Information Technology (IT) Volume 2, Part 1 – Capitalized ......Summary Information Technology Operating Unit’s (IT) request includes support for a total of $986.05 million of

Application No.: Exhibit No.: SCE-05, Vol. 02, Pt. 1 Witnesses: J. Bubb

C. Carazo J. Castleberry G. Haddox C. Hu G. Huckaby J. Kelly L. Miller R. Park J. Pespisa J. Shotwell J. Tran

(U 338-E)

2015 General Rate Case

Information Technology (IT) Volume 2, Part 1 – Capitalized Software

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

Summary

Information Technology Operating Unit’s (IT) request includes support for a total of

$986.05 million of capitalized software expenditures for the forecast period 2013-2017.

Operating Software is primarily used to manage and monitor the health of mainframe

servers, midrange servers, storage, and personal computers.

Information Security requests are for requirements to protect critical SCE systems and

sensitive information from cyber attacks and thefts.

Our Expanded Capabilities help implement the technology to develop, run, maintain and

expand services, primarily in the Software-as-a-Service and Development/Platform-as-a-

Service categories.

NERC CIP request is to develop and implement systems and processes that will help

ensure that SCE sustains compliance with NERC’s mandated set of Cyber Security Critical

Infrastructure Protection standards.

Also included are 39 specific capitalized software projects from SCE’s other Operating

Units. Our review and prioritization of our requests ensure that these are the projects most

beneficial to our ratepayers.

SCE-05: Information Technology Volume 2, Part 1 – Capitalized Software

Table Of Contents

Section Page Witness

-i-

I. OPERATING SOFTWARE ..............................................................................1 C. Carazo

A. Background ............................................................................................1

B. Business Requirements ..........................................................................1

C. Recorded and Forecast Expenditures .....................................................2

D. Recorded Expenditures ..........................................................................2

E. Forecast Expenditures ............................................................................3

F. Conclusion .............................................................................................4

II. CYBERSECURITY AND IT COMPLIANCE .................................................6 G. Haddox

A. Introduction ............................................................................................6

B. Information Security ..............................................................................8

1. Background ................................................................................8

2. Business Requirements ............................................................10

a) Perimeter Defense ........................................................10

b) Interior Defense ...........................................................12

c) Data Protection.............................................................13

d) Common Cybersecurity Services .................................14

e) Solutions for Emerging Legislative Mandates ......................................................................15

3. Recorded and Forecast Expenditures .......................................18

a) Perimeter Defense Expenditures ..................................18

b) Interior Defense Expenditures .....................................20

c) Data Protection Expenditures ......................................23


Table Of Contents (Continued)


-ii-

d) Common Cybersecurity Services (CCS) Expenditures ................................................................26

e) Solutions for Emerging Legislative Mandates Expenditures ................................................27

4. Analysis....................................................................................29

a) Alternatives Considered ...............................................29

5. Conclusion ...............................................................................29

C. SONGS Cybersecurity .........................................................................30

1. Background ..............................................................................30



4. Analysis....................................................................................33

5. Conclusion ...............................................................................33

III. REGULATORY MANDATES .......................................................................34

A. NERC CIP Compliance .......................................................................34

1. Purpose .....................................................................................34

2. Scope ........................................................................................35

3. Request Summary ....................................................................36


a) Detailed NERC mandated Business Requirements ...............................................................37

b) Program Approach .......................................................40


6. Conclusion ...............................................................................44




-iii-

IV. EXPANDED CAPABILITIES ........................................................................46

A. Service Management System ...............................................................46 C. Carazo

1. Background ..............................................................................46



a) Recorded Expenditures ................................................47

b) Forecast Expenditures ..................................................48

4. Conclusion ...............................................................................48

B. Enterprise Data Management Services ................................................49 J. Kelly

1. Data Masking and Subsetting Project ......................................49

a) Background ..................................................................49

b) Business Requirements ................................................50

(1) Problem Statement ...........................................50

(2) Recommended Approach .................................50

c) Recorded and Forecast Expenditures ...........................52

d) Conclusion ...................................................................53

C. Shared Enterprise Integration Services and Upgrades .........................53

1. Integration Product Refresh and Upgrade Deployments ............................................................................53

a) Background ..................................................................53







-iv-


d) Conclusion ...................................................................56

D. Data Warehouse Upgrades ...................................................................57

1. SAP Business Warehouse (BW) HANA Enterprise Data Warehouse Upgrades .......................................................57

a) Background ..................................................................57





d) Conclusion ...................................................................58

E. Business Intelligence ...........................................................................59

1. Business Intelligence Tools Upgrade Refresh .........................59

a) Background ..................................................................59





d) Conclusion ...................................................................61

F. Business Analytics ...............................................................................62

1. Business Analytics ...................................................................62

a) Background ..................................................................62





-v-




d) Conclusion ...................................................................65

G. Data Archiving Project ........................................................................65

1. Data Archiving .........................................................................65

a) Background ..................................................................65





d) Conclusion ...................................................................68

H. Enterprise Platform Core Refresh ........................................................68 J. Castleberry

a) Background ..................................................................68

(1) Finance .............................................................69

(2) Human Capital Management ...........................69

(3) Supply Chain Management ..............................69

(4) Enterprise Asset Management .........................70

(5) Analytics and Reporting ..................................70

(6) Customer Relationship Management (CRM) ..............................................................70

(7) Governance, Risk and Compliance ..................71

(8) NetWeaver and SAP NetWeaver Process Integration (SAP PI) ...........................71




-vi-





d) Conclusion ...................................................................73

V. PROJECTS LESS THAN $1 MILLION .........................................................75

A. List of projects .....................................................................................75

B. Brief justification .................................................................................75

VI. ORG UNIT SOFTWARE PROJECTS ............................................................76

A. Proposed Capitalized Software Projects ..............................................76

B. Safety, Security & Compliance ............................................................77

1. Master Access Project ..............................................................77 J. Pespisa

a) Background ..................................................................77



d) Conclusion ...................................................................80

C. Financial Services ................................................................................80 G. Huckaby

1. Financial Accounting Standards Board Lease Project ......................................................................................80

a) Background ..................................................................80



d) Conclusion ...................................................................83




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2. Tax Department Repairs Project ..............................................83

a) Background ..................................................................83



d) Conclusion ...................................................................85

D. Corporate Center (Formerly Operations Support) ...............................85

1. CCURE Upgrade .....................................................................85 G. Haddox

a) Background ..................................................................85



d) Alternatives Considered ...............................................88

e) Conclusion ...................................................................88

2. Integrated Work Management System/CAD/CAFM System Upgrade .......................................................................89 R. Park

a) Background ..................................................................89


(1) Strategic Master Planning ................................90

(2) Work Management...........................................90

(3) Facility Asset Management ..............................91

(4) Facility Condition Index ..................................91

(5) Sustainability....................................................92

c) Recommended Approach .............................................92

d) Forecast Expenditures ..................................................93




-viii-

e) Conclusion ...................................................................94

3. Enterprise Compliance Management System ..........................95 J. Shotwell

a) Project Overview .........................................................95


c) Implementation Schedule.............................................96

d) Recorded and Forecast Expenditures ...........................97

e) Conclusion ...................................................................98

4. Electronic Document Management/Records Management .............................................................................98

a) Background ..................................................................98


(1) eDMRM Benefits Over Alternatives .............101

(2) Additional Benefits ........................................102

c) Implementation Overview .........................................103

d) Key Steps of Implementing Project ...........................103

(1) Basic Document/Records Management ...................................................103

(2) Public Safety ..................................................103

(3) External Access Collaboration .......................104

(4) Auto-Classification Proof of Concept ............104

(5) Email Management ........................................104

(6) Engineering Drawing Management ...............104

(7) Company-wide Library Implementation ..............................................104




-ix-

e) Forecast Expenditures ................................................105

(1) Cost Reasonableness ......................................105

(2) Forecast Cost by Year ....................................106

f) Conclusion .................................................................106

E. Customer Service ...............................................................................107

1. Dynamic Pricing ....................................................................107 L. Miller

a) Background ................................................................107

(1) Project Overview ...........................................107

(2) Scope ..............................................................107

(3) Implementation Schedule...............................108

b) Recorded and Forecast Expenses ...............................108

c) Conclusion .................................................................109

2. SCE.com Strategic Upgrade ..................................................109

a) Background ................................................................109


(2) Scope ..............................................................110


b) Business Requirements ..............................................115

(1) Current System and Process...........................115

(2) Alternatives Considered .................................116

(3) Cost-Benefit Analysis ....................................116

c) Recorded and Forecast Expenditures .........................116

d) Conclusion .................................................................117




-x-

3. Edison SmartConnect® (ESC) Project Stabilization .............118 J. Bubb

a) Background ................................................................118


(2) Scope ..............................................................118



(1) Current Systems and Processes ......................119




d) Conclusion .................................................................120

4. Meter Service Organization (MSO) Integrated Work Management Systems Project ......................................120

a) Background ................................................................120


(2) Scope ..............................................................121







d) Conclusion .................................................................125




-xi-

5. Digital Experience Program ...................................................125 L. Miller

a) Overview ....................................................................125

(1) SCE’s Customer Engagement Model Continues to Evolve .......................................125

(2) Technology in Customer Self-Service Options Has Advanced Rapidly ...........................................................126

(3) An Investment in Integrated Technology Is Required .................................126

(4) The Digital Experience Program Provides Long Term Benefits ........................126

(5) Shifting Customer Experience towards Broader Access .................................128

(6) Shifting Customer Experience Impacts SCE’s Self-Service Model ...............128

(7) Investment in Technology is Required to Meet Customer’s Shifting Expectations .....................................130

b) Digital Experience – Systems Overview ...................130

(1) Upgrade the Interactive Voice Response to Utilize Advanced Speech Recognition (ASR) and Text to Speech (TTS) Technologies .......................130

(2) Alerts and Notification System ......................132

(3) Outage Communication System ....................136

(4) Build Out the Customer Data Warehouse ......................................................138

(5) SCE.com/Customer Service Relationship (CRM) Integration ....................140




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c) Digital Experience Overall Project Schedule ............141

d) Cost-Benefit Analysis ................................................142

e) Operational Benefits ..................................................143

f) Recorded and Forecast Expenditures .........................145

g) Conclusion .................................................................146

6. Prepayment Program ..............................................................146 C. Hu

a) Background ................................................................146


(2) Scope ..............................................................146






d) Conclusion .................................................................149

7. GRC Rate Design Phase II .....................................................149

a) Background ................................................................149


(2) Scope ..............................................................150








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d) Conclusion .................................................................152

8. Enhanced Metering and Usage ..............................................152 C. Hu

a) Background ................................................................152


(2) Scope ..............................................................153







d) Conclusion .................................................................155

9. Edison SmartConnect® Monitoring and Analysis System (SCMAS) Phase 2 .....................................................156 J. Bubb

a) Background ................................................................156


