Section 22

III.D.2. 23

a) Descriptions of the Energy Education Centers 24

SCE opened its first EEC in Irwindale, California in January 1990 and hosted 25

approximately 23,500 visitors in 2012. SCE opened its second Energy Education Center in Tulare in 26

February 1996. This center serves the customers of the San Joaquin Valley and neighboring areas and 27

hosted approximately 13,700 visitors in 2012. Both facilities offer energy seminars, technology 28

demonstrations, and special events on such varied topics as energy-efficient lighting, daylighting, food 29

service, HVAC, electric safety, and energy management. SCE’s EECs are described further in the 30

following sections. 31

29

(1) SCE Energy Education Center–Irwindale 1

SCE’s Energy Education Center in Irwindale (EEC-Irwindale) is a 51,000 2

square-foot complex that is staffed by technical specialists and support staff who deliver expertise in 3

energy management, energy services, engineering, and customer service. EEC-Irwindale promotes 4

energy conservation, environmental solutions, power quality, sustainable building design, renewable 5

generation, greenhouse gas reduction, and marketplace education through seminars, workshops, 6

displays, technical consultations, demonstrations, and collateral materials. EEC-Irwindale consists of 14 7

facilities as shown in Table III-7 below. These facilities include a conference center that can 8

accommodate over 100 customers and several meeting rooms where educational workshops, seminars, 9

and other events are conducted. 10

(2) SCE Energy Education Center–Tulare 11

SCE’s Energy Education Center in Tulare (EEC-Tulare) is a 32,000 12

square-foot complex located on ten acres and is staffed by technical specialists and support staff with 13

expertise in energy management, energy services, engineering, and customer service. EEC-Tulare also 14

promotes energy conservation, environmental solutions, power quality, sustainable building design, 15

renewable generation, greenhouse gas reduction, and marketplace education through seminars, 16

workshops, displays, technical consultations, demonstrations, and collateral materials. Because EEC-17

Tulare is in such close proximity to the largest agricultural counties in the state (Kern, Tulare, and 18

Fresno), it also employs expertise in agricultural energy efficiency applications. EEC-Tulare consists of 19

nine facilities, some of which are constructed with energy-efficient materials, providing demonstration 20

of energy-efficient construction technologies and applications. EEC-Tulare also has a facility that 21

demonstrates energy-efficient agricultural irrigation technologies. Table III-8 below outlines the 22

facilities at EEC-Tulare. 23

30

Table III-7 Description of SCE’s Energy Education Center – Irwindale Facilities

Line No.

Facility Description of Facility Customer Segment

1. Innovation Center

Compressed air, industrial lighting and daylighting technologies, cool roofs, energy management systems, demand response, window glazing, electric motors and drives, fans and HVAC systems

2. Sustainability CenterSustainable building design and operations, chilled water systems, daylighting, energy-efficient lighting, daylight harvesting

3. Programs and ServicesDisplays on lighting technologies, integrated demand side management, program literature and information

4. Daylight CenterDaylighting and solar responsive lighting/dimming controls, lighting technologies

5.Electro-Magnetic Fields (EMF)/Power Quality

An interactive educational center featuring EMF exhibits and power quality mitigation exhibits

6. Lighting ClassroomDisplays on various energy-efficient lighting technologies and applications, daylight simulator, color booths

7. Computer Lab

Provides computer-based training on SCE’s computer-based energy services such as SCE EnergyManager, demand bidding, and software that supports the Savings By Design program, and building codes and standards

8. Irwindale Conference Center

103-seat capacity, theater-style conference center for events and seminars that showcases state-of-the-art audio-visual equipment and energy-efficient lighting technologies

9. Smart Energy ExperienceInteractive exhibit for smart grid technologies, residential demand response, energy efficiency, sustainable design

Residential and small business

10. Foodservice TechnologyEfficient and environmentally friendly electric cooking and food preparation equipment

Commercial and institutional food service

11. Wet Cleaning DemonstrationEnergy-efficient and environmentally friendly alternatives to the standard method of dry cleaning garments with perchloroethylene (PERC)

Small and medium commercial and industry

trade groups

12.

Solar Photovoltaic Demonstration and Plug-In Electric Vehicle (PEV) Charging Area

Over 2,000 square-foot structure to demonstrate photovoltaic technology. Demonstration also includes the latest PEV charging technology. PEV charging is available to the public. Supports the statewide and SCE solar and EV programs and initiatives

13. Outdoor Demonstrations

Outdoor demonstrations showcase drought tolerant landscaping, outdoor lighting technologies, street lighting, renewable generation (solar, wind), sustainability, and conservation applications

Small, medium, and large commercial and industrial

Residential, small, medium, and large commercial and

industrial

Small, medium, and large commercial and industrial, residential, and agricultural

31

Table III-8 Description of SCE’s Energy Education Center – Tulare Facilities

Line No.

Facility Description of Facility Customer Segment

1. Outdoor Demonstration Area

3.5 acre outdoor demonstration area showcasing pumping and irrigation technologies, outdoor lighting technologies, street lighting, renewable generation (solar, wind), and sustainability and conservation applications

2.Main Exhibit Hall and Information Center

General exhibit area that can host up to 250 customers for energy efficiency seminars and events. Numerous hands on displays and exhibits that support seminars in HVAC, lighting, building codes and standards, programmable logic controls, pumping, motors, and food service. Customer brochures, program calendars, and other collateral material in support of the educational objectives of the EECs

3. Business CenterNine-station computer lab with a technology information library on a variety of energy-related subjects

4. Learning Center A, B, and C

Classrooms equipped with audio-visual capabilities to create an effective learning environment for customers, providing opportunities to share educational materials with offsite locations via video conferencing

5. Professional Lighting Lab

Center for classroom and meeting activities featuring informational lighting exhibits on energy conservation and power outage preparedness. Showcase of cost-effective commercial and retail lighting technologies and demonstration of the value of a lighting management system

6. Annex Building5,000 square-foot facility for classroom and meeting activities with video conferencing capabilities

7. Sustainability Building3,200 square-foot facility for showcase and demonstration of various industrial and commercial technologies and for seminar activities

8.Solar Photovoltaic Demonstration Area

Demonstration of solar photovoltaic (PV) technology. PV demonstration display featuring three different technologies of PV panels to support statewide and SCE solar programs and initiatives

9. Technology Training Center4,880 square-foot building constructed with energy-efficient structural insulated panels (SIP) to serve as a training and exhibit area for HVAC professionals

Small, medium, and large commercial and industrial, and

agricultural

Small, medium, and large commercial and industrial, residential, and agricultural

b) Energy Education Centers Base Year Operating Results 1

In 2012, the EECs conducted multiple sessions of 35 unique O&M funded 2

customer classes on such topics as power quality fundamentals, electrical safety, industrial maintenance, 3

and electrical system analysis. In addition, both EECs conducted 1,284 O&M-funded events attended 4

by a total of 14,251 customers. An additional 404 class sessions were presented on energy efficiency 5

32

topics and were funded through the Public Goods Charge (PGC). These PGC-funded classes are not 1

included in this GRC request. 2

The demand for educational programs and events continues for both EEC-3

Irwindale and EEC-Tulare, particularly for seminars and training on HVAC, programmable logic 4

controllers (PLC), and building envelope technology. To meet this continued demand, SCE constructed 5

an additional 4,800 square-foot facility at EEC-Tulare to support hands-on training, workshops, and 6

working displays for HVAC technicians and upstream market participants, such as engineers, architects, 7

and developers. 8

The EECs evaluate and adjust operations as needed to maintain technological 9

relevance in course offerings, displays, and facilities to keep pace with ongoing market and technology 10

advancements. In 2012, EEC-Irwindale completed upgrades and additions, including the installation of 11

new videoconference equipment and infrastructure improvements in essential customer areas, the 12

installation of a 22 kW solar photovoltaic array/carport parking area along with eight level-2 electric 13

vehicle charging units, and the completion of the buildout of the interactive exhibit showcasing smart 14

grid technologies, demand response, energy efficiency and distributed generation technologies, 15

programs, and services. In 2012, EEC-Tulare completed upgrades and additions, including the 16

installation of 70 kW of solar photovoltaic generation. While these upgrades and additions were capital-17

funded, they support the overall mission of the EECs. 18


The recorded/adjusted costs for the EECs shown in Table III-9 were derived after 20

analyzing recorded costs for these activities and adjusting them to reflect ongoing business operations. 21

Table III-9 Energy Education Centers


Line No.

Energy Education Centers 2008 2009 2010 2011 2012

1 Labor Expense 1,015 998 1,230 842 861 2 Non-Labor Expense 949 1,129 1,119 1,007 470 3 Other - - - - - 4 Total Operation Expense 1,963 2,126 2,349 1,849 1,330

In 2010, labor increased by $233,000 due to personnel added in late 2009 to 22

perform schedule planning, display, and design-related activities. In 2011, labor decreased by $388,000 23

33

because of vacancies that were not filled and employees on temporary work assignments. In 2009, non-1

labor expenses increased $180,000 because of video conferencing costs, demolition expenses related to 2

the customer demonstration center, new products and services, and display and furniture replacement. 3

Non-labor costs decreased in 2011 through 2012 because of the implementation of operations 4

optimization efforts that included an overall reduction in events and supporting expenses and a reduction 5

in employee-related expenses. Part of this reduction in non-labor is a result of the implementation of the 6

EEC’s Event Business Management System (EBMS). This new technology-based customer 7

management interface enables easier online registration for seminars and workshops. It streamlines 8

access to key offerings and enables the integration of web-enabled, on-demand training, resulting in 9

greater efficiencies in event scheduling and training delivery. 10

d) Energy Education Center Test Year Operating Expectations 11

In the 2015 Test Year, SCE expects to continue EEC activities at the same level 12

as the Base Year. As in the Base Year, these activities will include promoting energy conservation, 13

environmental solutions, power quality, sustainable building design, renewable generation, greenhouse 14

gas reduction, and marketplace education through seminars, workshops, displays, demonstrations, and 15

collateral materials. As a result, SCE is not forecasting a change in the O&M expenses for this activity 16

in the Test Year. 17

4. Customer Choice Services 18

The Customer Choice Services (CCS) organization facilitates Energy Service Provider 19

(ESP) and Community Choice Aggregator (CCA) participation in the Direct Access (DA) and potential 20

Community Choice Aggregation markets in the SCE service territory and provides appropriate oversight 21

of ESPs’ and CCAs’ day-to-day interactions with SCE. Both ESPs and CCAs are primarily responsible 22

for procuring and providing for the electric power needs (including ancillary services) of their 23

customers, ensuring resource adequacy and renewable portfolio requirements are met for those 24

customers, and scheduling and settling with the California Independent System Operator (CAISO). 25

Although the Commission suspended DA for new customer enrollment in September 26

2001, Senate Bill (SB) 695 partially re-opened DA in 2009 on a limited basis to retail non-residential 27

customers. In 2010, the Commission issued D.10-03-022 to revise the new rules in accordance with SB 28

695. 29

Community Choice Aggregation was enabled by Assembly Bill (AB) 117, which was 30

signed into law in September 2002, allowing cities, counties, and Joint Power Authorities (JPAs) 31

34

comprised of cities and/or counties, to act as CCAs to purchase and sell electricity on behalf of utility 1

customers within their service area(s). In 2004 and 2005, the Commission issued D.04-12-046 and 2

D.05-12-041, respectively, to implement the rules for the CCA program. 3

a) Description of the Customer Choice Services 4

CCS maintains ongoing business-to-business relationships with ESPs that serve 5

customers in our service territory and with potential CCAs. This SCE-ESP and SCE-CCA business 6

relationship is achieved through an account management approach, similar to our relationships with 7

medium and large non-residential customers who have more complex needs, rates, and service 8

arrangements, whereby a CCS account manager is assigned to each ESP and CCA. These account 9

managers act as a single point of contact and have access to other SCE personnel to resolve service-10

related issues. Because communication and operational issues with ESPs and CCAs differ significantly 11

from those of SCE’s end-use customers, this approach provides services and information tailored to their 12

needs. Responding to information requests and questions from ESPs requires specific knowledge and 13

experience to handle tasks, such as registration of new ESPs, the DA lottery enrollment process, 14

relocations, assignments, switching allowed under the DA suspension rules, and the implementation of 15

processes arising from the ongoing regulatory decisions related to direct access. 16

CCAs have many of the same processes for enrolling and returning individual 17

customers to the utility for bundled service, but they also have a number of different processes due to the 18

“opt-out” nature of a CCA. To facilitate this market, SCE expects to provide services to CCAs similar 19

to those provided to ESPs, serving as the single point of contact for CCA inquiries and day-to-day 20

requests with SCE, maintaining the ongoing business-to-business relationships with prospective and 21

current CCAs, providing customer-related reports to the CCAs, and responding to billing and credit-22

related inquiries once a CCA is in operation. 23

The key functions performed by the CCS organization are Contract Management, 24

Account Management, and Service and Support, as described below. 25

(1) Contract Management 26

The contract management function includes developing and providing 27

information for ESPs and CCAs on how to do business with SCE, facilitating the ESP and CCA 28

enrollment processes, completing the necessary documents and agreements, establishing ESP and CCA 29

contracts and accounts in the SCE system, and providing ongoing administration and contract 30

management. This function also includes compliance testing, data transmission, internal and external 31

35

communications, managing and maintaining the CCS website and internal DA and CCA intranet sites, 1

and updating information provided to ESPs and CCAs in SCE’s territory. CCS’s website is an essential 2

component of daily operations and provides information to these providers. The site contains 3

information such as load factors, distribution loss factors, data exchange guides and tools, and the most 4

current SCE or market business process updates that are required for the daily functions performed by 5

ESPs and CCAs. CCS also provides updated DA information for the ESPs and for customers on the 6

status of the annual lottery customer enrollment process.12 CCS further verifies that ESPs and CCAs are 7

adhering to DA and CCA tariff requirements.13 8

(2) Account Management 9

The account management team builds and maintains business relationships 10

with ESPs and CCAs in order to facilitate the market and business-to-business transactions with SCE. 11

The majority of the questions involve DA customers switching to and from DA service, relocating 12

accounts, or assigning DA eligibility to other customers. CCS DA activity increased as a result of the 13

partial reopening of DA. CCS account managers educate ESPs on the requirements of the decisions and 14

the processes that SCE employs during the enrollment period. Account managers also provide updates 15

and address regular inquiries from current and potential ESPs regarding SCE process changes stemming 16

from new Commission direct access rulings and decisions, such as the partial re-opening of DA and the 17

process improvements for administering enrollments of direct access rights authorized in D.10-03-022 18

and D.12-12-026, respectively. 19

CCS account management responds to inquiries from current and potential 20

CCAs and helps ensure that SCE meets its obligations with the CCA during start-up, the establishment 21

of service for individual service accounts, and throughout the implementation process. 22

Daily contact is made with ESPs and CCAs through a variety of methods, 23

including telephone, e-mail, direct mail, and in-person meetings. 24

(3) Service and Support 25

The service and support function provides ongoing, daily operational 26

assistance to ESPs and CCAs. This function serves as a single point of contact to handle the day-to-day 27

12 The modification of the DA enrollment process to a Random Number List Switching and Enrollment “Annual Lottery”

process was specified in D.12-12-026.