(2) Scope ..............................................................157








-xiv-



d) Conclusion .................................................................161

10. Hiperwall Refresh ..................................................................161

a) Background ................................................................161


(2) Scope ..............................................................162





c) Cost-Benefit Analysis ...............................................166

d) Recorded and Forecast Expenditures .........................166

e) Conclusion .................................................................166

11. Plug-In Electric Vehicle (PEV) Support Systems .................167 L. Miller

a) Background ................................................................167


(2) Scope ..............................................................168









-xv-


d) Conclusion .................................................................173

12. Customer Service System (CSS) Enhancements ...................174 C. Hu

a) Background ................................................................174


(2) Scope ..............................................................174







d) Conclusion .................................................................177

13. Cell Relays Replacement Project ...........................................177 J. Bubb

a) Background ................................................................177


(2) Scope ..............................................................178










-xvi-

d) Conclusion .................................................................182

14. Home Area Network (HAN) Future Upgrades and Standards ................................................................................183 L. Miller

a) Background ................................................................183


(2) Scope ..............................................................183







d) Conclusion .................................................................187

F. Power Supply .....................................................................................187

1. Data Management Platform Upgrade Phase 3 .......................187 J. Tran

a) Background ................................................................187



d) Conclusion .................................................................189

2. CAISO Market Enhancements in 2013 ..................................189

a) Background ................................................................189

(1) Pay-for-performance Regulation ...................190

(2) Mandatory Multi-Stage Generator (MSG) ............................................................191




-xvii-



d) Conclusion .................................................................193

3. CAISO Market Enhancements in 2014–2017 ........................193

a) Background ................................................................193



d) Conclusion .................................................................200

4. Energy Procurement Information Center Replacement ...........................................................................200

a) Background ................................................................200



d) Conclusion .................................................................202

5. Renewable Contract Management System ............................203

a) Background ................................................................203



d) Conclusion .................................................................204

6. Energy Trading and Risk Management (ETRM) System Replacement ..............................................................205

a) Background ................................................................205






-xviii-

d) Conclusion .................................................................207

7. Common Data Store (CDS) and Power Supply Data and Reporting database (PDR) Upgrade ................................207

a) Background ................................................................207



d) Conclusion .................................................................209

8. Usage Measurement System ..................................................210

a) Background ................................................................210



d) Conclusion .................................................................211

9. Generation Management System ...........................................211

a) Background ................................................................211



d) Conclusion .................................................................213

10. Aggregated Demand Response ..............................................213

a) Background ................................................................213



d) Conclusion .................................................................216

11. Market System Replacement .................................................216




-xix-

a) Background ................................................................216



d) Conclusion .................................................................218

12. Fundamental Modeling Platform ...........................................218

a) Background ................................................................218



d) Conclusion .................................................................220

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


List Of Figures

Figure Page

-xx-

Figure I-1 Operating Software Expenditure Recorded 2008-2012 and Forecast 2013-2017 ......................2

Figure II-2 SCE Detected Intrusion Attempts ..........................................................................................12

Figure VI-3 Digital Experience Benefit Areas ........................................................................................127

Figure VI-4 Customers Move To Self-Service Creates A Shift In How SCE Delivers

Service And Information ....................................................................................................................129

Figure VI-5 Current Alerts & Notification Architecture .........................................................................133

Figure VI-6 Proposed Alerts & Notification Architecture ......................................................................134

Figure VI-7 Digital Experience Program Implementation Schedule ......................................................142

Figure VI-8 Cost and Timing of Benefits – Digital Experience Capital Software Projects

(Nominal $ in Millions) .....................................................................................................................143

Figure VI-9 Full Investment Yields Hard Benefits by 2020....................................................................145

Figure VI-10 Edison SmartConnect® Monitoring and Analysis (SCMAS) System

Diagram..............................................................................................................................................157

Figure VI-11 Hiperwall Configuration Diagram .....................................................................................164

Figure VI-12 Current PEV Seven Stage Process .....................................................................................171

Figure VI-13 Meter and Communications System ..................................................................................181


List Of Tables

Table Page

-xxi-

Table I-1 Operating Software Work Breakdown Structure (WBS) ID and Description .............................1

Table II-2 Perimeter Defense Expenditures (Nominal $000) ....................................................................18

Table II-3 Capital Cost Forecast (Nominal $000) .....................................................................................19

Table II-4 Recorded Costs (Nominal $000) ...............................................................................................20





Table II-9 Project Capital Cost Forecast (Nominal $000) .........................................................................27

Table II-10 Recorded Costs (Nominal $000) .............................................................................................27

Table II-11 Project Capital Costs Forecast (Nominal $000) .....................................................................28

Table II-12 Recorded Costs (Nominal $000) .............................................................................................32

Table II-13 Capital Cost Forecast (Nominal $000) ...................................................................................32

Table II-14 Project Capital Cost Breakdown (Nominal Dollars) ..............................................................33

Table III-15 NERC CIP Standards Requirements .....................................................................................38

Table III-16 Recorded Costs (Nominal $000) ...........................................................................................40

Table III-17 Project Capital Cost Forecast (Nominal $000) ......................................................................41

Table III-18 Project Cost Breakdown (Nominal $000) .............................................................................44

Table IV-19 Service Management System Expenditures (Nominal Dollars) ............................................47

Table IV-20 Service Management System (Nominal Dollars) ..................................................................48

Table IV-21 Data Masking and Subsetting Project ...................................................................................49

Table IV-22 Shared Enterprise Integration Infrastructure .........................................................................53

Table IV-23 Funding Requirements (Nominal $000,000) .........................................................................56

Table IV-24 SAP BW HANA Enterprise Data Warehouse .......................................................................57

Table IV-25 SAP BW HANA Enterprise Data Warehouse Upgrades (Nominal $000) ............................58

Table IV-26 Business Intelligence Tools Upgrade Refresh ......................................................................59

Table IV-27 Business Intelligence Tools Upgrade Refresh Forecast Costs (Nominal

Dollars) ................................................................................................................................................61


List Of Tables (Continued)

Table Page

-xxii-

Table IV-28 Business Analytics ................................................................................................................62

Table IV-29 Business Analytics Forecast Costs (Nominal Dollars) ........................................................64

Table IV-30 Data Archiving Project ..........................................................................................................65

Table IV-31 Enterprise Platform Core Refresh .........................................................................................68

Table IV-32 Capital Cost Forecast (Nominal Dollars) ..............................................................................73

Table IV-33 Recorded Costs (Nominal Dollars) .......................................................................................73

Table V-34 Estimated Software Project Less Than $1Million for 2013-2017 (Nominal

$000) ....................................................................................................................................................75

Table VI-35 Estimated Capitalized Software Project Expenditures for 2013-2017

(Nominal $000) ....................................................................................................................................76

Table VI-36 IWMS Costs & Benefits (2013-2017) (Nominal $000) ........................................................94

Table VI-37 Comparison of Recorded to Forecast Expenditures ..............................................................97

Table VI-38 Mitigating the Risk Associated With Managing Unstructured Content .............................100

Table VI-39 Typical eDMRM Library Implementation ..........................................................................105

Table VI-40 eDMRM Implementation Cost Summary (2013-2017) ......................................................106

Table VI-41 Dynamic Pricing Project Costs by Year Recorded 2010-2012 and Forecast

2013-2014 (Nominal $ Millions) .......................................................................................................109

Table VI-42 SCE.com Strategic Upgrade Costs by Year Recorded 2010-2012 and

Forecast 2013-2014 (Nominal $ Millions) ........................................................................................117

Table VI-43 SCE.com Future Upgrades Forecast 2013-2014 (Nominal $ Millions) ..............................117

Table VI-44 Capital Forecast Expenditures for the Edison SmartConnect® Stabilization

Project (Nominal $ Millions) .............................................................................................................120

Table VI-45 Capital Forecast Expenditures for the MSO Integrated Work Management


Table VI-46 Digital Experience Program Cost Savings Benefit Assumptions (less ASR &

TTS Project) .......................................................................................................................................144

Table VI-47 Capital Forecast Expenditures for the Prepayment Program Project (Nominal

$ Millions) ..........................................................................................................................................149



Table Page

-xxiii-

Table VI-48 Capital Forecast Expenditures for the General Rate Design Phase II Project

(Nominal $ Millions) .........................................................................................................................152

Table VI-49 Capital Forecast Expenditures for the Enhanced Metering and Usage Project


Table VI-50 Capital Forecast Expenditures for the SCMAS Phase II Project (Nominal $

Millions) .............................................................................................................................................161

Table VI-51 Capital Forecast Expenditures for the Hiperwall Refresh Project (Nominal $

Millions) .............................................................................................................................................166

Table VI-52 Capital Forecast Expenditures for the PEV Support System Project


Table VI-53 Capital Forecast Expenditures for the CSS Enhancements Project (Nominal

$ Millions) ..........................................................................................................................................176

Table VI-54 Capital Forecast Expenditures for the Cell Relay Replacement Project


Table VI-55 Capital Forecast Expenditures for the HAN Future Upgrades and Standards


Table VI-56 Capital Forecast Expenditures for Data Management Platform Update Phase

3 (Nominal $000) ...............................................................................................................................189

Table VI-57 Capital Forecast Expenditures for CAISO Market Enhancements Project

(2013) (Nominal $000) ......................................................................................................................193

Table VI-58 Capital Forecast Expenditures for CAISO Market Enhancements Project

(2014-2017) (Nominal $000) .............................................................................................................200

Table VI-59 Capital Forecast Expenditures for Energy Procurement Information Center

Replacement (Nominal $000) ...........................................................................................................202

Table VI-60 Capital Forecast Expenditures for Renewable Contract Management System

(Nominal $000) ..................................................................................................................................204

Table VI-61 Capital Forecast Expenditures for Energy Trading and Risk Management

System (Nominal $000) .....................................................................................................................206



Table Page

-xxiv-

Table VI-62 Capital Forecast Expenditures for Common Data Store and Power Supply

Data and Reporting Database (Nominal $000) .................................................................................209

Table VI-63 Capital Forecast Expenditures for Usage Measurement System (Nominal

$000) ..................................................................................................................................................211

Table VI-64 Capital Forecast Expenditures for Generation Management System

(Nominal $000) ..................................................................................................................................213

Table VI-65 Capital Forecast Expenditures for Aggregated Demand Response (Nominal

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

Table VI-66 Capital Forecast Expenditures for Market Systems Replacement (Nominal

$000) ..................................................................................................................................................217

Table VI-67 Capital Forecast Expenditures for Fundamental Modeling Platform

(Nominal $000) ..................................................................................................................................220

1

I. 1

OPERATING SOFTWARE 2

Table I-1 Operating Software

Work Breakdown Structure (WBS) ID and Description

WBS ID DescriptionCIT-00-OP-CS-000030 Operating Software & MiddlewareCIT-00-OP-CS-000023 Microsoft Enterprise Agreement License and DeploymentCIT-00-OP-CS-000046 Domain Name Services (DNS)

A. Background 3

Operating Software is primarily used to manage and monitor the health, performance, capacity, 4

and configuration of mainframe servers, midrange servers, storage, and personal computers. This 5

section of testimony also includes upgrades of operating system software and desktop applications. 6

Examples of Operating Software are Microsoft Windows 7 and the Office 2010 suite of products 7

including Excel, Word, and PowerPoint. Other examples of Operating Software include CMDB 8

(Configuration Management Database), Capacity Management and DCIM (Datacenter infrastructure 9

Management) software. 10

B. Business Requirements 11

Operating Software is indispensable to SCE’s daily operations. It allows SCE to operate 12

effectively in a highly complex computing environment. Operating Software requirements are dictated 13

by the number, type, and size of computing hardware components maintained by SCE, as well as by 14

business needs. Business needs can be classified into three groups: 15

Hardware and Software Additions – necessary to add additional software licenses 16

incrementally as growth occurs and service levels warrant 17

New Capability – necessary to support requirements of new products 18

Vendor Specified End of Life (i.e., vendor obsolescence) – necessary to keep SCE in 19

compliance with vendor software licensing, support and security requirements at a level 20

consistent with business needs1 21

1 See IBM Software Support Lifecycle available at http://www-01.ibm.com/software/support/lifecycle/ for IBM’s software

product lifecycles.

2

C. Recorded and Forecast Expenditures 1

SCE recorded $85.497 million for the period 2008-2012 for Operating Software and middleware 2

and estimates $53.835 million, a 52.2 percent decrease, for the period 2013-2017,as depicted in the 3

figure below. 4

Figure I-1 Operating Software Expenditure

Recorded 2008-2012 and Forecast 2013-2017

Forecast

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Operating Software $6,627.5 $32,258.8 $18,198.7 $26,556.1 $26,785.8 $7,200.0 $3,390.0 $2,500.0 $27,500.0 $13,245.0

Total $6,627.5 $32,258.8 $18,198.7 $26,556.1 $26,785.8 $7,200.0 $3,390.0 $2,500.0 $27,500.0 $13,245.0

Recorded

$0.0

$5,000.0

$10,000.0

$15,000.0

$20,000.0

$25,000.0

$30,000.0

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Operating Software($000)

Operating Software

D. Recorded Expenditures 5

In 2008, we recorded $6.628 million of capital expenditures for operating software, primarily for 6

additional mainframe software licenses and other Operating Software driven by the refresh of 7

mainframes servers at the end of useful life and system capacity performance increases for Customer 8

Service System (CSS) transaction processing needs. In 2009, we recorded $32.259 million, primarily 9

comprised of $17.400 million for the new Microsoft Enterprise License Agreement (ELA) for Microsoft 10

operating system products (we replaced the Microsoft products used in our server and desktop 11

environments prior to Microsoft’s published end-of-support date at the end of 20132), and $7.860 12

million for data backup and storage management software to reduce the complexity of managing our 13

server and storage environments by centralizing, simplifying, and automating tasks. Another $2.463 14

2 See Microsoft support Lifecycle Index available at http://support.microsoft.com/gp/lifeselectindex for software end of

support information. (Last visited July 1, 2013).

3

million was spent for electronic messaging and collaboration licenses to support the growth of the 1

workforce, and $1.511 million for enterprise configuration management software licenses and 2

implementation, which was used to integrate our data center configuration into a coherent database. 3

In 2010 we recorded $18.199 million of capital expenditures, primarily for an IBM Enterprise 4

License Agreement (ELA) for Operating Software, which was needed to upgrade our server and storage 5

environments prior to IBM’s published end of product life and end of support.3 6

In 2011 we recorded $2.806 million, primarily for CMDB (Configuration Management 7

Database) Operating Software to simplify the management of our server and storage infrastructure and 8

application interfaces. Another $23.750 million was primarily for Microsoft Windows Desktop 9

Operating Software deployment and to procure Incident Management and Enterprise Application 10

Performance Monitoring Operating Software. 11

E. Forecast Expenditures 12

For the forecast period 2013 to 2017, total forecast expenditures are $53.835 million, or 51.2 13

percent less than the recorded period total. SCE uses a standard methodology to forecast capitalized 14

expenditures for most new capital projects and refreshes of existing applications. Our preliminary cost 15

estimates are developed by a team of SCE employees who have experience with previous capital 16

technology projects. The software and vendor estimates are based on experience from similar projects 17

that IT has successfully implemented. With certain exceptions, competitive bidding and rigorous 18

screening of the vendors and the products is conducted, which includes issuing a request for proposal 19

(RFP). The workpapers included with this Volume provide the details used to develop the costs for each 20

of our capital forecasts. To develop our forecast, we identified specific types of Operating Software by 21

evaluating business requirements based on the following drivers: (1) hardware and software additions, 22

(2) new capabilities, and (3) vendor specified end of life. We used pricing agreements negotiated in 23

2012 with Microsoft4 to estimate Operating Software costs. We plan to make these purchases through 24

our strategic business partners, Edge Solutions and Zones. Both suppliers were selected as strategic 25

business partners representing IBM and Microsoft respectively. These companies provide solutions 26

meeting our business requirements, and also are Diverse Business Enterprise (DBE) suppliers, helping 27

to fulfill SCE’s supplier diversity requirements as established in CPUC’s General Order 156. For all 28

other vendor products, we used estimated costs based on previous projects with similar scope. 29

3 Id.

4 See workpaper entitled “Microsoft ELA.”

4

In 2013 we forecast $7.200 million: (a) to procure additional mainframe software licenses 1

driven by refresh of the new mainframe servers, which replaced older mainframe computers at the end 2

of their useful life (year-end 2012); (b) to upgrade server Operating Software due to vendor published 3

end of life (end of support); and (c) to expand ERP licenses and software infrastructure and to continue 4

the Solution Manager implementation. 5

In 2014 we forecast $3.390 million for the new Cisco and VMware Enterprise License 6

Agreements (ELA) and Domain Name Servers (DNS) software for Operating Software needed to 7

upgrade our server and storage environment prior to vendor published end of life (end of support) in 8

2015.5 9

In 2015 we forecast $2.500 million for the new Cisco and VMware Enterprise License 10

Agreements (ELA) for Operating Software needed to upgrade our server and storage environments prior 11

to vendor published end of life (end of support) by year-end 2016.6 12

In 2016 we request $27.500 million for the new Microsoft, Cisco and VMware Enterprise 13

License Agreements (ELA) for Operating Software needed to upgrade our server, storage and desktop 14

environments prior to vendor published end of life (end of support).7 15

In 2017 we forecast $13.245 million for the new Microsoft, Cisco and VMware Enterprise 16

License Agreements (ELA) for Operating Software needed to upgrade our server, storage and desktop 17

environments prior to vendor published end of life (end of support).8 18

F. Conclusion 19

Operating Software is indispensable in the daily operations at SCE. It allows SCE to remain 20

proactive in a highly complex computing environment. The expenditures forecast are needed to manage 21

computing resources as they grow in size and complexity, while mitigating the ongoing potential risk to 22

critical business functions due to technology obsolescence and vendor obsolescence. Technology 23

obsolescence results when the underlying technology that an application uses is identified by its vendor 24

to be phased out (no longer approved for use). The reasons for technology obsolescence include, but are 25

not limited to, security flaws, unstable technology platforms, and operating system changes. Vendor 26

5 See Cicso Product Support Publications available at http://www.cisco.com/en/US/products/products_end-of-

life_policy.html (Last visited July 1, 2013).

6 Id.

7 Id.

8 Id.

5

obsolescence (also known as Vendor Specified End of Life for products) results when a Commercial-1

Off-The-Shelf (COTS) application or version of an application is no longer supported by the vendor. 2

Products, versions and support dates are published on most vendor websites. 3

6

II. 1

CYBERSECURITY AND IT COMPLIANCE 2

A. Introduction 3

The importance of cybersecurity to the utility industry and to SCE has expanded as systems and 4

data have become more integral to business operations, and as the electric infrastructure has become 5

more essential to national commerce and communications capabilities. Cyber attacks are continually 6

growing in number and sophistication, and the availability of cyber weapons is on the rise as well. 7

Therefore, maintaining a strong defense against cyber attack requires a continually evolving set of 8

strategies. 9

Recent examples of cyber attack are well documented in the news media and the intelligence 10

community. In August 2012, a virus attack delivered by e-mail compromised more than 30,000 11

computers at the Saudi Arabian Oil Co., also known as Saudi Aramco. In this attack, the virus destroyed 12

data on servers and erased hard drives on individual computers.9 In June 2010, a computer worm called 13

Stuxnet was discovered, which attacked and damaged nuclear facilities in Iran.10 Within the U.S., 14

President Obama recognized the growing cyber threat to critical infrastructure when he issued policy 15

directive PPD-21 in February 2013.11 16

Most recently, Mandiant Corporation released its report “APT1: Exposing One of China’s Cyber 17

Espionage Units.” In this report, Mandiant cites evidence for its conclusion that APT1 (Advanced 18

Persistent Threat 1) is a cyber-espionage arm of the Chinese government, which “has systematically 19

stolen hundreds of terabytes of data from at least 141 organizations” and which “focuses on 20

compromising organizations across a broad range of industries in English-speaking countries.”12 In fact, 21

SCE’s monitoring and analysis of intrusion attempts found that over 25 percent of attacks on SCE 22

networks and systems in 2012 originated from China.13 This conclusion by Mandiant that cyber-23

espionage is sponsored and funded by the Chinese government reinforces our conviction that SCE must 24

maintain a strong defensive posture against cyber attack. 25

9 See workpaper entitled “Saudi Aramco Oil Giant recovers from virus attack,” BBC News, August 27, 2012.

10 See workpaper entitled “The Real Story of Stuxnet,” by David Kushner, IEEE Spectrum, March 2013.

11 See workpaper entitled “Presidential Policy Directive PPD-21,” February 12, 2013.

12 See workpaper entitled “APT1: Exposing One of China’s Cyber Espionage Units,” Mandiant Corporation, 2013.

13 See workpaper entitled “Cyber attacks on SCE by Country of Origin.”

7

The Cybersecurity & IT Compliance Division (C&C) oversees SCE’s Corporate Cybersecurity 1

Program to maintain the confidentiality, availability, integrity, and accountability of SCE’s information 2

technology systems and operations through security engineering and risk management. C&C also 3

oversees regulatory compliance activities across IT and develops programs to ensure compliance with 4

emerging federal and state legislative and regulatory mandates regarding cybersecurity. 5

SCE employs a defense-in-depth strategy for security, which utilizes multiple layers of 6

protection to prevent unauthorized access to its systems. As a result, IT sponsors a number of capital 7

projects in the area of information security. These projects fall into three primary categories: Perimeter 8