13 General Obligations of ESPs are prescribed in Rule 22. CCA tariff requirements are contained in Rule 23 – Community Choice Aggregation and Rule 23.2 – Community Choice Aggregation (CCA) Open Season.

36

requests from ESPs and is expected to fulfill the same role for CCAs. The service and support group 1

receives ESP and CCA inquiries through inbound calls and e-mails and typically handles less complex 2

but higher volume inquiries requiring analysis and research, such as DA service request status, DA 3

eligibility status, billing concerns, credit concerns, and payment inquiries. The service and support 4

group interacts with the DA support groups in the Customer Contact Center, the Revenue Services 5

Organization, and the Meter Services Organization (Engineering, Meter Shop, and Field Services). 6

Additionally, the service and support group coordinates and manages electronic data exchanges with 7

ESPs. 8

b) Customer Choice Services Base Year Operating Results 9

In 2012, CCS continued to perform the contract management, account 10

management, and customer service and support activities described above. 11

(1) Electric Service Provider and Direct Access Activities 12

As of December 31, 2012, there were 16 active ESPs operating in SCE’s 13

service territory, serving about 29,000 DA service accounts, accounting for 10.9 billion kWh annually or 14

12 percent of SCE’s total distribution load. In comparison, on December 31, 2009, there were 15 active 15

ESPs and 19,000 DA service accounts, accounting for 7.8 billion kWh annually or nine percent of 16

SCE’s total distribution load. 17

The highest volume activity in CCS relates to transactions involving DA 18

customers returning to bundled service or DA-eligible accounts switching to DA from bundled service. 19

DA customers also have various options to switch between ESPs, relocate service accounts, and add 20

new facilities. As a result, many ESPs continue to request assistance to facilitate these transactions and 21

resolve issues raised by market participants with respect to how these transactions are to be completed 22

within the DA rules. In 2012, the CCS account management and the service and support groups handled 23

an estimated 100 calls and more than 1,400 e-mail communications and requests, which required 24

analysis and/or research to complete. SCE continues to receive Customer Information Service Requests 25

(CISRs) from ESPs. CCS provides the requested information for these service accounts, including 26

meter number, billing cycle, and load profile. In addition, CCS provides training to existing and new 27

ESPs that currently, or will soon, conduct business with SCE. In 2012, CCS worked with 13 new ESPs 28

to review the regulations, tariffs, and procedures to operate in California, and SCE expects continued 29

interest in the DA market. 30

37

In 2012, CCS also began preparing to implement the Random Number 1

List Switching and Enrollment “Annual Lottery” process, which replaced the previous first-come, first-2

served DA enrollment process, as specified in D.12-12-026.14 3

(2) Customer Choice Aggregation Activities 4

During the past several years, many cities and counties in SCE’s service 5

territory have explored the formation of a CCA. Through 2012, only the San Joaquin Valley Power 6

Authority had filed an implementation plan with the Commission.15 The CCS team continues to work 7

with interested cities, counties, and JPAs to respond to questions, provide information about CCA, and 8

provide aggregated and customer-specific information to municipalities that are exploring or considering 9

formation of a CCA. When requested, customer information is provided in accordance with the CCA-10

INFO tariff adopted by D.04-12-046. 11


The recorded/adjusted costs for Customer Choice Services as shown in Table III-13

10 were derived after analyzing recorded costs for this activity and adjusting them to reflect ongoing 14

business operations. 15

Table III-10 Customer Choice Services


Line No.

Customer Choice Services 2008 2009 2010 2011 2012

1 Labor Expense 988 1,001 822 1,036 1,044 2 Non-Labor Expense 143 67 208 107 13 3 Other - - - - - 4 Total Operation Expense 1,131 1,068 1,030 1,143 1,056

For the period 2008-2012, Customer Choice Services operating expenses 16

remained relatively stable, with the labor and non-labor expenses fluctuating in 2010-2011 due to the 17

temporary use of contract employees to support this activity due to employees who were on leave of 18

absence. In 2011, labor and non-labor expenses returned to historical levels as temporary contract 19

14 The Random Number List Switching and Enrollment “Annual Lottery” process was implemented in April 2013.

15 In September 2012, the San Joaquin Valley Power Authority was dissolved.

38

employees were converted to SCE employees. In 2012, non-labor decreased due to a reduction in 1

temporary contract employees and employee-related expenses. 2

d) Customer Choice Services Test Year Expectations 3

SCE does not expect DA activity to significantly increase costs for CSS. If future 4

laws or Commission decisions related to DA or CCA have a significant impact on CCS activities, SCE 5

expects that any additional costs associated with the outcomes of these regulatory proceedings would be 6

addressed in the appropriate regulatory forum as directed by the Commission. 7

SCE plans to continue to respond to public entities who are contemplating the 8

formation of a CCA, although the likelihood of CCA formation in SCE’s service territory in 2015-2017 9

continues to be uncertain.16 10

In the 2015 Test Year, SCE expects to continue Customer Choice Services 11

activities at the same level as the Base Year. As a result, SCE is not forecasting a change in the O&M 12

expenses for this activity in the Test Year. 13

5. Economic Development Services 14

SCE’s Economic Development Services (EDS) supports the regional economy and 15

benefits SCE’s ratepayers by helping to retain, grow, and attract commercial and industrial customers. 16

Since 1992, as demonstrated through the application of the Ratepayer Impact Mechanism (RIM) test, 17

EDS has provided a direct benefit to all SCE customers by helping to reduce rates by minimizing 18

stranded investment in assets and increasing recovery of fixed revenue requirements. SCE’s EDS 19

activities yield economic and fiscal benefits to California, as well as to the counties and cities served by 20

SCE, by helping to keep jobs in the state. 21

a) Descriptions of the Economic Development Services Function 22

SCE’s EDS group benefits ratepayers by retaining and expanding at-risk 23

businesses, attracting businesses in growth industries through various activities, including administering 24

SCE’s Economic Development Rate (EDR), providing leadership on initiatives that strengthen 25

California’s business infrastructure, and working with state and local economic development 26

16 Other Operating Revenue (OOR) derived from DA service fees is discussed in SCE-04, Volume 2. Due to the

uncertainty surrounding the formation of CCAs in the future, SCE has not included either the costs that would be incurred to provide services to CCAs and CCA customers or the associated OOR derived from CCA service fees. Should a CCA form, SCE expects that the OOR derived from CCA Service Fees would offset the majority of the costs associated with providing services to the CCA and impacted customers.

39

organizations. EDS activities are separated into two primary activities: Project Management and 1

Business Development. 2

(1) Project Management 3

EDS project managers work in conjunction with BCD’s account 4

management organization, as well as local, regional, and state representatives to identify and assist in the 5

retention and expansion of “at-risk businesses.” Project managers also assist in the attraction of new 6

businesses in growth industries to replace the recorded net losses of manufacturing facilities due to 7

either closure or migration out of SCE’s service area. 8

(2) Business Development 9

The business development team enhances project management efforts 10

through specific activities, such as providing marketing and collateral materials and communications to 11

internal and external audiences, maintaining SCE’s web-based tools, performing target market analysis, 12

along with regulatory and rate-specific support, and locating, monitoring, and providing assistance to 13

new identified markets for SCE that help meet SCE’s business objectives. 14

b) Economic Development Services Base Year Operating Results 15

During 2012, EDS facilitated the discussions or played a significant role in 38 16

projects, retaining and attracting 7,592 jobs. Of these projects, 21 were retention, eight were expansion, 17

and nine were attraction projects. Collectively, these projects represent approximately 280 million kWh 18

annually and account for over $26.1 million in annual revenue to SCE, which were at risk if not for the 19

efforts of EDS and other stakeholders. Without these projects, the fixed costs associated with delivery 20

of electricity would have been spread to the remaining SCE customers. As described below, EDS’s 21

2012 Base Year impact yields a net present value of $3.184 million and a benefit-cost ratio of 1.26, 22

demonstrating the EDS program is beneficial and cost-effective for all ratepayers. 23

(1) Project Management 24

The primary focus of project management is business retention, due 25

mainly to aggressive out-of-state competition, coupled with California’s high cost of doing business and 26

challenging business climate. Other states and utilities are currently using proactive business attraction 27

practices to entice companies to relocate, allowing competitors to successfully target California 28

businesses for out-of-state relocation. Project management activities focus on assisting at-risk 29

businesses and resolving issues critical to their retention and expansion such as energy costs, site-related 30

concerns, and workforce development. EDS works with companies to provide competitive advantage 31

40

programs and to identify the availability of federal, state, and local incentives. In 2012, EDS project 1

managers worked on 202 separate business projects, 38 of which resulted in the customer being 2

successfully retained, attracted, or expanded. 3

EDS project managers also develop and maintain strong collaborative 4

external and internal partnerships to connect businesses with regional resources and incentives. 5

External partners include local, regional, and state economic development 6

organizations (EDOs). As an example, EDS is on the TeamCalifornia board and helps drive decisions to 7

market California regions for business investment and job creation. TeamCalifornia members include 8

representatives from each of the state’s ten economic development marketing regions, state government 9

agencies, utilities, local workforce investment boards, along with colleges and universities. The 10

organization provides its members the opportunity to pool resources and promote California to a 11

national and global business audience through participation in trade shows, advertising in targeted 12

publications, and online state-level cooperative branding. This statewide partnership of economic 13

developers is significant because government resources are limited for marketing the state to the 14

business community to help address and deter the aggressive campaigns of lower-cost states seeking to 15

attract California businesses. 16

Internal collaboration is also necessary to coordinate services for the 17

retention, expansion, and attraction of businesses and industries. One example is the SCE Data Center 18

Task Force (SCE-DCTF), formed by EDS as an internal cross-functional team within SCE to coordinate 19

efforts to support a growing, energy-intensive industry that is highly mobile and sensitive to power 20

reliability and costs. The SCE-DCTF targets data center customers for energy efficiency, load growth, 21

business retention, expansion, and attraction opportunities. The SCE-DCTF business plan focuses on 22

identifying and engaging with existing and potential data center customers to attract, retain, and expand 23

operations within SCE’s service territory through coordinated and focused efforts to support the needs of 24

this unique and important customer group. 25

(2) Business Development 26

In 2012, EDS conducted strategic market analysis, developed targeted 27

marketing and communication materials, promoted the EDR, and provided continued support to EDR 28

customers. An economic impact analysis was prepared for each of the 38 successful projects on a 29

customer-requested ad hoc basis. EDS also supported other economic development activities as 30

discussed below. 31

41

(a) Economic Development Rate Design and Analysis 1

The business development group continues to administer and 2

monitor the effectiveness of new rate options that meet the needs of large, energy-intensive, at-risk 3

business customers. The EDR is an example of a rate designed to provide reduced electricity costs when 4

a customer can successfully demonstrate that, if not for the EDR, either alone or in combination with 5

other incentives, that customer would not expand operations, establish operations in our region, or 6

would close its business or relocate outside of California. 7

(b) Target Market and Migration Analyses 8

The business development group performs analyses to identify 9

customer migration and generate leads from key existing and emerging industries. Such analyses allow 10

project managers to target at-risk customers and industries whose retention on SCE’s system provides a 11

larger customer and sales base over which the fixed costs of energy generation, transmission, and 12

distribution are spread, thus helping to reduce rates. 13

(c) Economic Impact Analysis 14

The Economic Impact Analysis (ECIA) is performed through a 15

model that estimates the economic and fiscal impacts that specific business projects have on the regional 16

economy. The ECIA model is similar to other generally-accepted economic impact models, such as 17

those developed by Minnesota IMPLAN Group, Inc. and the Regional Economic Models, Inc. SCE’s 18

ECIA model uses 2011 IMPLAN multipliers, other relevant inputs, and project-specific inputs to 19

determine direct, indirect, and induced impacts. 20

The ECIA model is used to demonstrate the positive impact a 21

business retention or expansion would have for a specific customer project. The results can be shown to 22

the city in which the customer is located to show the projected economic impacts and revenues to the 23

community from the project. More importantly, it demonstrates how direct jobs create additional jobs 24

and infrastructure demands on every other sector of the local and regional economies. The ECIA model 25

also projects job growth from indirect and induced auxiliary sectors. Indirect impacts are new jobs, 26

output, and income that will be generated by industries that supply goods and services directly to the 27

company. Induced impacts consist of the jobs, output, and personal income in industries that serve the 28

direct and indirect employees and their families. 29

42

(d) Other Business Development Activities 1

Business Development continues to provide small and new 2

businesses with access to information and resources that foster and support business sustainability. 3

SCE’s EDS website continues to serve as a portal to information and tools, including subjects such as 4

workforce training, financial assistance for start-up businesses, and local, regional, and state business 5

incentives. EDS maintains and updates the website to help ensure that customers receive the latest 6

information and tools to make informed decisions. 7

EDS also supports forums that provide opportunities to discuss 8

best practices and benchmarking for start-up businesses. EDS is a member of the National Business 9

Incubation Association (NBIA) and continues to support incubation facilities that nurture early-stage 10

businesses. In 2012, EDS sponsored several NBIA programs and a portion of its annual conference. 11

SCE partners with Workforce Investment Boards (WIBs), the 12

Employment Training Panel (ETP), and worksource organizations to produce a more educated and well-13

trained workforce in the Southern California region. SCE is involved in job fairs, awareness campaigns, 14

sponsorships, and other workforce-related activities. 15

EDS continues to provide “at-risk” business leads to the project 16

management team for follow-up, gathered from both internal and external reports on customer activity. 17

The lead generation program uses leading indicators, such as declining electricity usage and/or credit 18

scores, to find customers who are likely to need assistance from the EDS group. 19

(3) Ratepayer Impact Measurement (RIM) Test 20

California Public Utilities Code Section 740.4 does not define how 21

ratepayer benefit should be measured. However, the Commission has held and later affirmed in multiple 22

GRC proceedings that ratepayer benefit can be measured through the Ratepayer Impact Measurement 23

(RIM) test. The test measures the impacts to customer bills or rates due to changes in the utility’s 24

revenues and operating costs caused by the program. 25

In performing the RIM test, SCE uses the most current avoided costs and 26

the retail rates in effect at the time. One key assumption for the RIM test is the continued use of the 27

current ratemaking mechanisms beyond the 2012 Base Year. Another assumption is the inclusion of all 28

generation, transmission, and distribution factors for use in the determination of the net present value 29

and the benefit-to-cost ratio. Additionally, for forecast purposes, all calculations use the rates and 30

associated marginal costs in effect as of April 1, 2013. 31

43

A RIM test yielding a positive net present value and a benefit-to-cost ratio 1

greater than 1.0 indicates the program is beneficial and cost-effective to all ratepayers by lowering rates 2

and bills. Based on the methods and assumptions set forth in the CPUC Standard Practice Manual and 3

related approaches noted above, EDS’s 2012 Base Year program yields a net present value of $3.184 4

million and a benefit-to-cost ratio of 1.26, demonstrating the EDS program is beneficial and cost-5

effective for all ratepayers. 6

(4) Economic Benefit in California 7

EDS’s activities result in economic benefit in California and help lower 8

overall rates for SCE’s customers. The ECIA model as described above was used to determine the 9

cumulative impact of SCE’s retention, expansion, and attraction of projects on California’s economy. 10

SCE included only the economic and fiscal impacts of projects at risk for closure or out-of-state 11

relocation. Projects that were not at risk to leave California were excluded from the analysis in order to 12

demonstrate only the net impact on California. 13

Using the ECIA IMPLAN Model, the cumulative direct, indirect, and 14

induced economic impacts of EDS activities in the 2012 Base Year operations resulted in the retention 15

and creation of approximately 16,362 jobs in California and associated economic output of $4.2 million. 16

Additionally, the incremental taxes, fees, and licenses collected at the state, county, and city levels 17

resulted in a cumulative fiscal impact of approximately $94,745. 18


The recorded/adjusted costs for ESD are shown in Table III-11 and were derived 20

after analyzing recorded costs for this activity and adjusting them to reflect ongoing business operations. 21

Table III-11 Economic Development Services


Line No.

Economic Development Services

2008 2009 2010 2011 2012

1 Labor Expense 1,441 1,669 1,642 1,489 1,207 2 Non-Labor Expense 1,031 1,046 865 699 203 3 Other - - - - - 4 Total Operation Expense 2,472 2,715 2,507 2,188 1,410

In 2009, SCE filled a number of EDS vacancies that existed in 2008, resulting in 22

an increase in labor expenses in that year. Labor expenses remained relatively flat in 2010 and then 23

44

declined in 2011 and 2012 due to SCE’s efforts to leverage other economic development resources both 1

within and outside of SCE. In 2012, BCD implemented a number of productivity measures, including 2

further leveraging the efforts of EDS and other state and local economic development agencies. As a 3

result of these initiatives, in 2012, BCD reduced the number of EDS labor resources, resulting in a 4

decrease in labor costs of $282,000 compared to 2011. 5

Non-labor expenses remained relatively flat between 2008 and 2009. Since 2009, 6

SCE has reduced non-labor expenses in this activity by leveraging other internal and external economic 7

development resources, eliminating the Global Information System (GIS) toolset in 2012 and reducing 8

SCE sponsorship expenses. In addition, as SCE reduced labor expenses in this activity in 2011 and 9

2012, SCE also reduced employee-related expenses, such as travel, training, and professional 10

development expenses. 11

d) Economic Development Services Test Year Operating Expectations 12

In the 2015 Test Year, SCE expects to continue to conduct EDS activities and, 13

with the optimization of EDS operations, SCE forecasts a reduction in O&M expenses of $195,000. 14

Specifically, SCE plans to continue to leverage state and local economic development activities in order 15

to reduce internal activities and expenses, while still maintaining the core capability to address customer 16

retention issues and activities associated with administering the economic development rates. 17

SCE’s most recent EDR program closed to new customers effective December 31, 18

2012, although SCE will continue to administer the five-year contracts signed by customers before the 19

sunset date. PG&E has a pending application at the Commission (A.12-03-001) for a new EDR 20

program. If a new EDR program is approved for PG&E with terms that would be favorable to SCE’s 21

ratepayers, SCE could potentially file a similar application to implement a new EDR. 22

B. Business Customer Division Recorded Cost Summary 23

As noted in Chapter I of this Volume, in order to better describe and forecast BCD activities, 24

SCE has consolidated these activities into FERC Account 908.600. Table III-12 below summarizes five 25

years of historical recorded/adjusted expenses for FERC Account 908.600. There are four types of 26

adjustments that are summarized for each account or subaccount and are described individually in the 27

workpapers supporting this Volume. Descriptions of these adjustments are included in Exhibit SCE-10. 28

The four types of adjustments are as follows: 29

1. Ratemaking adjustments, made at the corporate level, to conform corporate accounting to 30

FERC categories and to remove non-utility expenses; 31

45

2. Accounting adjustments, made to transfer recorded expenses from one account to another 1

within the BCD functional group of accounts to appropriately reflect the current 2

organizational structure within Customer Service; 3

3. Operational adjustments, such as removing one-time, non-recurring activities; and 4

4. Reclassification adjustments, made to move expenses originally recorded within one group of 5

FERC Accounts to another FERC group to reflect current practices. 6

Once these FERC account level adjustments were made, the recorded data was categorized into 7

functional groups. The recorded O&M expenses for each functional group for 2008 through 2012 were 8

then reviewed to identify cyclical, nonrecurring, or unusual expense patterns resulting in specific 9

organizational unit adjustments that were made to the functional group expenses. 10

The analyses of recorded/adjusted costs associated with each activity within FERC Account 11

908.600 are described in each activity’s section above. As shown in Table III-12 below, the aggregate 12

O&M costs in FERC Account 908.600 have declined by more than 20 percent since 2010. 13

46

Table III-12 Business Customer Division

Recorded/Adjusted Expenses (2008-2012) FERC Account 908.600

(Constant 2012 $000)

Line No.

2008 2009 2010 2011 2012

12 Labor Expense 11,919 12,130 11,371 11,072 9,963 3 Non-Labor Expense 3,822 4,111 4,439 4,145 2,537 4 Other - - - - - 5 Total AM Expense 15,741 16,241 15,810 15,216 12,500 67 Labor Expense 2,832 3,010 3,675 3,919 3,482 8 Non-Labor Expense 699 842 904 615 440 9 Other - - - - -

10 Total TS Expense 3,531 3,852 4,579 4,534 3,922 1112 Labor Expense 1,015 998 1,230 842 861 13 Non-Labor Expense 949 1,129 1,119 1,007 470 14 Other - - - - - 15 Total EEC Expense 1,963 2,126 2,349 1,849 1,330 1617 Labor Expense 988 1,001 822 1,036 1,044 18 Non-Labor Expense 143 67 208 107 13 19 Other - - - - - 20 Total CCS Expense 1,131 1,068 1,030 1,143 1,056 2122 Labor Expense 1,441 1,669 1,642 1,489 1,207 23 Non-Labor Expense 1,031 1,046 865 699 203 24 Other - - - - - 25 Total EDS Expense 2,472 2,715 2,507 2,188 1,410 2627 Labor Expense 18,194 18,808 18,740 18,357 16,556 28 Non-Labor Expense 6,644 7,194 7,535 6,573 3,663 29 Other - - - - - 30 Total 908.600 Expense 24,838 26,002 26,275 24,930 20,219

Business Customer Division Total

Business Account ServicesFERC 908.600Account Management (AM)

Technical Services (TS)

Energy Education Centers (EEC)

Customer Choice Services (CCS)

Economic Development Services (EDS)

C. Test Year Expectations (FERC Account 908.600) 1

Figure III-2 shows the recorded/adjusted historical and forecast expenses for the BCD function. 2

Details regarding the forecast O&M expenses for this function are described in detail in Section III.A 3

above and summarized below. As noted in Chapter I, in order to better describe and forecast Business 4

Customer Division Activities, SCE has consolidated these activities into FERC Account 908.600. 5

47

Figure III-2 Business Customer Division

Recorded And Adjusted 2008-2012/Forecast 2013-2015 FERC Account 908.600


1. Determination of Test Year Estimating Methodology 1

In 2012, SCE recorded $20.219 million for BCD activities as shown in Table III-12 2

above. Labor costs have declined since 2009 and non-labor costs have declined since 2010. The most 3

recent year accurately reflects expense levels associated with current activity levels, and, therefore, the 4

Last Recorded Year was selected as the appropriate basis for forecasting labor and non-labor O&M 5

expenses for this FERC Account. 6

2. Test Year Adjustments 7

SCE forecasts a net reduction in O&M expenses of $1.339 million for FERC Account 8

908.600 in the 2015 Test Year for Account Management Services and Economic Development Services 9

as summarized below. These adjustments are summarized in Table III-13 below. Details of each 10

adjustment are described in Section III.A. SCE does not forecast a change in O&M expenses for 11

Technical Services, the Energy Education Centers or Customer Choice Services activities in the Test 12

Year. 13

48

a) Account Management Services (Summary) 1

As noted in Section III.A.1.d), SCE’s 2015 Test Year forecast includes two 2

adjustments. First, SCE forecasts $1.402 million in reduced O&M costs associated with optimizing 3

Account Management Services Activities. Second, SCE forecasts an increase in costs of $258,000 in 4

this activity to reflect the impact of non-residential customer growth. Together, these two adjustments 5

total a reduction in O&M expenses in 2015 of $1.144 million for Account Management Services 6

Activities. 7

b) Economic Development Services (Summary) 8

As noted in Section III.A.5.d), SCE forecasts a reduction in O&M expenses for 9

the Test Year of $195,000 by further leveraging state and regional economic development activities. 10

Table III-13 Summary of Test Year Forecast Adjustments

FERC Account 908.600 (Constant 2012 $000)

Line No.