Defense, Interior Defense, and Data Protection. SCE also anticipates the need to respond to new 9

legislation in the cybersecurity arena, and thus IT sponsors a fourth category of work referred to as 10

Solutions for Emerging Legislative Mandates. Finally, in a fifth project category, Common 11

Cybersecurity Services, IT is developing a means to allow devices on the smart grid to securely 12

communicate with grid control centers. 13

Perimeter Defense: Perimeter Defense includes the processes, procedures, personnel, 14

hardware and software designed to protect SCE’s information and systems from external 15

attacks. Perimeter Defense is especially critical to systems that are accessible via the 16

Internet. 17

Interior Defense: The goal of the Interior Defense program is to secure SCE’s internal 18

business systems from unauthorized users, devices and software. Advanced and integrated 19

real time monitoring of SCE’s internal business network makes it more difficult for 20

unauthorized users to gain access to our systems and for rogue devices or software to cause 21

business disruption. 22

Data Protection: The objective of the Data Protection program is to protect SCE customers, 23

employees, contractors, and other personnel from identity theft, as well as to protect 24

confidential SCE information residing on all computing devices from unauthorized use, 25

distribution, reproduction, alteration, or destruction. 26

Solutions for Emerging Legislative Mandates: Cybersecurity legislation and regulation 27

continue to evolve with a great deal of activity. The Presidential Executive Order Improving 28

Critical Infrastructure Cybersecurity,14 dated February 12, 2013, has increased focus in these 29

14 See workpaper entitled “Executive Order – Improving Critical Infrastructure Cybersecurity,” February 12, 2013.

8

areas. As a large electric utility that is a part of the critical national infrastructure, SCE 1

strives to protect shareholder interests through shaping cybersecurity legislation and 2

regulation, and through early compliance planning. 3

Common Cybersecurity Services: Common Cybersecurity Services is an architecture that 4

allows any device in the smart grid network to securely access common services (e.g., 5

cybersecurity, network monitoring, etc.) in utility control centers. This architecture is needed 6

because the level of automation and connectivity introduced through grid modernization has 7

also increased its vulnerability. 8

IT also sponsors a category of cybersecurity projects for SONGS 9

SONGS Cybersecurity: In February 2012, SONGS’ Cyber Security Program underwent an 10

inspection by the NRC. As a result of the inspection, SONGS is required to remediate any 11

issues identified in the inspection and advance its Cyber Security Program.15 In 2015, 12

SONGS will be re-inspected to validate that the improvement areas identified are remediated 13

and the SONGS Cyber Security Program is integrated into the plant’s operations. 14

B. Information Security 15

1. Background 16

In today’s evolving corporate environment, the once structured and clearly defined 17

business network has all but vanished. Moreover, it has been extended to include the public internet 18

with its unstructured boundaries. This trend has resulted in the creation of business services outside the 19

once protected business network, and the need to grant entities outside the business network access to 20

resources within this network. This increasingly broad accessibility to SCE’s network presents a need 21

for a flexible process to access these systems balanced by stronger security controls.16 22

Within SCE, the C&C group is responsible for preventing cyber attacks from impeding 23

SCE’s business and electric power operations. According to the Director of National Intelligence of the 24

United States, cyber threats pose a critical national and economic security concern due to the continued 25

advances in, and growing dependency on, information technology.17 The dependence on mobile 26

15 See workpaper entitled “SONGS Critical Digital Asset (CDA) Remediation” for more information on SONGS CDA

Remediation project.”

16 See workpaper entitled “Security without Boundaries: Managing Your Multi-Perimeter World with Security Intelligence,” IBM Institute for Advanced Security, 2012.

17 See workpaper entitled “Worldwide Threat Assessment of the US Intelligence Community,” James R. Clapper, January 2012.

9

technologies, wireless communications and cloud computing, and the use of personal devices to access 1

business systems, has further exposed business systems to known and yet to be discovered cyber threats. 2

According to the Director, one of the greatest strategic challenges is “providing timely, actionable 3

warning of cyber threats and incidents, such as identifying past or present security breaches.”18 Threats 4

to critical infrastructure continue from various entities including nation states, terrorist networks, 5

organized crime organizations and individuals. Corporate networks, business systems, and critical 6

infrastructure also may be threatened by insiders within the business environment itself. 7

Cybersecurity is critical to the reliability and resiliency of the nation’s electric grid, and 8

equally, to SCE’s electric grid. This is particularly important since the electric grid is arguably the most 9

complex and critical infrastructure that various business sectors depend upon to deliver essential 10

services (e.g., communications, transportation). 11

Industrial control systems (ICS) are an integral part of the critical electric infrastructure, 12

helping to facilitate operations in vital sectors such as electricity, oil and gas, water, transportation, and 13

chemical. A holistic cybersecurity approach is required that uses specific countermeasures to create an 14

integrated security posture to defend against cybersecurity threats against ICS. The same defense-in-15

depth approach SCE uses to protect its corporate network and systems is being applied to SCE’s ICS 16

network to provide a flexible framework for improving cybersecurity defenses. This approach includes 17

implementing layers of security measures utilizing firewalls, intrusion detection/prevention systems, and 18

vulnerability management technologies which are described in more detail in this Volume. 19

It is difficult to protect against something we cannot see. To protect SCE’s critical 20

systems and information, SCE will bring together the information collected across the various 21

cybersecurity layers to establish a unified monitoring capability for ‘actionable warning’ as described by 22

the Director of National Intelligence.19 This unified monitoring capability is discussed in more detail in 23

the Business Requirements section. 24

In addition to the cyber threat challenge, SCE must also comply with an evolving 25

regulatory environment which has become more focused on protecting critical infrastructure and 26

sensitive business information. Key legislation and regulations include North American Electric 27

Reliability Corporation – Critical Infrastructure Protection (NERC CIP) reliability standards, Sarbanes-28

Oxley (SOX) Act, Health Insurance Portability Accountability Act (HIPAA), Nuclear Regulatory 29

18 Id.

19 Id.

10

Commission (NRC) Protection of Safeguards Information, and Payment Card Industry (PCI) Data 1

Security Standards. SCE is responding to the changing regulatory environment and expanding cyber 2

threat landscape through integration and streamlining of the cybersecurity framework which will be 3

accomplished by strengthening our defense-in-depth strategy. Implementing cybersecurity through a 4

layered defense strategy allows SCE to deploy multiple defense mechanisms between the adversary and 5

the target.20 These layers help increase visibility into intrusions while improving SCE’s opportunities to 6

identify and rapidly respond to threats. This is accomplished at SCE by implementing enhanced security 7

controls in layers to address Perimeter Defense, Interior Defense, and Data Protection. In the Business 8

Requirements section below, the projects planned to support the defense-in-depth strategy are described. 9

2. Business Requirements 10

a) Perimeter Defense 11

Perimeter Defense includes the processes, procedures, personnel, hardware and 12

software designed to protect SCE’s information and systems from external attacks. Perimeter Defense is 13

especially critical to systems that are accessible via the Internet. Traditionally, network security is based 14

upon a layered Defense-in-Depth approach. This approach includes implementing security in layers 15

with each layer providing an increasing level of restrictive controls. 16

SCE has generally followed this approach; however, the perimeter is not as 17

clearly defined as it once was due to: 18

Increasingly mobile workforce 19

Wireless access to business data 20

Increased usage of non-managed personal devices such as smart phones and 21

tablets 22

Expanded use of social networks 23

Increasing reliance on electronic collaboration capabilities 24

Growing use of cloud service (externally hosted business solutions) 25

Higher reliance on virtualization at all levels of computing 26

Expanded use of web services 27

Dynamic web applications (html5, Web 2.0) 28

Changing business environment that favors partnering and hosting data offsite 29

20 See workpaper entitled “Defense In Depth,” National Security Agency.

11

Threat environment shifting towards more sophisticated and directed attacks 1

The objective of the Perimeter Defense program is to protect SCE from external 2

threats from the Internet. SCE is under continuous cyber attack, and the attack methods, exploits, and 3

capabilities are constantly evolving as new types of attacks are discovered. Such attacks include 4

computer viruses, worms, phishing, spyware, and advanced persistent threats, any of which could cause 5

significant damage to SCE’s information systems if successful. Figure II-2 illustrates the growth in 6

detected intrusion attempts into SCE’s network over the period 2008-2012.21 7

SCE must increase the overall security of its controls relating to access of 8

business systems and data within our internal business network from the Internet. SCE will increase 9

remote access security by implementing improved tools for use by an increasingly more mobile 10

workforce utilizing devices either issued by SCE or owned by employees. To complement this 11

capability, SCE will also be implementing newer generation intrusion protection systems and intrusion 12

detection systems to improve detection of unauthorized access. This approach will be coordinated with 13

controls already in place to increase SCE’s overall security posture and improve protection of its 14

information and computing infrastructure. These systems will be integrated into a common, unified 15

monitoring capability, ensuring that rapid response to security events can be initiated. 16

21 See workpaper entitled “SCE Detection of Intrusion Attempts.”

12

Figure II-2 SCE Detected Intrusion Attempts

‐

25,000

50,000

75,000

100,000

125,000

150,000

175,000

200,000

225,000

250,000

275,000

300,000

325,000

350,000

2008 2009 2010 2011 2012

b) Interior Defense 1

Interior Defense is a set of protection controls required to secure SCE’s internal 2

business systems, not only from unauthorized users, but also from devices and software attempting to 3

access SCE’s business systems. Earlier identification of suspicious activity would allow us to take 4

quicker action to minimize any potential damage which may result from this activity. 5

Advanced and integrated real time monitoring of SCE’s internal business network 6

would make it more difficult for unauthorized users to gain access to our systems. It will also make it 7

more difficult for rogue devices or software to access SCE systems or cause business disruption. These 8

advanced techniques include: 9

13

Extending SCE’s Identity and Access Management system to newer 1

generation security technology 2

Enhancing and expanding SCE’s data collection capabilities 3

Implementing technology to allow SCE to analyze collected information for 4

security threats 5

Initiating automated alerts when questionable activity is detected 6

This approach helps to address advanced persistent threats by using advanced data 7

collection and analysis technologies for early detection of potentially questionable activity. 8

Key changes in the business environment require adaptation by SCE to mitigate 9

significant new cybersecurity risks. It should be noted that many of the same drivers discussed for 10

Perimeter Defense are also challenges for SCE’s internal business network. The primary difference is 11

that when the threat exists internally, the first layer of defense has already been bypassed. These change 12

drivers include: 13

Increasingly mobile workforce 14

Wireless access to business data 15

Increased usage of non-managed personal devices such as smart phones and 16

tablets 17

Higher reliance on virtualization at all levels of computing 18

Expanded use of web services 19

Dynamic web applications (html5, Web 2.0) 20

Threat environment shifting towards more sophisticated and directed attacks 21

c) Data Protection 22

The Data Protection Program seeks to safeguard the very core of SCE’s 23

information computing environment by introducing controls to protect critical business information. For 24

example, the Data Protection Program will add specialized technology that will: 25