Description2015 Forecast Adjustment

1 Account Management Support Operational Excellence (1,402) 2 Account Management Customer Growth Impact 258 3 Economic Development Services Operational Excellence (195) 4 Total FERC Account 908.600 Forecast Adjustments (1,339)

3. Test Year Forecast 11

The rationale supporting our forecast to reduce our 2012 Last Recorded Year of $20.219 12

million by a net amount of $1.339 million is described above. The Test Year forecast for FERC 13

Account 908.600 is shown in Figure III-3 below and includes a reduction in expenses of $1.596 million 14

associated with operational excellence improvements SCE expects to achieve as a result of consolidating 15

and implementing process improvements in BCD. Figure III-3 also includes an increase in forecast 16

expenses of $258,000 to reflect the impact of customer growth on Account Management Services 17

Activities. Combined, these adjustments result in a Test Year forecast for FERC Account 908.600 of 18

$18.879 million. Figure III-3 shows the Test Year forecast for FERC Account 908.600 compared to the 19

Base Year. 20

49

Figure III-3 Business Account Services

Comparison of 2012 Base Year to 2015 Test Year FERC Account 908.600

(Constant 2012 $000s)

$20,219 $258 ($1,596)

$18,879

$0

$5,000

$10,000

$15,000

$20,000

$25,000

2012 Recorded Customer Growth Operational Excellence 2015 Forecast

D. Business Customer Division Capital 1

1. Introduction 2

BCD requires capital funding for ongoing upgrades and improvements to the EECs and 3

specialized equipment to support BCD engineering and such specialized services as pump testing. The 4

BCD capital requirements total $8.016 million for 2013-2017 and are described below. 5

2. Structures and Improvements – Energy Education Centers (CCS-00-SI-BC-CT-6

00001 and CCS-00-SI-BC-AT-00001) 7

The EECs will require capital funding to align with evolving customer demand for 8

Workforce Education and Training programs and to maintain compliance with Commission directives 9

and other essential statewide initiatives. In particular, a number of the projects included below for both 10

EEC-Irwindale and EEC-Tulare were developed to support expanding the Quality Installation and 11

Quality Maintenance (QI/QM) and green workforce training programs. In addition, the capital projects 12

for the EECs include facility retrofits and upgrades to existing classrooms and structures to replace worn 13

or obsolete equipment, HVAC system improvements, and upgrades to equipment testing facilities for 14

lighting and HVAC trades and certifications educational and training facilities. SCE also proposes to 15

50

build a Zero Net Energy (ZNE) test center in order to support the Commission’s long-term ZNE goals 1

by providing a functional modular facility that will enable the demonstration of new ZNE technologies, 2

materials, and techniques. In 2015, we forecast $1.483 million in capital expenditures for structures and 3

necessary improvements at EEC-Irwindale and EEC-Tulare. In addition, we forecast capital 4

expenditures of $1.957 million in 2016 and $1.747 million in 2017 for similar improvements. The 5

recorded and forecast capital expenditures for the structures and building improvements are shown 6

below in Table III-14. 7

Table III-14 Energy Education Centers Structures and Improvements17

(Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 EEC - Irwindale $ 201 $ 1,070 $ 1,367 $ 498 $ (2) $ 313 $ 1,020 $ 584 $ 706 $ 113 2 EEC - Tulare 422 570 715 886 (23) 164 276 899 1,251 1,634

3Total Energy Education CentersStructures and Improvements

$ 623 $ 1,640 $ 2,082 $ 1,384 $ (25) $ 477 $ 1,295 $ 1,483 $ 1,957 $ 1,747

Line No Expenditure

Recorded Forecast

a) Energy Education Center – Irwindale 8

In 2013 through 2017, EEC-Irwindale capital projects total $2.736 million and 9

include $1.425 million for facility retrofits and upgrades to existing classrooms and structures, $445,000 10

for HVAC system improvements, $716,000 to upgrade lighting and HVAC trades and certifications 11

training facilities, and $149,000 for the installation of new solar photovoltaic generation infrastructure.18 12

b) Energy Education Center – Tulare 13

In 2013 through 2017, EEC-Tulare capital projects total $4.224 million and 14

include $363,000 for facility retrofits and upgrades to existing classrooms and structures, $2.268 million 15

for upgraded trades and certification training facilities, and equipment testing facilities for lighting, 16

HVAC, and ZNE educational programs and $1.593 million for HVAC system improvements.19 17

3. Specialized Equipment (CCS-00-SE-BC-PT-00001 and CCS-00-SE-BC-TS-00001) 18

SCE’s forecast for the specialized equipment for use by BCD engineers and pump test 19

specialists is budget-based and considers the age and condition of the equipment. Recorded and forecast 20

17 2012 Amounts reflect the impact of an accounting adjustment of $93,000 for EEC-Irwindale, and a write-off of $33,000

for EEC-Tulare.

18 See workpapers for a detailed list of EEC-Irwindale capital projects.

19 See workpapers for a detailed list of EEC-Tulare capital projects.

51

amounts for BCD’s specialized equipment are shown in Table III-15. Specialized equipment items 1

forecast from 2013 through 2017 are described in the sections that follow. 2

Table III-15 Business Customer Division Specialized Equipment

(Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015 2016 20171 Engineering Tools and Equipment -

Technical Services $ 186 $ - $ 126 $ 110 $ - $ 20 $ 20 $ 227 $ 131 $ 133 2 Engineering Tools and Equipment -

Pump Test - 267 127 106 87 99 103 105 108 111

3Total Business Customer Services Specialized Equipment

$ 186 $ 267 $ 254 $ 215 $ 87 $ 118 $ 123 $ 332 $ 239 $ 244

Line No Expenditure

Recorded Forecast

a) Engineering Tools and Equipment 3

Engineers use portable metering equipment to measure electricity use, fluid flow, 4

system temperatures, and other metrics needed to evaluate end-use customer equipment and/or process 5

changes that may be appropriate for customers seeking better management of their energy consumption. 6

Engineers similarly use portable test equipment to measure energy use, 7

temperatures, and other data at customer sites to support their evaluation of energy consumption and 8

performance of existing or new equipment being considered by customers. Customers also place 9

equipment in the Refrigeration and Thermal Test Center and the Southern California Lighting 10

Technology Center, which is used to measure energy consumption, temperatures, and other data for 11

verification of equipment performance. SCE forecasts expenditures of $531,000 in 2013 through 2017 12

for engineering tools and equipment. 13

SCE's pump test and hydraulic services organization uses specialized equipment 14

to perform pump tests for customers. This equipment is used to gather various measurements, such as 15

power, pressure, water levels, and flow of water and other fluids to determine the overall pumping plant 16

efficiency. Customers use the test results to make informed decisions as to when and how to renovate or 17

replace equipment to increase efficiency, reduce energy consumption, demand, and annual operating 18

costs. SCE forecasts expenditures of approximately $100,000 per year in 2013-2017 for pump test 19

equipment, for a total of $526,000 for the period. 20

E. Business Customer Division Other Operating Revenues (OOR) 21

1. Introduction 22

SCE provides a variety of programs that complement our role as a utility, and the revenue 23

derived from these activities is classified as Other Operating Revenue (OOR). SCE’s OOR is comprised 24

52

of those products and services managed by SCE’s Customer Service Operations (described in Volume 2 1

of this exhibit) and those products and services managed by BCD (presented in this Volume). BCD 2

manages OOR consisting of Energy Related Services (ERS), a program that manages the development, 3

financing, and implementation of energy efficiency or renewable energy projects for federal customers, 4

and SCE EnergyManager, an online energy information tool for its largest non-residential customers. 5

These services provided by BCD described in this section are offered to customers on a tariffed basis. 6

Revenues derived from these charges are recorded in FERC Account 456. In this 7

Chapter, we define the functional sub-accounts associated with the services offered on a tariffed basis 8

and describe the analyses and estimating methods used to forecast our Test Year 2015 OOR. The total 9

OOR managed by BCD is summarized in Table III-16. 10

Table III-16 Business Customer Division Other Operating Revenues

FERC Accounts 456.924 and 456.945 (Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015

1 456.924 Energy Related Services 1,127 1,185 679 300 416 425 450 500 2 456.945 SCE EnergyManager 976 558 478 521 517 191 191 191 3 Total 2,103 1,743 1,157 821 933 616 641 691

Line No.

FERC Account

DescriptionRecorded Forecast

2. Estimating Method for OOR 11

Generally, the process followed in estimating the Test Year 2015 revenues associated 12

with the tariffed products and services we offer involves: 13

Identification of the revenue-related activity for each existing subaccount; 14

Identification of any new revenue-related activities, if applicable; 15

A review of the historical record of actual revenue collected from this activity to the 16

extent applicable; and 17

A description of the basis or method employed to estimate the Test Year 2015 18

forecast for these activities. 19

Of the two OOR services described in this Volume, only SCE EnergyManager is fee-20

based. 21

3. FERC Account 456.924 – Energy Related Services 22

Energy Related Services (ERS) is a tariffed product offered to our federal customers 23

under SCE’s Area-Wide Agreement and Basic Ordering Agreements with various United States 24

53

government agencies. The ERS program was created through Advice Letter 1358-E (approved on 1

February 1, 1999) and updated in Advice Letter 2703-E (approved on April 3, 2012). The current Area-2

Wide Agreement was created pursuant to federal law, dated November 26, 2008. Under Executive 3

Order 12902, dated March 8, 1994, the federal government is authorized and encouraged to enter into 4

contracts with local utilities on an established source basis to expedite and facilitate the implementation 5

of cost-effective energy and water conservation measures. 6

Under the ERS program, federal customers are able to use SCE’s energy efficiency and 7

project management expertise for identifying, designing, financing, and managing the construction of 8

energy efficiency or renewable energy projects. SCE generates revenue through the project 9

management of these energy efficiency and renewable projects. SCE has developed agreements with 10

lenders to provide the initial funding and subsequent capital for projects when federal customers do not 11

have the funds appropriated or budgeted. Project funding is repaid to the lender by the customer over 12

time—typically 15 years. In this manner, SCE is able to meet many of the needs of our federal 13

customers while minimizing the required financial commitment. In addition, SCE targets moderate-14

sized projects in the $500,000 to $1.500 million range. Based on the projects identified to date, SCE 15

estimates that the program will generate net revenues of approximately $500,000 in the Test Year. This 16

is an increase of $84,000 from the 2012 recorded OOR of $416,000 and reflects SCE’s expectation that 17

activities in this area will increase slightly as a result of a modest increase in federal government 18

spending following the constrained spending environment encountered from 2000 to the present. 19

Figure III-4 below provides the recorded and forecast revenues associated with ERS. 20

54

Figure III-4 FERC Account 456.924 Energy Related Services

(Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015

Recorded & Forecast Revenues (Nominal 2012 $000) $ 1,127 $ 1,185 $ 679 $ 300 416$ 425$ 450$ 500$

Prior Year Total 416$ 425$ 450$ Change 9$ 25$ 50$

Amounts represent net OOR (OOR less expenses)

Recorded Forecast

-

200

400

600

800

1,000

1,200

1,400

2008 2009 2010 2011 2012 2013 2014 2015

4. FERC Account 456.945 SCE – EnergyManager® 1

SCE provides online energy information to its largest commercial and industrial 2

customers using the SCE EnergyManager suite of tools. Daily and monthly updates are free of charge, 3

and for a fee, customers can elect to receive same-day energy usage updates on an hourly or quarter-4

hourly basis. The current and proposed fees for SCE EnergyManager tools are shown in Table III-17 5

below. 6

SCE EnergyManager operations are described in Chapter IV of this exhibit. As described 7

in Section IV.B, since 2009, the number of customers enrolled in EnergyManager Basic has declined, 8

while overall usage of the service has increased significantly as reflected in the number of customer 9

users accessing the tool each month and the average number of monthly website visits. 10

In SCE’s 2012 General Rate Case (A.10-11-015), SCE proposed reducing or eliminating 11

some of the fees for Cost Manager and Bill Manager. That proposal was adopted in D.12-11-051. The 12

adopted fee structure was implemented on January 1, 2013 and, therefore, is not reflected in the Base 13

Year results. 14

55

SCE does not propose any change to the fee structure established in D.12-11-051. While 1

there has been an increase in the usage of free EnergyManager services, SCE expects that fee-based 2

enrollments will remain at current levels. However, the reduction in fees approved in D.12-11-051 has 3

resulted in a decrease in EnergyManager OOR as shown in Table III-17. 4

Table III-17 Current and Proposed SCE EnergyManager Fees,

Monthly Service Fee Per Account

Line No.

DescriptionFees Prior to

January 1, 2013

Current Fees Proposed Fees

1 Customers with SCE EnergyManager Basic:2 Daily Cost Manager $ 10 - 3 Hourly Cost Manager $ 60 $ 60 4 Quarter Hourly Cost Manager $ 100 $ 100 5 Customers without EnergyManager Basic:6 Monthly Cost Manager $ 10 - 7 Daily Cost Manager $ 30 - 8 Hourly Cost Manager $ 80 $ 60 9 Quarter Hourly Cost Manager $ 120 $ 100

10 Bill Manager Initial Set Up Fee $ 10 - 11 Bill Manager Monthly Fee $ 6 - - 12 SCE EnergyManager Suite of Tools - 13 Hourly Energy Usage Updates $ 60 14 Quarter Hourly Energy Usage Updates $ 100

56

Figure III-5 FERC Account 456.945

Forecasted SCE EnergyManager OOR (Nominal $000)

2008 2009 2010 2011 2012 2013 2014 2015

Recorded & Forecast Revenues (Nominal $000) $ 976 $ 558 $ 478 $ 521 517$ 191$ 191$ 191$

Prior Year Total 517$ 191$ 191$ Change (326)$ -$ -$

Recorded Forecast

-

200

400

600

800

1,000

1,200

2008 2009 2010 2011 2012 2013 2014 2015

57

IV. 1

CUSTOMER PROGRAMS AND SERVICES 2

SCE’s Customer Programs and Services (CP&S) Division leads SCE’s efforts to engage and 3

serve its customers through three distinct functions. First, the Consumer Affairs and Customer 4

Satisfaction function gathers and receives feedback from SCE’s customers to answer customer inquiries, 5

resolve consumer complaints, and improve our programs and services. Second, the Marketing, 6

Communications and Digital Delivery of Customer Services function educates and helps SCE’s 7

residential and non-residential customers make informed decisions about rates, programs, and services 8

that benefit them. Third, the Customer Programs function develops, implements, and manages many of 9

SCE’s programs and services. The Consumer Affairs and Customer Satisfaction function and the 10

Marketing, Communications and Digital Delivery of Customer Services function are presented in 11

Volume 2 of this exhibit. Their applicability to non-residential customers is described briefly below. 12

The Customer Programs function, along with an analysis of its recorded and forecast O&M costs, is 13

described below. 14

A. Consumer Affairs, Customer Satisfaction, Marketing, Communications and Digital 15

Delivery of Customer Services 16

SCE’s Consumer Affairs and Customer Satisfaction function is described in Volume 2, Chapter 17

VII, of this Exhibit. Although the majority of activities undertaken in this function address the needs 18

and concerns of our 4.1 million residential customers, non-residential customers also benefit from these 19

activities. For example, approximately 15% of the inquiries and complaints handled by Consumer 20

Affairs originated from non-residential customers, primarily small businesses. The Customer 21