Allow protection of data fields within files 26

Allow protection of business information on mobile devices 27

Enhance access controls to sensitive business information 28

Control the replication of business information to personal removable storage 29

media 30

14

Ensure protection of business information stored at external sites hosting SCE 1

business systems. 2

The objective of the Data Protection Program is to protect SCE customers, 3

employees, contractors, and other personnel from identity theft, as well as to protect confidential SCE 4

information residing on all computing devices from unauthorized use, distribution, reproduction, 5

alteration, or destruction. This program will focus on improving the security of information stored 6

within various databases both within and outside of SCE’s computing environment. This objective will 7

be achieved by: 8

Implementing enhanced controls for granular data protection 9

Automating data classification 10

Monitoring and alerting unauthorized access to business information 11

Managing business information saved on personal devices 12

Controlling the copying of business information to removable devices such as 13

memory sticks and DVDs. 14

d) Common Cybersecurity Services 15

Over the past several years, SCE has been working to develop Common 16

Cybersecurity Services (CCS) to protect its grid infrastructure, based on the understanding that the level 17

of automation and connectivity being introduced through grid modernization efforts has also increased 18

its vulnerability. This, coupled with the increasing threat of cyber attack inherent in the current 19

geopolitical climate, requires the deployment of military-grade cybersecurity solutions to ensure 20

continued grid reliability. CCS is designed to implement security mechanisms to enforce 21

confidentiality, integrity, and availability in the form of security services and policies that protect 22

electronic information, communication, and control systems necessary for the management, operation, 23

and protection of key components of SCE’s network and computing systems infrastructure. 24

SCE’s smart grid common services architecture delivers the capability for any 25

device in the grid network to access common services (e.g., cybersecurity, device management, network 26

monitoring, etc.) in utility control centers. SCE is actively engaged in technology transfer of advanced 27

cybersecurity technologies from the defense and intelligence industry to our smart grid implementations. 28

CCS is designed to implement security mechanisms to enforce confidentiality, integrity and availability 29

by way of security services and policies that protect electronic information, communication and control 30

15

systems. CCS is designed to satisfy smart grid requirements as part of the national effort on critical 1

infrastructure and information protection standards. 2

The Common Cybersecurity Services are comprised of Central Security Services 3

and Edge Security Services. The Central Security Services consist of Central Security Configuration 4

Services, Cybersecurity Infrastructure Services and Automated Security Services, which are physically 5

located at SCE’s Grid Control Center, where electrical energy delivery is monitored and managed. The 6

Edge Security Services consist of Edge Security Configuration Services and Automated Security 7

Services, which provide distributed enforcement security on devices at or near the perimeter of a system. 8

The CCS solution enables the design and enforcement of policies that can be 9

configured for specific devices, device classes or locations in the electric grid. Each device on the 10

electric grid secured by CCS will have a unique key to enable secure communications with its control 11

system. This approach mitigates the risk that an attacker will be able to seize control of the electric grid 12

from an individual device, such as a relay or capacitor bank controller, and provides the ability to 13

rapidly respond to a cybersecurity event. 14

e) Solutions for Emerging Legislative Mandates 15

In recent years, extensive legislation, regulation, and a Presidential Executive 16

Order have been introduced to address cybersecurity and data privacy. Federal and California state laws 17

and regulations22 are driving the need for cybersecurity compliance within the energy sector to increase 18

reliability, availability, and security of the electric grid. 19

This heightened interest is occurring because electric grid assets are essential to 20

our nation’s economy and security as part of the national critical infrastructure. Terrorism, recent 21

blackouts, foreign state-sponsored cyber attacks (e.g., China),23 natural disasters, and increased reliance 22

on the grid for essential services (e.g., voice communications, commerce) are driving the interest. 23

More agencies are being formed to focus on cyber threats, (e.g., Office of Energy 24

Infrastructure Security), and more cyber focus in existing agencies is evident (e.g., National 25

Infrastructure Advisory Council and National Association of Regulatory Utility Commissioners). Any 26

significant new events will likely foster emergency action including legislation. 27

SCE views cyber attacks as a matter of national security and has long been a 28

proponent of legislative reform that supports a secure cyber environment. The White House, with a 29

22 See workpaper entitled “Senate Bill No. 1386,” September 26, 2002.

23 See workpaper entitled “U.S. Eyes Pushback On China Hacking.”

16

Presidential Executive Order on Cybersecurity, clearly demonstrated its belief that cyber attacks are a 1

threat to national security and gave the Department of Homeland Security broad authority to unify the 2

fragmented approach that exists across the nation today.24 In addition, the California Public Utilities 3

Commission issued a white paper expressing its concern over cybersecurity and the distribution 4

network,25 and is contemplating an Order Instituting Rulemaking (OIR). The ever-increasing cyber 5

threats faced by the nation and SCE will likely lead to increased levels of regulation and legislation, 6

increasing the need for collaboration with business partners and external entities.26 7

SCE’s approach is to plan and act early. SCE needs to do this with sufficient 8

comprehensiveness to respond proactively to changing regulations, ensure compliance, allow for risk 9

mitigation, and maintain the trust of the public, regulators, and customers. Legislation and regulations 10

can necessitate accelerated action, with deadlines which may be expensive and more difficult to meet. 11

Moreover, new threats may surface (e.g., zero-day threats) which can drive mandates that require SCE 12

to react and respond very quickly. Cyber legislation and regulation can affect every aspect of SCE 13

business and technology. 14

Based on legislation and regulations already drafted, and the discussions 15

underway in the legislative and regulatory arenas, action is expected to be required in three to five years 16

in the following areas: 17

Cybersecurity and critical infrastructure protection: Past bills (112th session) 18

focus on information sharing and critical infrastructure regulations, private 19

and public partnerships, cost recovery, protection from civil liability in 20

handling government-issued information, and emergency authority. With the 21

White House Presidential Policy Directive/PPD-21 on Critical Infrastructure 22

Security and Resilience,27 and the Executive Order – Improving Critical 23

Infrastructure Cybersecurity,28 both released on February 12, 2013, the 24

executive branch is adjusting its approach to cybersecurity. The approach is 25


25 See workpaper entitled “Cybersecurity and the Evolving Role of State Regulation,” State of California, September 19, 2012.

26 External entities include: the White House; Congress; federal agencies and national standards bodies (e.g., NRC, NEI, DOE, FERC/NERC, DOD, DHS, NAESB, NIST); and state government agencies (e.g., CPUC, CEC)

27 See workpaper entitled “Presidential Policy Directive PPD-21,” February 12, 2013.


17

causing a need for realignment in policy and jurisdiction among federal 1

agencies, as well as changes across critical infrastructure industries. 2

Data Privacy: Data privacy legislation has been proposed at the federal and 3

state levels, and through the CPUC via an Order Instituting Rulemaking 4

(OIR). State data privacy laws vary among states. Federal legislation lags in 5

this area because data privacy has been coupled with other concerns. 6

More specifically, the following activities are likely to come to fruition and could 7

require very complex solutions: 8

Intelligence gathering and information sharing capabilities with private and 9

public organizations 10

Privacy bills require data protection controls as well as notification processes 11

when personal information is breached or exposed (e.g., California SB 1386, 12

Section 2(b)).29 13

Electromagnetic pulse (EMP) and geomagnetic disturbance (GMD) threats 14

that particularly impact cybersecurity and business recovery 15

Project Kaleidoscope capability for monitoring network activities for a 16

targeted geographic area 17

Smart Grid NISTIR guidelines have potential for being adopted and becoming 18

mandates 19

History has shown that new mandates can be very disruptive (e.g., NERC CIP). 20

Proactive planning and action is being taken now to address foreseeable mandates, enabling potentially 21

less expensive solutions. 22

29 See workpaper entitled “Senate Bill No. 1386,” September 26, 2002.

18

3. Recorded and Forecast Expenditures 1

a) Perimeter Defense Expenditures 2

Table II-2 Perimeter Defense Expenditures

(Nominal $000)

Recorded Costs (2015 case)2008 2009 2010 2011 2012

$478.9 $3,029.4 $3,639.7 $4,037.8 $7,063.1

For 2010, expenditures covered the following activities: 3

Implementation of new firewalls to protect critical computing infrastructure 4

Initiation of SSL/VPN project to enhance remote access security 5

Implementation of enhanced web security controls which included new 6

monitoring and network web proxy technology 7


Completion of SSL/VPN implementation to enhance remote access security 9

Replacement/upgrades of web firewalls protecting SCE’s external public 10

internet access 11

Implementation of security appliances required to support internal web 12

applications 13


Implementation of network security vulnerability testing technology 15

Acquisition and initial implementation of technology to strengthen user access 16

controls 17

Acquisition and implementation of technology to protect SCE from new and 18

more advanced security threats. 19

19

Table II-3 Capital Cost Forecast

(Nominal $000)

$6,519.0 $5,508.0 $5,673.0 $4,949.0 $5,000.0

Capital Cost Forecast (2015 case)

2013 2014 2015 2016 2017

The Perimeter Defense project costs shown in Table II-3 (also see estimate 1

summary workpaper)30 contains cost estimates and assumptions for forecast costs in 2013 through 2017. 2

Costs in 2013 and 2014 include hardware, software and labor costs related to enhancing Perimeter 3

Defense security. This includes the installation and consolidation of technologies, enabling of necessary 4

activity logging capabilities, and development of integration with a unified security monitoring 5

capability. 6

SCE uses a standard methodology to forecast capitalized expenditures for most 7

new capital projects and refreshes of existing applications as discussed in the testimony SCE-05, Vol. 1 8

entitled “IT-Overview, O&M and Capital”, page 6. In order to forecast projects in 2015 through 2017, a 9

combination of publicly available quotes and direct vendor quotes was used. Firms selected are 10

identified industry leaders who provide solutions that will meet the business requirements for SCE’s 11

Perimeter Defense project. Costs obtained provide the basis for the cost forecast. In order to provide 12

the best forecast, where possible, projects are broken into components and when available, price quotes 13

have been requested to substantiate each of the components. 14

Virtual Private Network (VPN) is a security control allowing SCE to better 15

manage secure remote access to internal business systems. The costs represented are based upon 16

internal recorded costs as well as publicly available quotes and reflect the need to expand this capability 17

to better support our mobile workforce.31 18

To provide increased security in support of the business drivers as outlined in the 19

business requirements, SCE must remain diligent in maintaining Advanced Persistent Threat (APT) 20

protection. The costs represent the acquisition of network appliances.32 Based upon the anticipated 21