Satisfaction function’s effort to identify and implement improvements to SCE’s services also benefits 22

non-residential customers. For example, SCE’s efforts to improve outage management communications, 23

led by the Customer Satisfaction function and described in detail in Volume 2, Section VII.B.2, benefit 24

all non-residential customers who may be impacted by planned or unplanned outages. As a result of the 25

efforts undertaken by the Customer Satisfaction function in the Base Year, non-residential customers 26

now receive automated messages for both planned and unplanned outages, greatly expanding the 27

proactive communications about outages affecting them. 28

SCE’s Marketing, Communications and Digital Delivery of Customer Services function is 29

described in Volume 2, Chapter VIII, of this Exhibit. Like the Consumer Affairs and Customer 30

Satisfaction function, many of the activities undertaken by the Marketing, Communications and Digital 31

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Delivery of Customer Services function benefit SCE’s non-residential customers. For example, as part 1

of SCE’s comprehensive annual summer conservation campaign, SCE conducted outreach to small 2

businesses through print ads, digital, and outreach communication materials supplied for sponsored 3

community events to help small businesses prepare for the high temperatures of the summer months. 4

These efforts are described in more detail in Section VIII.A.2 of Volume 2 of this exhibit. 5

SCE’s Digital Delivery of Customer Services function manages SCE’s digital presence through 6

SCE.com, including many self-service tools that allow residential and non-residential customers to 7

conduct business with SCE online, including checking their account balances and paying their bills. In 8

2012, SCE improved the accessibility of SCE.com so that 80 percent of its content is now available in 9

Spanish, Chinese, Vietnamese, and Korean, which is expected to benefit small business owners who are 10

more comfortable conducting business in these languages. These efforts are described in more detail in 11

Section VIII.B.2 of Volume 2 of this exhibit. 12

B. Customer Programs 13

The Customer Programs function develops, implements, and manages many of SCE’s programs 14

and services. These activities, performed by SCE’s Customer Programs and Services (CP&S) 15

organization, are described in detail below and costs related to these activities are recorded in FERC 16

Account 908.640. 17

1. Description of Customer Programs 18

The Customer Programs function combines activities related to developing and delivering 19

SCE’s portfolio of programs. Currently, this portfolio consists of energy information and management 20

programs, such as Budget Assistant and SCE EnergyManager. The Customer Programs function is also 21

responsible for managing SCE’s dynamic pricing programs and portfolio of Energy Efficiency (EE) and 22

Demand Response (DR) programs, which are funded through the Public Goods Charge or Demand 23

Response Balancing Account and are not included in the O&M forecast in this Application except as 24

noted below in Section 1b. Finally, this function also leads the development of new customer service 25

related programs and services, e.g., SCE’s Pre-Payment program (described in Volume 2 of this Exhibit) 26

and pilots/programs that help customers adopt new technology (like HAN and energy management). 27

a) Energy Information and Management Programs 28

Deployment of ESC meters was completed in the Base Year for residential and 29

commercial customers with demands less than 200 kW. ESC provides SCE the ability to more actively 30

engage customers in managing their energy use and expense. Central to engaging customers with the 31

59

information and services to better manage their energy usage is providing them with a suite of tools that 1

serve to enhance their understanding of the correlation between energy usage and their electric bill. 2

These tools include daily usage and cost calculations, projected cost and usage calculations, and Budget 3

Assistant, which offers proactive outbound cost information to help customers more actively manage 4

their energy budget. 5

For customers with demands greater than 200 kW, SCE continues to offer the 6

SCE EnergyManager program. This program is a web-based application that participating customers 7

can use to access their energy and demand data, as well as usage, cost, and billing reporting tools. 8

In addition to SCE’s energy information and management programs and services, 9

we will enable certain third-party services and facilitate customer access to services offered by other 10

market participants. For example, through our proposed ESPI platform, we will enable customers to 11

authorize us to provide a customer’s usage data to a third-party energy management service provider in 12

an automated fashion.20 13

b) Dynamic Pricing Programs 14

Dynamic pricing (or time-differentiated) programs and rates include Time-of-Use 15

(TOU) Rates, Critical Peak Pricing (CPP, also known as the Summer Advantage Incentive program), 16

and Real-Time Pricing (RTP) options. The primary purpose of these programs and rates is to provide 17

appropriate pricing signals to customers, prompting them to reduce their energy consumption during on-18

peak periods or shift their consumption to off-peak periods. Prior to the deployment of the ESC meters, 19

a meter change was required in order to accommodate customers with demands less than 200 kW 20

choosing to take service under a time-differentiated rate plan. With SCE’s ESC meters fully deployed, 21

these rate options are now immediately available to the vast majority of residential and business 22

customers. 23

In D.09-08-028, SCE was directed to file a proposal to implement additional 24

default or optional dynamic pricing rates and mandatory TOU rates for certain non-residential and 25

residential customers, which the Commission ordered to be effective in January 2012. The 26

implementation of dynamic pricing rates was delayed in SCE’s 2012 GRC Phase 2 proceeding, and, in 27

D.13-03-031, the Commission directed SCE to begin the transition of eligible non-residential customers 28

20 SCE’s proposed ESPI platform is described in Application for Approval of Proposal to Enable Automated Access of

Customer Usage Data to Authorized Third Parties and Approval of Cost Recovery Mechanism (A.12-03-004). As of May 31, 2013, no Decision has been issued in this proceeding.

60

with demands less than 200 kW to mandatory TOU rates beginning in January 2014 and to default CPP 1

in 2016. Furthermore, in D.12-04-045, the Commission found that dynamic pricing rates should be 2

included in the utilities’ General Rate Cases, and, although it approved funding for CPP <200kW, CPP 3

≥200kW and RTP for the 2014-2014 Demand Response budget period, the Commission ordered those 4

programs not be included in future Demand Response applications. Accordingly, SCE includes those 5

program costs in this application.21 6

c) Other Customer Service Related Programs 7

In addition to energy information and management and dynamic pricing 8

programs, the Customer Programs function also develops, pilots, and manages other customer service 9

related programs. A primary program that this function manages is the Renewable Tariff and 10

Interconnection Program, which is designed for customers who are interested in renewable generation, 11

particularly solar energy. In terms of program development activity, this function actively assesses the 12

portfolio of programs and services that SCE offers its customers and looks for opportunities to enhance 13

existing or add new programs to address evolving customer needs. An example of the type of 14

opportunities this function assesses is the expansion of billing and payment programs. Additionally, 15

with the emergence of new technologies, this function is responsible for testing and piloting new 16

technologies and identifying opportunities to integrate these technologies into existing program 17

offerings or to develop new programs that encourage customer adoption of new technologies. Emerging 18

technology areas of focus include HAN, solar, and PEV. 19

As part of the program development, implementation, and management activities, 20

the Customer Programs function coordinates with Customer Service operating organizations (e.g., the 21

Revenue Services Organization described in Volume 2 of this Exhibit), Regulatory, Legal, and Financial 22

organizations throughout SCE to ensure the successful development and implementation of new 23

customer programs. The function also partners with the Marketing and Communications function to 24

21 In SCE’s 2012 GRC Decision (D.12-11-051), the Commission directed SCE to track Dynamic Pricing expenses

recovered through the GRC and report them in this GRC. See D.12-11-051, Ordering Paragraph 25, p. 885. In 2012, Dynamic Pricing expenses were recorded in the ESC Balancing Account (ESCBA), consistent with the Commission’s direction. See D.12-11-051, p. 350. Therefore, no Dynamic Pricing expenses were recorded and recovered through the GRC in 2012. As of the filing of this Application, Dynamic Pricing expenses to be recovered through the GRC have not yet been fully recorded. Capital expenditures associated with the Dynamic Pricing capitalized software project that was first described in SCE’s 2012 GRC (A.10-11-015) are discussed in Exhibit SCE-05, Vol. 2, Part 1.

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integrate programs and services into Lifestyle Packages, pre-defined bundles of programs and services, 1

which allow customers to more easily enroll in SCE’s various offerings. 2

2. Base Year (2012) Operating Results 3

a) Energy Management and Information Programs 4

In 2012, as the deployment of the ESC infrastructure was completed, residential 5

and commercial customers with demands less than 200 kW were able to take advantage of a suite of new 6

tools and services. These new tools leverage the interval data available from the ESC meter and provide 7

this information to customers so that they can better understand the correlation between energy usage 8

and cost. Additionally, customers with demands greater than 200 kW were still able to take advantage 9

of SCE’s EnergyManager offering. 10

(1) Web Presentment of Interval Data 11

Web presentment of hourly or 15-minute interval usage data is updated 12

daily and available to ESC-metered customers through My Account on SCE’s website. Customers can 13

access the website to view their account information and many other charts and reports depicting their 14

recent and historical electricity usage. This includes information such as the previous day’s data, all 15

usage data within the current (not yet billed) billing period, historical monthly consumption, and 16

historical monthly with a three-year comparison of recorded usage for the most recent month. Detailed 17

usage information will remain available for a rolling 36-month timeframe. Current and projected usage 18

information is also included to help customers better understand their usage patterns and behaviors and 19

the relationship between their usage and rate plan. Additionally, SCE incorporated hourly and daily 20

high temperature information to help customers understand the relationship between warm weather and 21

energy usage. Included with the hourly and daily usage display is a cursor roll-over feature that displays 22

the high temperature for the hour and for the day, specific to each customer’s climate zone based on the 23

applicable U.S. postal zip codes. By the end of 2012, there were approximately one million active My 24

Account users who were able to leverage this granular usage information.22 25

(2) Web Presentment of Cost Information 26

The ESC system also leverages the availability of granular usage data to 27

perform daily cost calculations and end of bill period cost projections based on actual and forecast 28

22 Active My Account users are defined as ESC-metered customers with unique user ID log-ins to My Account within the

last 90 days.

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electricity usage across many different individual rate plans. These cost tools collectively leverage the 1

interval usage data and translate it to relevant customer-specific electricity costs to help customers better 2

manage their electricity use. These cost tools have helped transform the customer’s experience beyond 3

the basic value of having access to hourly interval data alone, by infusing dynamic projections and rate-4

specific information to provide near real-time billing data and forecasts of potential bill impacts based 5

on each customer’s actual usage behavior. With these newly enabled features, customers can always 6

know how much they’ve spent within the current billing period and how much they are expected to 7

spend in advance of actually receiving their next monthly bill. As demonstrated by adoption rates and 8

positive consumer feedback, these tools have been well received and are serving to enforce the value 9

proposition for smart meters. In 2012, on My Account on SCE’s website informational pages, a 10

prominent four quadrant display of “Balance Due,” “Projected Next Bill,” “Billed Usage,” and “Daily 11

Usage” data provided a wealth of information at the summary level with more detailed supporting 12

information just a click or two away. Additionally, SCE developed a visual depiction for residential 13

customers of their actual and projected usage into the tiered rate pricing structure. This dynamic display 14

is referred to as “Tier Position” and provides customers with their specific daily cost for electricity as 15

calculated using the standard four-tier rate plan structure. The chart also provides the kWh price for 16

each of the four tiers, the allocation of kWh for each tier, and the customer’s projected tier landing point 17

at the end of the current billing period. Additionally, each of the first three pricing tiers displayed in this 18

chart is relative in length to the kWh allocation to that tier, and a reference is provided to indicate the 19

customer’s current position within the tiered pricing structure. This report facilitates customers’ ability 20

to quickly determine not only the price they are paying for electricity but also what they can expect to 21

pay by the end of the current billing period. The Tier Position report was developed to assist customers 22

to better understand the underlying structure of the basic residential rate plan and the relationship 23

between usage and costs. It also may serve to help reduce or prevent any end-of-month bill surprises. 24

SCE’s website presents multiple elements of dynamic data that are updated daily and accessible 24/7. 25

SCE continues to work to help ensure the accuracy and availability of these tools and will continue with 26

its customer engagement efforts in an attempt to maximize customer awareness and increase 27

participation. 28

(3) Budget Assistant 29

Budget Assistant (BA) is a cost management tool for residential and small 30

business customers that leverages the “projected next bill” information to provide customers with 31

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advance notification of how their energy costs are aligning with an established spending target. 1

Customers enroll in the program by (1) setting a desired monthly spending goal; (2) choosing the 2

frequency of when they will receive updates from SCE, either weekly or only when their projected costs 3

are expected to exceed their spending goal; and (3) selecting how they want to receive their updates 4

from SCE, either via text message, e-mail or a phone call. 5

SCE supports customer enrollment in the program through multiple 6

channels. For those customers who choose to enroll online, the enrollment page for BA includes a 7

calculation of customers’ specific average monthly summer and winter bill amounts to assist customers 8

with establishing a relevant spending target. SCE also provides enrollment options for those customers 9

who do not have internet access and/or prefer to call SCE or mail in their enrollment. Once enrolled, 10

customers receive routine updates as to how they are performing against their spending target to avoid 11

future high bill surprises. 12

In 2012, SCE sent out more than seven million messages containing intra-13

bill cycle cost information to enrolled participants. It is reasonable to expect that customers who have 14

enrolled to receive weekly updates may be more inclined to pursue conservation efforts and active bill 15

management, as compared to customers who have selected threshold or “only-when-over” updates that 16

are triggered when the projected next bill is forecast to exceed the spending goal. Because the BA tool 17

provides a forecast of the next bill amount and all future bills as they may relate to the established 18

spending goals, the BA tool adeptly serves as an early warning system to avoid any higher-than-19

expected bills, expanding the value proposition to achieve universal appeal across all customer 20

segments. 21

SCE’s back office systems are maintained to perform the necessary 22

calculations and notifications. As of December 30, 2012, more than 350,000 customers were enrolled to 23

use the BA tool. Of these customers, 44 percent were enrolled in SCE’s income-qualified programs. 24

Other BA program statistics are summarized in Table IV-18 below. 25

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Table IV-18 Budget Assistant Program Statistics

Line No.