30 See workpaper entitled “Perimeter Defense Cost Breakdown.”

31 See workpaper entitled “Purchase Order, Dyn Tek Services.”

32 See workpaper entitled “Scanner Quote.”

20

requirements, three network appliances will be required in 2015 with an additional four network 1

appliances in 2016. 2

Firewalls are the first layer of defense on networks and control access to protected 3

business networks. Estimated costs were obtained via a publicly available quote from a leader in the 4

network security industry.33 The costs were obtained to help estimate reasonable project costs. The 5

costs represent the acquisition of two firewalls in 2015, six additional firewalls in 2016, and an 6

additional six in 2017. 7

For the grid control network, expansion of the intrusion detection and prevention 8

systems will begin in 2015 and complete in 2016. This expansion for control center and substations is 9

needed to introduce additional sensor points in the network that will enable more sensitive detection of 10

cyber threats. 11

Security log collection and analysis is a key capability for SCE to achieve its 12

objective of unified cybersecurity monitoring. In 2017, SCE will upgrade the current technology used 13

for log collection and analysis due to technology obsolescence. The cost represented is based upon 14

internal recorded costs for existing technology acquisition. 15

b) Interior Defense Expenditures 16

Table II-4 Recorded Costs (Nominal $000)


$3,389.0 $5,988.5 $5,740.2 $8,203.5 $3,925.9


Implementation of a security key management system to support encryption 18

certificates utilized on SCE’s internal business network 19

Initial phase of activity to improve UNIX operating system user access 20

controls by externalizing UNIX access management 21

Initial phase of implementation of newer generation network access controls 22

to address security threats relating to non-SCE devices attempting 23

unauthorized access to the internal business network 24

33 See workpaper entitled “Firewall Quote.”

21

Implementation of a newer generation intrusion prevention system to protect 1

against software-based security threats 2

Enhancements to Identity and Access Management capabilities 3


Upgrade of the Identity and Access Management system due to technology 5

obsolescence 6

Continuation of activity to improve UNIX operating system user access 7

controls by externalizing UNIX access management 8

Implementation of new generation network access control technology 9

Implementation of upgraded wireless network controls 10


Completion of technology upgrade to the Identity and Access Management 12

system 13

Continuation of implementation of system to improve UNIX user access 14

controls 15

Expansion of network access control technology implementation 16

Acquisition and implementation of technology required to secure access to 17

business systems by individuals with elevated access rights 18


(Nominal $000)

$9,529.0


2013 2014

$9,345.0 $3,220.0

2015

$9,036.0

2016

$7,729.0

2017

Costs associated with the Interior Defense project34 are attributed to planning, 19

construction and implementation of solutions to strengthen controls for identity management and access 20

management. This will include enhancements to key identity and access management components as 21

well as establishing a unified cybersecurity monitoring capability. This is part of a long term strategy to 22

34 See workpaper entitled “Interior Defense Cost Breakdown.”

22

continually ensure that only authorized individuals and devices have access to the SCE business systems 1

and data, and to continuously monitor for malicious activity that may occur. 2

In order to develop accurate forecasts for planned projects in 2015-2017, costs 3

were obtained from vendors with extensive experience in IT Security, from publicly available quotes, 4

and, where possible, from internal costs as identified within previous efforts. SCE uses a standard 5

methodology to forecast capitalized expenditures for most new capital projects and refreshes of existing 6

applications as discussed in Chapter I, Section E of this Volume. A summary of forecast costs based on 7

the estimates is described below. 8

The Active Directory infrastructure is a key component of SCE’s identity and 9

access management security controls. As stated in the Business Requirements section, SCE’s business 10

environment is evolving and security controls must be strengthened to support new business demands. 11

SCE will be expanding the Active Directory infrastructure and implementing security tools to manage 12

and monitor activity within this infrastructure. Expansion will include extending the internal Active 13

Directory infrastructure to support externally hosted business systems. This will require implementation 14

of integration technology allowing multiple Active Directory infrastructures to behave as a single 15

directory. The integration capability is required to enable SCE to maintain single user information and 16

associated access privileges across multiple environments. Implementing this capability will also 17

require enhancements to monitoring capabilities and security precautions to protect this highly critical 18

function. 19

Cybersecurity tools will improve visibility into network and server activity, and 20

will also enable monitoring of newer, more advanced threats. Information collected by these tools will 21

be retained within a central information repository to be used in support of a unified security monitoring 22

capability. The technologies to be implemented will include: 23

Security analytics technology 24

Vulnerability assessment technology 25

Anti-virus technology to support a virtualized environment 26

Security policy compliance monitoring and enforcement. 27

Expenditures for next generation firewalls in 2015 for Interior Defense address 28

the need to replace existing firewalls with next generation technology.35 This implementation will 29

35 See workpaper entitled “Firewall Quote.”

23

complement the Perimeter Defense implementation. Firewalls are utilized both on the perimeter and in 1

the interior network, with firewalls at the perimeter normally being more restrictive in relation to access 2

controls. 3

For the grid control network, implementation of new firewalls and gateways will 4

begin in 2015 and continue in 2016, and will be completed in 2017. This upgrade is required to add 5

needed protection to substation systems to mitigate the risk of a man-in-the middle attack, whereby a 6

communication between two systems is intercepted by an intruder. 7

For 2015 through 2017, SCE will be implementing an upgraded identity and 8

access management technology. New communication, collaboration and consumer technologies in the 9

business environment are transforming the way we work. Use of smart phones, social media, and cloud 10

computing in the workplace raise complex identity and access management challenges to security 11

controls relating to validation of user and device identities and controlling access to business systems. 12

This makes it imperative that SCE’s identity solutions are standardized inside and 13

outside of SCE’s business network. Imagine if electric plugs didn’t operate the same at work as at 14

home. A business environment without common secure identity processes across the extended business 15

network introduces many risks and inefficiencies. 16

In response to these challenges, SCE will implement a newer generation of 17

Identity and Access Management capabilities which will include biometrics,36 securing identity and 18

access controls in externally hosted systems (business systems in the cloud), expanding support for use 19

of personal devices for access to business systems and information, and integration of the Identity and 20

Access Management capability into SCE’s unified cybersecurity monitoring capability. 21

c) Data Protection Expenditures 22



$847.2 $3,886.7 $1,383.6 $3,638.9 $437.3


36 See workpaper entitled “The Role Of Biometrics In Enterprise Security,” by Catherine J. Tilton, Dell Power Solutions,

February 2006.

24

Initial acquisition and implementation of technology to support data loss 1

protection 2

Initial acquisition of technology to encrypt data files on laptops and desktops 3

Acquisition and implementation of technology to protect against viruses and 4

malware on desktops and laptops 5


Acquisition and expanded implementation of technology to enhance data loss 7

protection 8

Acquisition and expanded implementation of technology to encrypt data files 9

residing on laptops and desktops 10


Expanded implementation of technology to enhance data loss protection. 12


(Nominal $000)


2013 2014 2015 2016 2017

$4,092.0 $6,272.0 $5,150.0 $6,213.0 $3,777.0

Costs associated with the Data Protection project37 are attributed to planning, 13

construction, and implementation of solutions related to strengthening SCE’s ability to protect access to 14

business information and protect critical business information from being compromised. To accomplish 15

this objective, SCE will: 16

Implement technology to protect business information that resides on personal 17

devices, mobile devices and externally hosted systems 18

Implement technology to prevent business information from being copied to 19

personal removable media 20

Implement technology to discover business information residing across the 21

business network in order to implement appropriate access controls. 22

37 See workpaper entitled “Data Protection Cost Breakdown.”

25

This is part of a long-term strategy to limit access to SCE business information to 1

authorized individuals and prevent that information from being transferred outside of the business 2

network by unauthorized individuals and channels. 3

In order to forecast project costs for 2015-2017, published costs were obtained 4

from vendors with extensive experience in IT security. SCE uses a standard methodology to forecast 5

capitalized expenditures for most new capital projects and refreshes of existing applications as described 6

in Chapter I, Section E of this Volume. When SCE initiates specific project activities as described 7

below, the competitive bidding process will be initiated to ensure the most cost-effective solution is 8

selected using a request for proposal (RFP). Outlined below is a summary of forecast costs based on the 9

cost estimates.38 10

In 2015 SCE will replace the existing anti-virus technology with newer and more 11

advanced anti-virus technology. This change is not merely an upgrade to new technology, but is needed 12

to replace software which will have reached both vendor and technology obsolescence39 and will help 13

ensure threats introduced by new consumer platforms do not introduce malicious technology on SCE’s 14

business network. 15

In 2015 SCE will also expand technology needed to enable secure remote access 16

to business information. As SCE’s workforce continues to become more mobile, the need is expanding 17

for secure remote access to support personnel utilizing company-issued devices as well as personal 18

devices. This will be accomplished through expansion of SCE’s SSL/VPN technology. Expansion will 19

require additional SSL/VPN appliances, expansion of user directory capacity and expansion of 20

application virtualization. The cost estimate is based upon SCE’s prior acquisition and implementation 21

costs for SSL/VPN technology.40 A competitive bidding process will be followed when the project is 22

initiated to help ensure the most cost-effective solution is selected. 23

From 2015 through 2017, SCE will be implementing technology to manage ports 24

(physical connectors/plugs) on mobile devices that allow connection with external storage devices. This 25

technology is required to ensure business information accessed by user devices is not lost through the 26

ability to copy this information to external storage devices such as memory sticks or disk drives. 27

38 See workpapers entitled “Greenlight Internet Quote,” “Purchase Order, Zones, Inc.,” “Purchase Order, Accuvant, Inc.,”

“Purchase Order, Dyn Tek Services.”

39 See Chapter 1, Section B and Section F of this Volume for further discussion about technology obsolescence and vendor obsolescence.

40 See workpaper entitled “Purchase Order, Dyn Tek Services.”

26

From 2015 through 2017, a significant investment will be required to implement 1

technology to identify locations where business information is stored, determine information criticality 2

and manage access to this information. These locations can reside internally on SCE’s business network 3

or at external locations such as externally hosted systems. To accomplish this goal, SCE will be 4

implementing data asset discovery technology. 5

For the grid control network, two major efforts are planned for the 2016-2017 6

timeframe. First, we will upgrade the Security Information and Event Management (SIEM) software. 7

This effort is needed because the existing SIEM product is reaching the end of its life, and some desired 8

new functionality (e.g., Compliance Manager) is only supported on newer versions of the software. 9

Second, the anti-virus software will be replaced, since the current anti-virus software is nearing 10

obsolescence.41 It is critical to maintain the latest anti-virus solution to adequately protect the grid 11

control network from the latest brand of malware attacks. 12

d) Common Cybersecurity Services (CCS) Expenditures 13


$0.0 $0.0 $0.0 $0.0 $6,860.0



Completed Common Cybersecurity Services (CCS) Phase 2 Factory 15

Acceptance Test 16

Completed testing at vendor site 17

Completed Installation of CCS product (server and clients) in the SCE test 18

environment 19

41 See McAfee Product & Technology Support Lifecycle vendor support website for product end-of-life information

available at http://www.mcafee.com/us/support/support-eol-siem.aspx (Last visited July 1, 2013).