Description 2011 2012

1 New Program Enrollments (Gross) 123,603 274,166 2 Notification Preferences - Over Budget Updates 49% 48%3 Notification Preferences - Weekly Updates 51% 52%4 Notification Channel Preference - Email 64% 66%5 Notification Channel Preference - Text 24% 23%6 Notification Channel Preference - Voice 12% 11%7 Income Qualified Enrollments to Total Enrolled n.a. 44%

In 2012, SCE surveyed BA customers about their experience with the tool 1

and asked if it helped them to save energy and money. Survey respondents were highly positive about 2

how aware the BA tool has made them about their energy consumption. Many expressed how they had 3

altered their behavior to try to save energy, and thus money, on their monthly bills. Respondents also 4

highly rated the ease of use and understanding of the information they received from the BA alerts. A 5

summary of this survey is presented in Table IV-19 below. 6

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Table IV-19 Summary of 2012 Budget Assistant User Survey

Line No.

DescriptionScored4 or 5*

1 Signing up was easy 95%

2Since enrolling, I am more aware of my electricity usage

87%

3 Helps me save money 67%

4The "bill-to-date" feature provides me with useful information

87%

5The "projected next bill" feature provides me with accurate information

87%

6 The Budget Assistant alerts are easy to understand 92%

7Since I enrolled, I have gone to SCE.com more frequently to view my usage reports

54%

8 I would recommend Budget Assistant to a friend 85%

* A score of 5 = strongly agree, 1 = strongly disagree.

The survey also included an open-ended question asking how the BA tool 1

helps customers to save money, and the responses received generally fit within seven different 2

categories: promotes behavior change, saves money, raises awareness, provides control, provides 3

opportunity to engage family, no more bill surprises, and encourages online access to view usage data. 4

A small sample of verbatim responses follows: 5

“It has kept me aware of how much electricity I am using so I can try 6 to use less when I am going to go over budget.” 7

“For once in 14 years, I’m knowing how close how far I am stretching 8 my dollars, it was always a wonder waiting for my next bill price tag, 9 love the budget assistant, hardly come to sce online to even check the 10 budget, simple, smart, great idea thanks.” 11

“Extremely helpful when budgeting monthly, retirement income and 12 knowing where we are using the most electricity, so we can change 13 our living habits.” 14

“It has almost become a personal goal for me to see how much I can 15 get below my budget each month. I enjoy the challenge.” 16

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“We are fixed income, and this has really kept me on budget!” 1

SCE will continue to educate customers and promote the use of the tool to 2

better raise awareness of energy costs and enable behavioral changes that can have positive impacts on 3

their next monthly bill. 4

(4) SCE EnergyManager 5

SCE EnergyManager is a web-based application that displays energy and 6

demand data, and provides usage, cost, and billing reporting tools. SCE EnergyManager is offered to 7

customers with demands greater than 200 kW. In our 2012 General Rate Case (A.10-11-015), SCE 8

proposed to offer the suite of tools (daily and monthly data updates) to SCE’s large business customers 9

(>200kW) at no charge and to reduce fees for hourly and quarter-hourly usage data updates. This 10

proposal was adopted in D.12-11-051 and took effect on January 1, 2013. Features and benefits of SCE 11

EnergyManager are shown in Table IV-20. 12

Table IV-20 Features and Benefits Available to Customers through the SCE EnergyManager

Features Benefits • Energy Demand/ Usage (kW, kWh,

kVAR, kVARh, Excess kW/kWh)

• Energy data at 15-minute intervals in the form of charts, graphs, and table formats

• 48 months of historical kWh data in 15 minute intervals

• Service account groupings, such as by region, type of business, etc.

• What-if analysis to estimate the cost of hypothetical changes usage or rates

• Customized frequently used reports

• Printable electronic copies of bills

• Export or print reports, graphs and table

• Track, analyze, and estimate energy cost

and usage

• Identify high and low usage through trend data

• Analyze energy data and determine ways to control and reduce energy usage and costs

• Compare and benchmark cost and usage

• Access billed data before bill arrives

Table IV-21 below summarizes SCE’s EnergyManager usage statistics for 13

the period of 2009-2012. In 2012, the SCE EnergyManager Basic customer base was approximately 14

6,500, which was a two percent decline compared to the 2009 customer base. This decline was due to 15

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service account closures and meters replaced with ESC Meters. As shown in Table IV-21, compared to 1

2011, in 2012, the average number of users per month is up 237 percent, and average number of 2

monthly website hits has increased 43 percent. This significant increase is due to a concerted effort by 3

our Business Customer Division to promote the SCE EnergyManager suite of tools. 4

Table IV-21 SCE EnergyManager Usage Statistics

LineNo. 2009 2010 2011 2012

3 Yr Growth 2009-2012

1 Yr Growth 2011-2012

1 SCE EnergyManager Basic (Free)2 Customer Base (Free Access) 1 6,668 6,571 6,581 6,544 -2% -1%3 Customer Users Per Month 2 331 464 703 2,368 615% 237%4 Average Monthly # of Website Hits 7,925 8,085 13,705 19,598 147% 43%56 Customer Base (Paid Access) 1 1,619 1,521 1,464 1,416 -13% -3%7 Customer Users Per Month 2 306 291 318 421 38% 32%8 Average Monthly # of Website Hits 1,464 1,150 2,615 4,008 174% 53%

Explanatory Notes:

1.

2.

Description

SCE Cost Manager & Bill Manager

Customer Base is defined by unique customers with access to the service (includes service accounts >200kW and some service accounts <200kW).

Customer Users is defined by website hits by unique customers in an average month.

b) Dynamic Pricing 5

In 2012, SCE offered residential and non-residential customers various dynamic 6

pricing programs as described below. 7

(1) Time-of-Use (TOU) Rates 8

SCE has long offered customers a variety of TOU rates. To date, TOU 9

participation has been primarily focused on C&I customers over 200kW who are required to be on TOU 10

rates. Other customers have elected to participate in TOU on an optional basis and were provided TOU-11

capable metering to support their participation in those plans. However, with the completion of the 12

deployment of ESC, interval meters are now installed on virtually all of SCE’s customers’ accounts and 13

enable participation in a TOU plan. 14

In January 2014, SCE will begin transitioning non-residential customers 15

(except agricultural and pumping customers) with demands of less than 200 kW to mandatory TOU 16

plans in compliance with D.13-03-031. Agricultural and pumping customers with demands of less than 17

200 kW will begin to be transitioned to mandatory TOU rates in February 2014. As noted above, the 18

implementation of the mandatory TOU transition was delayed in the 2012 GRC Phase 2 proceeding. As 19

such, in the Base Year, the activities were focused on planning for this significant transition which will 20

impact approximately 600,000 service accounts. Marketing of this program during the Base Year was 21

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limited in anticipation of the upcoming transition. Instead the execution of the marketing campaigns and 1

education and outreach efforts to support this transition will take place primarily in 2013 and 2014. 2

For residential customers, SCE initiated a proactive residential customer 3

outreach campaign in 2011 and 2012, focusing on Tier 5 customers, and those customers participating in 4

the Net Energy Metering rate. A direct mail campaign was launched to provide background and rate 5

comparison information covering the TOU-D-T rate plan (also known as the Residential Off-Peak 6

Savings Plan) and the standard residential rate plan. The direct mail piece was followed up with an 7

outbound calling campaign targeting those customers who did not respond to the mail solicitation. The 8

campaign resulted in an overall TOU-D-T adoption rate of 4.8%. SCE plans to continue its efforts to 9

promote the residential TOU rate plan by expanding the target population to include the identification of 10

customers who may benefit, or come very close to benefiting, from shifting to this rate plan based on 11

their actual electricity usage patterns as will be indicated by the available hourly interval usage data. 12

(2) Critical Peak Pricing (CPP) 13

As noted above, D.12-04-045 directed that dynamic pricing programs that 14

were funded through the DR balancing account not be included in future DR applications and instead are 15

to be included in each utility’s GRC. For SCE, this includes the Critical Peak Pricing (CPP) rates for 16

customers with demand less than 200 kW and greater than or equal to 200 kW. CPP is a tariff that 17

offers eligible participants a discount on monthly on-peak demand charges during the summer months 18

with an increase in energy charges when a CPP event is called. Design of the CPP rates is treated in the 19

GRC Phase 2 proceeding. In this Phase, SCE includes the cost of administering the program, and, in 20

preparation for the implementation of default CPP rates for commercial customers with demands less 21

than 200 kW, education and outreach efforts to inform these customers of the CPP rates. 22

Until the deployment of ESC meters, participation of customers with 23

demands less than 200 kW in CPP was very limited. Indeed, as of the end of 2012, there were only 24

approximately 800 non-residential service accounts with demands less than 200 kW on the CPP rate 25

schedule. SCE’s promotion of this rate during the Base Year was limited in anticipation of the 26

implementation of default CPP within the scope of SCE’s 2012 GRC Phase 2 proceeding. 27

As of the end of 2012, there were approximately 2,400 service accounts 28

with demands greater than or equal to 200 kW on the CPP rate schedule. Customers have the option to 29

leave and receive service under their Otherwise Applicable Tariff (OAT) if they do not wish to remain 30

on CPP. During the Base Year, SCE conducted marketing, education and outreach (ME&O) activities 31

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to (1) continue education and outreach efforts to C&I customer groups who were previously defaulted 1

and remained on CPP, (2) generate program awareness and understanding among customers that might 2

benefit from the program, and (3) develop sales support materials to promote the program and increase 3

enrollment. Funding for these efforts was included in SCE’s Demand Response Application (A.11-03-4

003) and approved in D.12-04-045. 5

(3) Real Time Pricing (RTP) 6

As noted above, D.12-04-045 directed that dynamic pricing programs that 7

were funded through the DR balancing account not be included in future DR applications and instead are 8

to be included in each utility’s GRC. For SCE, this includes the Real-Time-Pricing (RTP) rate. The 9

current RTP rate schedule is a dynamic, TOU pricing tariff for non-residential customers. This tariff 10

charges participants for the electricity they consume based on hourly prices driven by the prior day’s 11

temperature. Participants may adjust their electricity usage based on the hourly prices within different 12

temperature categories, seasons, and days of the week. Design of RTP rates is treated in Phase 2 of this 13

proceeding. In this Phase, SCE includes the cost of administering the program and conducting ME&O 14

activities. 15

As of the end of 2012, 120 customers were enrolled in RTP. During the 16

Base Year, SCE undertook efforts to develop customer awareness through ME&O efforts with the 17

purpose of making RTP easier for eligible customer classes to understand and participate effectively. 18

These ME&O efforts were integrated with SCE’s marketing efforts of other DR programs. Additionally, 19

there were efforts to provide ongoing communications with enrolled customers to help drive retention. 20

c) Customer Service Related Programs 21

In 2012, the Customer Programs function continued to manage the Renewable 22

Tariffs and Interconnection program. Additionally, there were a number of other program development 23

opportunities underway. 24

(1) Renewable Tariffs and Interconnection Programs 25

Customers are increasingly interested in renewable generation, particularly 26

solar energy, as one method of reducing their overall electric costs and reducing greenhouse gas 27

emissions associated with their energy consumption. For most customers, installation of a renewable 28

generation requires that they complete a Net Energy Metering (NEM) tariff application and 29

Interconnection application. SCE’s Distributed Generation Programs organization performs a number of 30

activities to support this process. First, this organization provides education and training by using both 31

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printed and electronic informational materials, hosting training classes for contractors, and responding to 1

direct customer inquiries. Once the customer completes an application, SCE’s Distributed Generation 2

Programs organization reviews the NEM Interconnection application to verify the eligibility of the 3

customer and proposed generating facility, secures an interconnection agreement from the customer, and 4

verifies the customer’s building permit for the generating facility prior to approving the customer’s 5

application.23 This group also processes customer applications to enroll in the Net Surplus 6

Compensation and Option R. 7

Following the successful installation of a customer’s renewable generation 8

facility, this organization also helps to respond to NEM customer questions regarding billing, energy 9

credits, and other tariff and/or interconnection related issues. This group also compiles Commission-10

mandated reporting related to the NEM tariff. 11

As shown in Table IV-22, the number of NEM applications SCE has 12

received has grown significantly since 2008. Over this period, the growth in the number of NEM 13

applications received has averaged over 50% per year. Indeed, the number of applications received 14

nearly doubled in 2012 compared to 2010. To help address this growth, SCE implemented continuous 15

improvement initiatives, including migrating to a paperless electronic submittal and filing system in 16

order to reduce application processing cycle time. 17

In addition to this growth in NEM application activity, the complexity of 18

the administration of the NEM Tariffs has grown over the past few years with the introduction of the Net 19

Surplus Compensation option in 2011. 20

Table IV-22 Net Energy Metering (NEM) Applications Received by SCE

(2008-2012)

Line No.

Description 2008 2009 2010 2011 2012

1 NEM Applications Received 3,009 4,707 7,962 14,981 15,896

23 Customers’ interconnection applications are also reviewed by SCE’s Electric System Planning group in the Transmission

and Distribution Operating Unit.