27

Table II-9 Project Capital Cost Forecast

(Nominal $000)

$8,680.0


2013 2014

$9,900.0 $5,339.3

2015

$8,232.0

2016

$8,459.0

2017

On the Common Cybersecurity Services (CCS) development plan for 2015-2017, 1

the following activities are of strategic importance and will be carried out:42 2

Roll-out CCS to substations in synchronization with the roll-out of Substation 3

Automation Phase 3, Centralized Remedial Action Scheme (CRAS) and 4

Phasor programs 5

Implement CCS to secure the Energy Management System SCADA 6

(supervisory control and data acquisition), back-office application, network 7

components, and field components 8

Implement CCS client on field area network devices, including but not limited 9

to Netcomm radio security upgrades. 10

Refresh CCS central services servers in 2017 11

e) Solutions for Emerging Legislative Mandates Expenditures 12


Recorded Costs (2015 case) 2008 2009 2010 2011 2012

NA NA NA NA NA

42 See workpaper entitled “Common Cybersecurity Services (CCS).”

28

Table II-11 Project Capital Costs Forecast

(Nominal $000)

$6,000.0


2013 2014

$0.0 $0.0

2015

$6,000.0

2016

$6,000.0

2017

The cost forecast above is based upon estimates for implementing technology and 1

capabilities that emerging legislation will likely require. The California Public Utilities Commission 2

(CPUC) and the White House, through Presidential Policy Directive 21 (PPD-21), have begun to define 3

the areas of proposed legislation for reliable national critical infrastructure protection and reliable energy 4

delivery to individuals, industry and emergency services. 5

In order to forecast43 for these emerging legislative mandates, SCE reviewed past 6

costs incurred for similar efforts, such as NERC CIP, which involved the implementation of cyber 7

standards. This forecast includes hardware, software, and labor costs relating to implementation of 8

systems and enhancements we anticipate will be required to meet emerging compliance requirements. 9

The goal of this project is for SCE to comply with emerging requirements in a 10

timely, cost effective manner. For 2015 through 2017, we anticipate the following strategic capabilities 11

will be needed to address the foreseeable legal and regulatory mandates: 12

Secure exchange of security incident data with service providers, in and out of 13

the energy sector, and with federal and state agencies. This will require 14

secure network connections and a high level of data protection due to the 15

confidential and critical nature of the information transmitted. 16

Isolated and secure information repository where security incident information 17

is tightly protected due to the critical nature and confidentiality of the 18

information. 19

Monitoring for critical assets and subsequent alerting to provide an enhanced 20

level of situational awareness. 21

Enhanced vulnerability assessment capabilities to allow for proactive 22

remediation of vulnerabilities to minimize threats to critical assets. 23

43 Our forecast is based on our historical annual expenditures required to address the NERC CIP mandate.

29

Enhanced forensics and security analytics to identify questionable activity and 1

allow for more timely remedial action. This will address insider threats and 2

unauthorized access initiated by various devices and individuals. 3

4. Analysis 4

a) Alternatives Considered 5

One potential alternative is to allow each SCE Operating Unit and project to 6

select and implement individual cybersecurity solutions. This would be the most basic approach. If 7

adopted, information security cohesion across the enterprise would be lost. This would result in 8

disparate information security solutions being implemented that may not be compatible. In addition, 9

dissemination of security alerts would become difficult to perform, causing timeliness of mitigation to 10

be reduced. This would result in excessive exposure to critical risks. Based upon internal experience 11

integrating disparate technologies, this approach is likely to result in higher implementation and 12

operating cost and will increase exposure to non-compliance with regulatory mandates. Fines for non-13

compliance with regulatory mandates vary depending upon severity and can reach up to $1million per 14

day, depending on the situation and SCE’s ability to rapidly respond to implementation of remedial 15

actions.44 16

Another alternative is to simply maintain the existing information security 17

technology and defer new investments to a later date. This approach would make SCE highly 18

vulnerable to cyber attacks, since our defenses could over time be penetrated by attackers. This could 19

result in potentially high levels of business disruption while remedial efforts are executed. SCE would 20

be placed in a continuously reactive state when cyber attacks occur, expending significant resources 21

first, to identify and block unauthorized access, and second, to restore business operations and recover 22

damaged business information. 23

The third alternative is the approach described in the foregoing testimony. By 24

proactively managing cybersecurity from a central environment, SCE will benefit from a common 25

cybersecurity function that is capable of protecting the entire organization. 26

5. Conclusion 27

SCE has seen increases in use of externally hosted business systems, personnel mobility 28

and the use of remote access to SCE’s business information. The continuing dependence on the Internet 29

44 See workpaper entitled “Sanction Guidelines,” Section 3.21, North American Electric Reliability Corporation, Appendix

4B, p. 9, January 31, 2012.

30

for accessing both internal and externally hosted business systems demands that SCE maintain a robust 1

Identity and Access Management capability to help ensure a secure and trusted environment to support 2

the changing business environment. 3

As SCE continues to move away from a single centralized network, the traditional 4

approach for cybersecurity is no longer sufficient. Newer cybersecurity technologies are needed to 5

address the rapidly growing sophistication of threats to our business systems and associated data, and to 6

help ensure systems utilized to manage delivery of power to our customers are also properly protected. 7

Implementing technology for cybersecurity protection and controls is only a portion of 8

the challenge facing SCE’s cybersecurity capability. To confirm that the controls implemented are 9

working, SCE needs to establish a robust unified monitoring capability. This capability will allow SCE 10

to collect cybersecurity information from across the business network and externally hosted 11

environments and establish a central point where the information will be analyzed. Due to the large 12

volume of data and the need for timely identification of potential threats, this unified monitoring 13

capability will utilize information analysis technology. 14

In the area of critical infrastructure, the proposed defense-in-depth strategy will increase 15

end-point and cyber asset security in grid control centers and substations through new and improved 16

controls which are integrated with existing controls. 17

The consequence of not moving in the planned direction will be a fragmented, more 18

complex set of cybersecurity controls and technologies, which will not effectively protect against the 19

evolving threat landscape. The growing sophistication of new threats is rapidly outpacing the capability 20

of current tools and technologies to defend against them. Without new technology, it will be necessary 21

to apply additional human resources to manual monitoring activities due to the limited ability of current 22

technology to perform automated monitoring. This will increase the administrative overhead of 23

manually monitoring for unauthorized access to SCE networks. It may also expose SCE to non-24

compliance with regulatory mandates to protect the confidentiality, integrity, and auditability of critical 25

business information, in the event that a security breach occurs. 26

C. SONGS Cybersecurity 27

1. Background 28

SONGS is operating in a challenging business environment, a rapidly evolving threat 29

environment, and an active regulatory environment. The need for additional cybersecurity measures 30

will be re-examined when SCE has formulated a detailed plan for plant decommissioning. Until all 31

31

systems are off-line, we will continue to address current and potential threats to the SONGS systems as 1

well as the need for additional cybersecurity measures during the shutdown period. 2

In February 2012, SONGS was one of the first nuclear power plants to undergo an NRC 3

Inspection of the plant’s Cyber Security Program. The NRC required nuclear power plants to add 4

specific provisions within their licenses to demonstrate their commitment to cybersecurity. 5

As a result of the inspection, SONGS is required to remediate any issues identified in the 6

inspection as well as advance the plant’s Cyber Security Program. In 2015 SONGS will be re-inspected 7

to validate that the improvement areas identified are remediated and the SONGS Cyber Security 8

Program is integrated into the plant’s operations. Further, the NRC will include cybersecurity 9

inspections on its inspection schedule and will return to inspect the program on a regular basis.45 10

The major Internet security companies all report that targeted cyber attacks and suspected 11

state-sponsored cyber attacks are increasing. As a part of the critical infrastructure, SCE, and by 12

extension SONGS, will be a focus of such efforts. 13

SONGS and the nuclear industry are integrating operating experiences from other plants 14

to improve the effectiveness of the SONGS Cyber Security Program to address issues such as portable 15

media, aging equipment, and other cybersecurity issues. 16


SONGS strategic objectives are to deliver electricity safely and securely to our 18

communities and maintain a high level of emergency preparedness. As a high profile nuclear power 19

plant with 8.4 million people (2010 Census Data) living within 50 miles of the plant, SONGS must 20

maintain a high level of security to its digital systems to achieve these objectives. 21

The SONGS Cyber Security Program vision is to achieve excellence by leveraging SCE’s 22

existing cybersecurity assets and licensing agreements, while addressing cyber issues specific to the 23

plant. The 2015 GRC will further integrate the SONGS Cyber Security Program into the SCE Corporate 24

Cybersecurity Program46 providing a unified security program where resources are leveraged as 25

appropriate. 26

Further, SONGS-specific cyber issues will also be addressed to increase the overall 27

security posture of SONGS. These specific issues include addressing improvement areas found during 28

45 See workpaper entitled “SONGS Critical Digital Asset (CDA) Remediation” for more information on SONGS CDA

Remediation project.

46 See SCE-05, Vol. 01, Chapter II, Section D on Cybersecurity & IT Compliance.

32

the 2012 NRC inspections, and the continuing assessment of Critical Digital Assets (CDAs) under the 1

plant’s Cyber Security Program. Further, the plant’s Cyber Security Program will help drive projects to 2

lower SONGS’ risk profile by implementing plant-specific technologies and remediating risks (e.g., data 3

diode updates). 4



Recorded Costs (2015 case) 2008 2009 2010 2011 2012

NA NA NA NA NA


(Nominal $000)

$2,500.0


2013 2014

$0.0 $0.0

2015

$2,500.0

2016

$2,500.0

2017

CDA Cyber Security Enhancements – Projecting the results of the Cyber Security 6

Assessments performed under the SONGS Cyber Security Program, projects will need to be initiated to 7

remediate any issues identified in the assessments.47 8

Cybersecurity Alignment – Projects in this category include: 9

Replace SONGS Network Intrusion Detection System (IDS) 10

Re-assess data diodes (one-way security appliances used to support SONGS safety 11

functions) 12

Build new mobile media security capabilities 13

Secure ports and network access controls, to prevent unauthorized devices within the 14

secure area from connecting to the network 15

47 See workpaper entitled “Forecast Expenditures for SONGS Cybersecurity” for detail on costs.

33

Table II-14 Project Capital Cost Breakdown

(Nominal Dollars)

2013 2014 2015 2016 2017

Safety and physical security

CDA Assessment remediation $2,000,000 $2,000,000 $2,000,000

Cybersecurity Alignment $500,000 $500,000 $500,000

Replace SONGs IDS

Replace Data Diodes

Additional Mobile media measures

Secure Ports - NAC

Total -$ -$ 2,500,000$ 2,500,000$ 2,500,000$

4. Analysis 1

San Onofre Nuclear Generating Station (SONGS) is faced with a number of challenges as 2

it adapts to operating in the current threat environment. As a part of the critical infrastructure, and as a 3

nuclear power plant, SONGS and its cybersecurity programs have come under increasing focus from the 4

Nuclear Regulatory Commission (NRC) as the number of cyber threats increase. Malware such as 5

Stuxnet and Shamoon have found ways to penetrate isolated secure networks and insert viruses into 6

critical systems in the nuclear and energy sectors.48 7

This increased focus by the NRC and the increased sophistication of cyber threats require 8

an increased level of cyber controls. As part of the increased level of controls, SONGS’ Cyber Security 9

Program and SCE’s Corporate Cybersecurity Program are being aligned to drive efficiencies of scale 10

and increased capabilities. New infrastructure that can be universally managed and monitored across the 11

enterprise will help to enable this alignment. 12

5. Conclusion 13

SONGS’ systems must be remediated as a result of the 2012 inspection and key systems 14

must be enhanced in order to meet the NRC requirements49 and the rapidly changing threat environment. 15

On this basis, funding for the SONGS Cybersecurity projects should be approved. 16

48 See workpaper entitled “Putting SCADA Protection on Radar,” by Marc Solomon, SecurityWeek, May 17, 2012,

available at http://www.securityweek.com/putting-scada-protection-radar, (Last visited April 25, 2013).