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d) Other Programs and Services 1

Base Year activities also included the assessment of additional billing and 2

payment options for customers. SCE’s Prepayment Option, described in Exhibit SCE-04, Volume 2, is 3

another example of an option developed to help customers become more proactive in managing their 4

energy consumption. The prepay option was developed to allow customers to pay for their electric 5

service in advance, thus allowing them to avoid paying a deposit in most circumstances. In addition to 6

benefits to participating customers, SCE anticipates that the program will result in a reduction in bad 7

debt expense and billing and postage savings. These benefits will be partially offset by increased 8

notification, payment processing, and call volume costs. 9

In addition, technologies enabled through the HAN became available to 10

customers. To support this availability, CP&S coordinated with the Customer Service Operations 11

Division to help ensure that the appropriate processes and procedures were in place to support customer 12

adoption of this technology.24 13

3. Analysis of Historical Data (FERC Account 908.640) 14

The recorded/adjusted costs for Customer Rates and Programs activities are shown in 15

Table IV-23 below and were derived after analyzing recorded costs for this activity and adjusted to 16

reflect ongoing business operations. The various accounting, operational, and reclassification 17

adjustments are discussed in the workpapers supporting this Volume. In addition, the ratemaking 18

adjustments are discussed in Exhibit SCE-10 Results of Operations testimony. 19

24 The costs associated with the activities described in this section were recorded in and recovered through the ESC

Balancing Account (ESCBA). In accordance with the ESC Deployment Decision, certain ESC steady state costs were recorded to the ESCBA. For the purposes of this GRC forecast, SCE has adjusted its recorded O&M costs to reflect ESC steady state costs and includes those steady state activities in its description of Base Year operating results.

72

Table IV-23 Customer Programs and Rates

Recorded/Adjusted Expenses (2008-2012) FERC Account 908.640


Line No.

Customer Programs and Rates

2008 2009 2010 2011 2012

1 Labor Expense 1,242 1,729 2,466 2,534 2,116 2 Non-Labor Expense 165 893 686 2,708 3,468 3 Other - - - - - 4 Total Operation Expense 1,407 2,622 3,152 5,242 5,584

In 2009, the operating expenses for Customer Programs and Rates increased over 2008 1

by $487,000 in labor expenses due to increased levels of NEM enrollment activities and support for 2

ESC.25 Non-labor costs in 2009 also increased by $728,000 due to increased systems expenses 3

associated with the implementation of default CPP for customer with demands greater than or equal to 4

200 kW, the development of EnergyManager system enhancements, and increased NEM enrollment 5

activities.26 6

In 2010, labor costs increased by $737,000 due to a number of factors, including 7

increased levels of NEM enrollment activities, increased ESC steady state costs, and increased CPP and 8

RTP program management costs. Non-labor expenses in this period decreased by $207,000 due to a 9

reduction in development costs associated with CPP. 10

In 2011, labor costs remained relatively stable while non-labor costs increased by $2.022 11

million due to a number of factors, including an increase Budget Assistant marketing efforts and NEM 12

enrollment activities. 13

In 2012, labor costs decreased by $418,000 due to a reduction in EnergyManager costs 14

and unfilled vacancies. Non-labor costs increased in 2012 by $760,000 due primarily to increases in 15

marketing expenses for TOU marketing for residential and small business customers. 16

25 Although ESC costs were recovered through the ESC Balancing Account (ESCBA), certain costs have been identified as

steady state costs and included in O&M recorded costs as an adjustment.

26 As noted above, in D.12-04-045 the Commission directed that dynamic pricing programs (CPP and RTP) be included in future GRC filings. Accordingly, although the historical costs for these programs were recovered through the Demand Response balancing account, they are included in the O&M recorded costs in this proceeding as an adjustment.

73

4. Customer Programs Test Year Expectations (FERC Account 908.640) 1

Figure IV-6 shows the recorded/adjusted historical and forecast expenses for the 2

Customer Programs and Rates function. Details regarding the forecast O&M expenses for this function 3

are described below. 4

Figure IV-6 Customer Programs and Rates

FERC Account 908.640 (Constant 2012 $000s)

a) Determination of Test Year Estimating Method 5

As shown in Table IV-23 above, SCE recorded $5.584 million for these activities 6

in the Base Year. Overall, labor and non-labor expenses have generally shown an increasing trend over 7

the past five years. Although labor expenses decreased in 2012 when compared to 2011 by $418,000, 8

the most recent year accurately reflects expense level associated with current activities, 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

b) Customer Programs Test Year Expectations 12

SCE’s Test Year forecast for FERC Account 908.640 includes non-labor 13

adjustments totaling $1.071 million. These adjustments are necessary to implement Dynamic Pricing 14

74

rates as adopted by the Commission in D.13-03-031 and address the continued growth and complexity in 1

the administration of the NEM tariff. 2

(1) Implementation of Dynamic Pricing 3

During the preparation of SCE’s 2012-2014 Demand Response 4

Application, SCE expected that default CPP was going to be implemented in the 2012 timeframe. 5

Funding to support this transition was requested in A.11-03-003 and approved in D.12-04-045. 6

However, in D.13-03-031, the Commission revised the timeline for default CPP and instead ordered that 7

small (GS-1) and medium (GS-2) non-residential service accounts be defaulted to CPP rates beginning 8

on January 1, 2016. Therefore, minimal expenses were incurred for default CPP in the 2012 timeframe 9

and the funding request to support the transition is being requested in this application. 10

SCE estimates that approximately 600,000 service accounts will be 11

impacted by this default. This will be a significant transition for customers, and an extensive customer 12

education and outreach plan is needed to effectively support this transition. In order to minimize the 13

confusion around the new pricing plan and encourage behavioral change that helps customers benefit 14

from the rate, customers must be aware that they are on a new rate, how the rate works, and what actions 15

they can take to benefit from the rate/minimize its impact on them. To educate these impacted 16

customers, SCE will communicate to this highly diverse group of customers in a simple understandable 17

manner through a mix of channels and in multiple languages. 18

In 2015, prior to the default of these customers to CPP, SCE will 19

communicate key information to customers, including their options. Pre-default communications will 20

emphasize that the CPP program does include a full year of bill protection for the first year of 21

participation. To encourage participation, SCE’s communications will help them better understand the 22

cost impacts to their future bills by including a customized rate analysis. This analysis is intended to 23

reveal potential bill impacts arising from future CPP participation based on the customer’s historical 24

usage, along with information on how changes in usage behavior can help to maximize incentives. 25

Another objective of the pre-default communications will be to obtain 26

current customer contact information for day-ahead event notification purposes. Because the CPP rate 27

structure includes increased energy charges during a CPP event period, it is important that customers 28

receive notification about the event in time to decide whether to make operational adjustments on the 29

following event day. 30

75

SCE’s program allows customers to enroll in event notification services, 1

which lets them select a preferred contact number/method (text messaging, voicemail, or e-mail). If a 2

customer does not provide a notification preference, SCE will rely on its existing telephone contact 3

information stored in its Customer Service System. However, this information may not be accurate for a 4

large percentage of these customers. This is because customer contact information is collected at the 5

time customers turn on electric service and is typically updated only if customers proactively contact 6

SCE and/or if customers update the information when/if they access their personal online information 7

on SCE’s website. The contact information collected at the time of turn-on for many of the business 8

accounts also may not be the appropriate contact to receive CPP event notifications. SCE anticipates 9

that multiple communications may be required to collect the appropriate contact information. After the 10

implementation, SCE plans to do follow-up communications to confirm rate changes and remind 11

customers of the actions they must take to maximize the benefits of participation in the CPP program. 12

Additionally, SCE will remind customers when their bill protection periods are about to end. Finally, 13

throughout the transition, SCE plans to perform market research. Research objectives will include 14

validating (1) program default messaging, (2) usefulness and understandability of rate analysis, and (3) 15

preferred methods of communication. 16

Second, SCE requests funding necessary to implement and execute CPP 17

event notification measures. In order to provide event notifications, SCE will leverage multiple 18

communication channels including automated voicemail, text messaging, and e-mail to inform 19

customers of CPP events on a day-ahead basis. Day-ahead notification of events is essential to provide 20

customers with ample opportunity to plan for CPP events. 21

Finally, SCE plans to increase marketing of Real Time Pricing (RTP) rate. 22

Prior to April 2013, RTP was available only for large non-residential customers with demands greater 23

than 500 kW. Beginning in April 2013, the RTP rate is available to all non-residential customers.27 24

SCE plans to increase its ME&O activities in order to develop customer awareness with the goal of 25

making the RTP easier for all customer classes to understand and participate in effectively. 26

In order to support the implementation of Dynamic Pricing as described 27

above, SCE forecasts an incremental $825,000 in the Test Year. 28

27 See D.13-03-031, Ordering Paragraph 3, Attachment C (Small Commercial and Industrial Customer Rate Design

Settlement Agreement) p. 13; Ordering Paragraph 4, Attachment D (Medium and Large Commercial Customer Rate Design Settlement Agreement) p. 17.

76

(2) Renewable Tariffs and Interconnection Programs 1

As described in Section 2.c)(1) above, the number of NEM applications 2

processed by SCE has grown an average of over 50% per year since 2008. Although SCE has 3

implemented process improvement initiatives that have resulted in improved cycle times, these 4

improvements have not been able to offset the growth in the number of applications processed. In 5

addition to this growth in application activity, the administration of NEM tariffs has grown over the past 6

few years with the introduction of the Net Surplus Compensation option in 2011, Option R in 2012, and 7

the expected implementation of Solar Renewable Credits (SRECs) beginning in 2013 or 2014. 8

SCE expects that customer interest in the NEM tariff will continue to grow 9

throughout this GRC period as SCE customers continue to be interested in and install renewable energy 10

generation systems. While SCE expects that process improvements can help offset a portion of this 11

growth, SCE forecasts that the non-labor O&M expenses to accommodate this growth in NEM tariff 12

administration activities will increase by ten percent per year throughout this GRC period resulting in an 13

increase of $246,000 in the Test Year. 14

c) Summary of FERC Account 908.640 Forecast 15

The forecast adjustments necessary to support the implementation of Dynamic 16

Pricing and growth in NEM administration activities described above total $1.071 million. These 17

adjustments result in a Test Year forecast of $6.655 million for FERC Account 908.640. Figure IV-7 18

shows the Test Year forecast for FERC Account 908.640 compared to the Base Year. 19

77

Figure IV-7 Customer Programs and Rates

Comparison of 2012 Base Year to 2015 Test Year FERC Account 908.640 (Constant 2012 $000s)

$5,584

$1,071 $6,655

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

2012 Recorded Program Changes 2015 Forecast

78

V. 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 and generally span 4

across multiple functional areas. These costs are recorded in FERC Account 907.600 and include the 5

cost of 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, and 9

Regulatory and Tariff Program Support. 10

These activities are described in the following sections. 11

1. Finance and Administration 12

a) Description of Finance and Administration Functions 13

Customer Service Finance and Administration is responsible for the Customer 14

Service Operating Unit’s budgets, accounting, financial performance reporting, financial planning and 15

analysis, internal controls, employee space planning, timekeeping, position maintenance, and payment 16

processing. These activities are described below. 17

(1) Planning and Performance Reporting 18

The Planning and Performance Reporting group is responsible for 19

providing budgeting, accounting, forecasting, reporting, financial planning, and analytical support to all 20

the operational divisions within the Customer Service organization. This group prepares, monitors, and 21

reports budgets for Other Operating Revenue (OOR), Operations and Maintenance (O&M), and Capital 22

Expenditures of the Customer Service Operating Unit. They work closely with the operating divisions, 23

providing staff support so that essential cost management processes are effective within the operational 24

divisions. They also monitor expense reporting on a routine basis through the corporate accounting 25

system and process accounting corrections as necessary. The group prepares detailed budget variance 26

reports including year-end budget forecasts. 27

The Planning and Performance Reporting group works with Customer 28

Service project managers to help ensure that proper accounting is established for all programs and 29

services that Customer Service provides to customers. In addition, they are also responsible for the 30

Customer Service Operating Unit’s project-specific financial analysis. Project analysis involves 31

79

gathering and analyzing cost and operational data for proposed and ongoing projects to determine cost-1

effectiveness. Performing these activities allows Customer Service management to have consistent and 2

accurate evaluations of the financial effects of the projects and programs delivered by Customer Service. 3

(2) Regulatory Finance and Long-Term Planning 4

The Regulatory Finance and Long-Term Planning group is responsible for 5

preparing, leading, and directing others across Customer Service in the preparation of financial forecasts 6

and other information as they relate to the development of testimony and workpapers for the General 7

Rate Case and FERC filings. Also, the group leads the effort in providing historical data analyses and 8

researching regulatory issues. Furthermore, the group provides support in witness preparation and data 9

request responses on behalf of Customer Service. In addition to managing regulatory matters, the group 10

leads a cross-functional team effort in the annual benchmarking on behalf of Customer Service. 11

(3) Internal Controls 12

Internal Controls is responsible for assisting Customer Service 13

management in fulfilling its responsibilities regarding the adequacy and effectiveness of the system of 14

internal controls within the organization by responding to management’s requests concerning internal 15

control issues, providing input on controls in new or changing areas, reviewing the effectiveness of 16

existing control processes within the organization; performing management testing of Sarbanes-Oxley 17

controls, coordinating Customer Service’s response to Enterprise Risk Management activities, and 18

coordinating with other audit entities to minimize duplication of effort. The Internal Controls group is 19

also responsible for coordinating Customer Service’s involvement in and compliance with the corporate 20

Business Continuity and Resiliency efforts associated with ensuring the timely return to business in the 21

event of natural disaster. 22

(4) Timekeeping 23

The timekeeping organization is responsible for conducting a variety of 24

compensation-related activities for the Customer Service Operating Unit. On a bi-weekly basis, the 25

group processes Customer Service employee timesheets in coordination with the Corporate Payroll 26

department. In addition, this group maintains employee personnel records; handles daily inquiries from 27

Customer Service; performs required maintenance for employee positions, organizational changes, and 28

personnel change requests; requisitions off-cycle employee paychecks; perform payroll adjustments; 29

coordinates the annual performance evaluation process; and provides ad hoc reports concerning vacation 30

time and absence histories. 31

80

(5) Payment Processing 1

The Payment Processing group is responsible for conducting a variety of 2

activities to support the Customer Service Operating Unit. The group works with Corporate Accounts 3

Payable to help ensure appropriate reviews and processes are followed for all external vendor invoices, 4

and provide assistance with purchase orders from management personnel requesting new equipment or 5

services. This group also completes monthly reconciliations of business travel activities and other credit 6

card transactions; processes system access requests; and administrates business-level policies regarding 7

computing tools, employee expenses, and approval authorization matrices. 8

2. Business Planning 9

a) Description of the Business Planning Function 10

A function of the Business Planning group is to develop the Customer Service 11

Operating Unit’s Business Plan, which sets operational unit priorities and key areas of focus over a 12

rolling five-year period, refreshed annually. This plan sets forth Customer Service’s mission, values, 13

performance goals and objectives, and actions to be taken to achieve our Customer Service objectives. 14

It also describes the necessary coordination between Customer Service and other SCE departments. The 15

plan is used to inform Customer Service employees about the Operating Unit and corporate goals and 16

help them understand how their individual contributions help support these goals to provide high-quality 17

customer service. 18

A critical part of the business planning process is to ensure that the business plan 19

can be implemented and results can be measured. Business Planning monitors Customer Service’s 20

progress and performance on goals, objectives, and action items identified in the plan. Performance 21

updates on progress toward meeting goals are regularly provided to management and Customer Service 22

employees. 23

Business Planning also provides a variety of organizational management and 24

resource planning-related support for Customer Service. Such functions include facilitation of Customer 25

Service leadership and management meetings; internal communication of Customer Service policies, 26

goals, and objectives; maintenance of organizational charts and payment approval matrices; processing 27

access orders; credit card expense reconciliation; and facilitation of management approval for employee 28

onboarding. 29

This group also regularly performs a variety of other specialized staff support 30

activities. Examples include providing project management and analytical support for customer service-31

81

wide Operational Excellence efforts, leading development of Customer Service staffing forecast needs, 1

and managing Customer Service participation in corporate-wide planning efforts. 2

3. Customer Service Regulatory and Tariff Program Support 3

a) Description of the Regulatory and Tariff Support Function 4

The Regulatory group supporting Customer Service is responsible for maintaining 5

and monitoring Customer Service’s compliance with regulatory and legislative mandates, rules, and 6

standards. This group is also responsible for providing regulatory support to Customer Service for all 7

CPUC- or SCE-initiated regulatory efforts or proceedings. Specific activities include preparing 8

Customer Service-specific portions of regulatory filings and monitoring compliance of Commission 9

compliance commitments. Recent examples of the proceedings include Smart Grid OIR, Residential 10

Rate OIR, Distributed Generation OIR, Smart Meter Opt-Out, Smart Grid Deployment Plan, and various 11

cost recovery proceedings such as the GRC, ERRA, and ESPI Application (A.12-03-004). Compliance 12

activities of the group include Affiliate Transactions, Essential Use, and Service Guarantee programs. 13

The group also coordinates the input of other Customer Service employees in the Commission, 14

California Energy Commission, and legislative processes. 15

The Tariff Program Support group is responsible for the management oversight of 16

special contract or nonstandard pricing options and provides rotating outage project management 17

support. These activities address more complex rate options such as SCE’s Base Interruptible Program 18

or CPP rate options, which require involved implementation and interpretation issues. 19

B. Operating Unit Management and Support Base Year Operating Results 20

1. Summary of Recorded Costs (FERC Account 907.600) 21

In 2012, SCE recorded a total of $6.809 million in O&M expenses for Operating Unit 22

Management and Support with recorded labor expenses of $4.080 million, and non-labor expenses of 23

$2.729 million. 24

2. Analysis of Historical Data (FERC Account 907.600) 25

The recorded/adjusted costs shown in Table V-24 below were derived after analyzing 26

recorded costs for this activity and adjusting them to reflect ongoing business operations. The various 27

accounting, operational, and reclassification adjustments are discussed in the workpapers for this 28

Volume. The ratemaking adjustments are discussed further in Exhibit SCE-10, Results of Operations 29

testimony. 30

82

Table V-24 Operating Unit Management and Support Recorded / Adjusted Expenses (2008-2012)

FERC Account 907.600 (Constant 2012 $000)

Line No.

Operating Unit Management and Support

2008 2009 2010 2011 2012

1 Labor Expense 4,348 3,933 4,073 4,066 4,080 2 Non-Labor Expense 3,182 2,997 3,557 3,252 2,729 3 Other - - - - - 4 Total Operation Expense 7,530 6,930 7,630 7,318 6,809

Recorded operating expenses for the Operating Unit Management and Support function 1

have fluctuated over the historical period. In 2009, labor expenses declined by $415,000 due to a 2

reduction in Tariff Program support activities. Since 2009, labor expenses in FERC Account 907.600 3

have remained relatively stable with a slight increase in 2012 due to increased business planning and 4

regulatory support activities. In 2009, non-labor expenses declined by $185,000 due to a reduction in 5

employee development activities and contract labor expenses. In 2010, non-labor expenses increased by 6

$560,000 due primarily to increased contract staffing to support various regulatory activities, including 7

the development of SCE’s 2012 GRC. In 2011, non-labor expenses decreased by $305,000 due to a 8

reduction in regulatory support contractor costs and a reduction in facility-related expenses. In 2012, 9

non-labor expenses declined by $523,000 primarily due to a reduction in employee related expenses, 10

including training and employee development activities and a reduction in corporate overhead 11

allocations. 12

C. Operating Unit Management and Support Test Year Expectations 13

(FERC Account 907.600) 14

Figure V-8 shows the recorded/adjusted historical and forecast expenses for the Operating Unit 15

Management and support function (FERC Account 907.600). Details regarding the forecast O&M 16

expenses for this function are described below. 17

83

Figure V-8 Operating Unit Management and Support

FERC Account 907.600 (Constant 2012 $000s)

1. Determination of Test Year Estimating Methodology 1

The 2012 Base Year activities for the Operating Unit Management and Support functions 2

are described above. In 2012, we recorded $6.809 million for these activities, and the recorded/adjusted 3

history for this functional group is shown in Table V-24. Labor and non-labor expenses for this activity 4

have been relatively stable over the most recent five-year period. Therefore, the Last Recorded Year 5

was selected as the base for our 2015 Test Year Forecast. Additionally, the most recent year accurately 6

reflects expense levels associated with current activity levels. 7

2. Test Year Adjustments 8

The Test Year forecast for FERC Account 907.600 is shown in Figure V-8 and includes a 9

reduction of $653,000 associated with operational excellence improvements SCE expects to achieve as a 10

result of consolidating and implementing process improvements in the finance function. Figure V-9 11

shows the Test Year forecast for FERC Account 907.600 compared to the Base Year. 12

84

Figure V-9 Operating Unit Management and Support

Comparison of 2012 Base Year to 2015 Test Year FERC Account 907.600 (Constant 2012 $000s)

$6,809$653

$6,156

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

2012 Recorded Operational Excellence 2015 Forecast

Appendix A

Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF LISA D. CAGNOLATTI 3

Q. Please state your name and business address for the record. 4

A. My name is Lisa D. Cagnolatti, and my business address is 6020 N. Irwindale Avenue, 5

Irwindale, California 91702. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Vice President of the Business Customer Division of the Customer Service Operating 8

Unit. In this role, I am responsible for managing and directing a business division focused on 9

delivering energy efficiency solutions, account management services and customer care for all of 10

SCE’s commercial, industrial, agricultural and government customers. 11

Q. Briefly describe your educational and professional background. 12

A. I hold a Bachelor of Science degree in Chemical Engineering from UCLA and an MBA from 13

Pepperdine University. I have over 28 years of experience in the utility industry including 14

positions of increasing responsibility in Marketing, Environmental Affairs, Regulatory Affairs, 15

Transmission and Distribution, and Customer Services. 16

Q. What is the purpose of your testimony in this proceeding? 17

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-04, 18

Volume 3, entitled Customer Service – Customer Service and Information Delivery, as identified 19

in the Table of Contents thereto. 20

Q. Was this material prepared by you or under your supervision? 21

A. The above-referenced testimony was prepared at the direction of Kenneth Devore. I have 22

reviewed this testimony carefully and in consultation with Mr. Devore and others who assisted in 23

its original preparation. I adopt and sponsor this testimony as my own. 24

Q. Insofar as this material is factual in nature, do you believe it to be correct? 25

A. Yes, I do. 26

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 27

judgment? 28

A. Yes, it does. 29

Q. Does this conclude your qualifications and prepared testimony? 30

A-2

A. Yes, it does. 1

A-3



OF KENNETH W. DEVORE 3


A. My name is Kenneth W. Devore, and my business address is 6042 N. Irwindale Avenue, 5

Irwindale, CA 91702. 6


A. I am the Director of Account Management Support and Technical Services in the Business 8

Customer Division of the Customer Service Operating Unit. In this role, I direct the activities of 9

senior managers and project managers, field engineers, rate analysts, and technical specialists 10

who deliver energy efficiency solutions, account management services and customer care for 11

SCE’s commercial, industrial, agricultural, and institutional customers. 12


A. I hold a Bachelor of Arts degree in Communications from California State University, Fullerton, 14

and a Masters in Business Administration from the University of La Verne. I have over 24 years 15

of experience in the utility industry, including positions of increasing responsibility in 16

Communications, Regulatory Policy and Affairs, Transmission and Distribution, and Customer 17

Service. From 2008 to 2013, I served as the Director of Edison SmartConnect and led SCE’s 18

smart metering program. I assumed my current position in the Business Customer Division in 19

April of 2013. Prior to joining SCE, I held senior management positions in communications and 20

human resources with the Vons Companies, Inc. 21




in the Tables of Contents thereto. 25


A. Yes. 27


A. Yes, I do. 29

A-4


judgment? 2

A. Yes, it does. 3


A. Yes, it does. 5

A-5



OF JESSICA LIM 3


A. My name is Jessica Lim, and my business address is 1515 Walnut Grove Avenue, Rosemead, 5

California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE). 7

A. I am the Manager of Offer Management and Marketing in the Customer Programs and Services 8

division of Southern California Edison. In this role, I am responsible for SCE’s marketing and 9

communications associated with Customer Service programs, rates and services. 10


A. I completed a Bachelor’s degree in Administrative Studies from U.C. Riverside in 1992 with 12

emphasis in business administration and marketing. I completed the Masters of Science in 13

Leadership and Management program through the University of La Verne in January 2013. I 14

have worked at SCE for approximately eight years in Customer Service. Prior to my current 15

function which I described above, I was the Manager of Planning, Performance, and Integration 16

in the Customer Service Operating Division for approximately two years. Prior to that position, I 17

was the Manager of Customer Strategy in Customer Experience and Management for 18

approximately five years. Prior to SCE, I have over 10 years of experience in business working 19

in disciplines such as advertising, marketing, and e-commerce for a variety of profit and not for 20

profit organizations and clients. 21



Volume 2, entitled Customer Service – Customer Service Operations and portions of Volume 3, 24

entitled Customer Service – Customer Service and Information Delivery, as identified in the 25

Table of Contents thereto. 26


A. Yes, it was. 28


A. Yes, I do. 30

A-6


judgment? 2

A. Yes, it does. 3


A. Yes, it does. 5

A-7

SOUTHERN CALIFORNIA EDISON COMPANY

QUALIFICATIONS AND PREPARED TESTIMONY

OF CARTER PRESCOTT


A. My name is Carter Prescott, and my business address is 2244 Walnut Grove Avenue, Rosemead, 2

California 91770. 3


A. I am the Principal Manager of Financial Analysis and Reporting, in the Financial and 5

Operational Services Organizational Unit. In this role, I have responsibility for budgeting, 6

planning, reporting, and financial analysis supporting the Customer Service Organization Unit. 7


A. I hold a Bachelor of Science Degree in Business Management and Accounting from the 9

University of Phoenix. I completed the Management Program in 2006. I have worked for 10

Southern California Edison for over ten years with increasing responsibilities in various financial 11

analysis, financial management and regulatory finance positions. 12



Volume 1, entitled Customer Service – Policy; portions of Exhibit SCE-04, Volume 2, entitled 15

Customer Service – Customer Service Operations; and portions of Exhibit SCE-04, Volume 3, 16

entitled Customer Service – Customer Service and Information Delivery, as identified in the 17

Table of Contents thereto. 18


A. Yes, it was. 20


A. Yes, I do. 22


judgment? 24

A. Yes, it does. 25


A. Yes, it does. 27

A-8

SOUTHERN CALIFORNIA EDISON COMPANY


OF THOMAS M. WALKER 2


A. My name is Thomas M. Walker, and my business address is 2244 Walnut Grove Avenue, 4

Rosemead, California 91770. 5

Q. Briefly describe your present responsibilities at Southern California Edison Company (SCE). 6

A. I am the Director of the New Program Development and Launch group within Customer Service. 7

I have the responsibility for the identification, evaluation, development and launch of new 8

customer programs. 9


A. I received my B.A. degree in Economics from University of Redlands in 1991. I have worked 11

for Southern California Edison for over 15 years. I have held positions in Business Integration, 12

the Phone Center, Billing, QF Contracts, Information Systems, Direct Access, Credit and 13

Payment Services, ERP and Edison SmartConnect. I have also held consulting positions and 14

worked for a large internet provider focusing on implementing projects in large billing systems. 15




in the Table of Contents thereto. 19


A. Yes, it was. 21


A. Yes, I do. 23


judgment? 25

A. Yes, it does. 26

A-9


A. Yes, it does. 2

Customer Service Volume 3 - Customer Service and ......SCE-04: Customer Service Volume 03 - Customer Service and Information Delivery Table Of Contents (Continued) Section Page Witness

Documents

Customer Service Volume 3 - Customer Service and ......SCE-04: Customer Service Volume 03 - Customer Service and Information Delivery Table Of Contents (Continued) Section Page Witness