49 See workpaper entitled “NRC Requirement 10CFR Sec 73.54,” March 1, 2013.

34

III. 1

REGULATORY MANDATES 2

A. NERC CIP Compliance 3

1. Purpose 4

The purpose of this set of projects is to develop and implement systems and processes 5

that will help SCE sustain its compliance with the North American Electric Reliability Corporation 6

(NERC) mandated Critical Infrastructure Protection (CIP) standards. 7

The Energy Policy Act of 2005 (EPAct) granted the Federal Energy Regulatory 8

Commission (FERC) authority to oversee mandatory reliability standards governing the nation’s 9

electricity grid. FERC certified NERC as the Electric Reliability Organization (ERO) in 2006. On June 10

18, 2007, compliance with NERC-approved CIP reliability standards became mandatory and 11

enforceable. As of now, NERC has developed five versions of CIP standards. The later versions have 12

built upon earlier versions, or revised previous standards. Implementation deadlines for Versions 1, 2, 13

and 3 have already been reached; Version 4 has been approved and is being implemented; Version 5 is 14

presently in the FERC approval process. 15

The original scope of NERC CIP Version 4 was divided into Version 4 and Version 5. 16

On April 19, 2012, FERC approved CIP Version 4 with a requirement to be implemented by April 17

2014.50 On January 31, 2013, NERC requested FERC to approve CIP Version 5. On April 18, 2013 18

FERC issued a Notice of Proposed Rulemaking (NOPR) to propose approval of CIP Version 5 with 19

certain modifications. In this NOPR, FERC also proposed to approve the CIP Version 5 Implementation 20

Plan which allows migration from the current CIP Version 3 directly to CIP Version 5, effectively 21

bypassing implementation of CIP Version 4.51 We estimate that CIP Version 5 auditable compliance 22

will be required by the first or second quarter of 2016. This is a reasonable assumption based on: (1) 23

FERC’s mandate to submit for approval before March 31, 2013, (2) NERC’s request for a quick 24

approval process, and (3) Congressional and White House pressures focused on cybersecurity standards 25

for the nation’s critical infrastructure. 26

The NERC CIP standards use the definition of the Bulk Electric System (BES) as a 27

reference in determining the scope of the mandate. A revised version of the definition, which impacts 28

50 2012 FERC LEXIS 696.

51 2013 FERC LEXIS 676.

35

the original NERC CIP scope, will be effective by April 2013 pursuant to FERC Order 773.52 53 The 1

modified definition removes language that allows for regional discretion in determining the BES scope, 2

establishes a bright-line threshold that includes all facilities operated at or above 100kV, and identifies 3

specific facility categories and configurations as inclusions (in some instances configurations operating 4

below 100kV) and exclusions from the scope of the BES. 5

2. Scope 6

SCE will need to achieve and maintain compliance with CIP Version 5 (estimated mid-7

2016 for auditable compliance) in a way that is consistent with the revised BES definition (effective 8

April 2013).54 9

CIP Version 5, coupled with the revised BES definition, will significantly broaden the 10

scope of assets and controls requiring compliance with CIP standards. For example, the expanded scope 11

of assets will include facilities such as control centers, backup control centers, generation facilities, 12

transmission substations, protection systems, and load shedding systems. Expansion in the scope of 13

controls include systems configuration monitoring, physical access control systems monitoring, 14

interactive remote access controls (to protect cyber assets from electronic interactive remote access 15

originating outside SCE’s network boundaries), role-based training, inbound and outbound electronic 16

access controls, shared and privileged account controls, and BES information access controls.55 17

CIP Version 5 includes language requiring implementation of a Continuous Improvement 18

concept.56 In an expert’s opinion, this means “that there must not only be security, but mechanisms in 19

place to ensure that security be maintained” over time.57 To sustain security over time, processes and 20

other mechanisms will be needed for continuous security performance monitoring, which requires 21

detecting, analyzing, and reporting deficiencies; planning and implementing effective remedies; and 22

auditing the effectiveness of the remedies or corrections. Because CIP Version 5 strives to address the 23

52 2012 FERC LEXIS 2245.

53 See workpaper entitled “Definition of Bulk Electric System,” Federal Energy Regulatory Commission (FERC) Reliability Standards Glossary of Terms, 2012.

54 NERC submitted CIP Version 5 to FERC for regulatory approval on January 31, 2013.

55 See workpaper entitled “Secure Interactive Remote Access,” North American Electric Reliability Corporation, November 2010.

56 See workpaper entitled “A Focus on Correcting Deficiencies,” North American Electric Reliability Corporation, Industry Webinar (1 of 2) for Version 5 CIP Standards – Project 2008-06 Cyber Security Order 706, September 11, 2012.

57 See workpaper entitled “Self-Correcting Cyber Policies,” by Stephen Flanagan, December 2012

36

balance of FERC Order 706 directives, the number and type of assets covered in the project scope driven 1

by Version 5 will be broad and deep, with additional processes and controls.58 The number of facilities 2

and assets in-scope for compliance is estimated to be nine to ten times compared to that of Version 4.59 3

The White House, Congress, and state governments are increasingly focused on 4

cybersecurity. Coupled with the concern that coordinated physical and cybersecurity attacks may have a 5

nationwide impact, it is reasonable to anticipate that the evolving and increasingly sophisticated 6

cybersecurity threats will compel further development and expansion of the NERC CIP standards 7

beyond CIP Version 5 during the 2015 GRC period.60 Based on regulatory history and our 8

understanding of standards implementation requirements, we believe existing cybersecurity tools and 9

processes will need to be upgraded, replaced, and expanded. 10

3. Request Summary 11

SCE will require additional capital funding to meet and sustain compliance with the 12

increasing scope of NERC CIP regulations and mandates. To comply with the expanded requirements 13

of CIP Version 5 and the revised BES definition, SCE will need to implement additional technologies 14

and technical controls including: 15

Technical controls for BES information storage, transit, and use 16

Configuration monitoring, configuration change detection, logging, and unauthorized 17

configuration change alerting 18

Interactive remote access controls including remote desktop controls, encrypted 19

communication tunnels, proxy systems, malware prevention, and network access 20

quarantine 21

Remote access to role-based NERC CIP training for contractors, consultants, vendor 22

support personnel, and SCE employees in outlying service areas 23

Role-based training registration, tracking, compliance alerts, and reporting 24

58 2008 FERC LEXIS 145.

59 See workpaper entitled “Expected Impacts – Transmission.”

60 See workpapers entitled “Testimony of Gerry Cauley,” - President and Chief Executive Officer, North American Electric Reliability Corporation Before The Energy and Power Subcommittee of the House Energy and Commerce Committee Hearing on Discussion Draft Legislation to Improve Cybersecurity of the Electric Grid, May 31, 2011, and “Testimony of Joseph McClelland,” - Director, Office of Electric Reliability Federal Energy Regulatory Commission Before the Committee on Energy and Natural Resources, United States Senate, May 5, 2011.

37

Inbound and outbound traffic monitoring, logging, and security events alerting for 1

electronic security perimeters 2

Advanced access controls (e.g., biometrics) 3

Shared and privileged account management systems 4

Monitoring of physical access control systems, logging, and security events alerting 5

Secured and non-shared test systems for BES cyber systems 6


a) Detailed NERC mandated Business Requirements 8

CIP Version 5 includes 10 standards: CIP-002-5 through CIP-011-1 (see table 9

below). In the published CIP versions, all of the CIP standards include specifications for Applicability, 10

Requirements, Measures of Compliance, Violation Risk Factors, Violation Severity Level, and 11

additionally in Version 5, there are specifications for Guidance and Technical Bases. 12

38

Table III-15 NERC CIP Standards Requirements

CIP 002 CIP 003 CIP 004 CIP 005 CIP 006

Cyber Systems Impact Rating

Security

Management Controls

Personnel and

Training

Electronic Security

Perimeters

Physical Security

Controls

Identify Cyber Systems/Assets

Identify High Impact

cyber assets

Identify Medium Impact cyber assets

Identify Low Impact

cyber assets

Annual Review

Annual Approval by CIP Senior Manager

High & Medium Impact Cyber

Security Policy

Low Impact Cyber Security Policy

Leadership

Identification

Delegation of leadership authority

Quarterly Awareness Training

Annual Role-based

Training

Personnel Risk Assessment

Access Authorization

Access Review

Access Revocation

Define Electronic Security Perimeter(s)

Define Electronic Security Access

Points

Access Controls to Cyber Assets

Interactive Remote

Access Controls

Physical Security Plan

Two or more Physical

Access Controls

Physical Access Monitoring, logging

& Alarms

Visitor Control Program

Access Control

Systems Testing & Maintenance

CIP 007 CIP 008 CIP 009 CIP 010 CIP 011

Systems Security

Controls

Incidents

Reporting & Response Planning

Recovery Plans For

Cyber Systems

Configuration

Management & Vulnerability Assessment

Information Protection

Physical & Logical Ports Protection

Security Code

Upgrades

Malicious code prevention

Access logging &

monitoring

Strong Access Authentication

Shared & Generic Access Accounts

Management

Identify, Classify, and Respond to Cyber Security Incidents

Report Cyber

Security Incidents to NERC

Cyber Security Response Team

Test Cyber Security

Response Plans Annually

Recovery Plans

Data for Recovery & Backups

Preserve Data for

Forensics

Test Recovery Plan(s) Annually

Manage Changes to Recovery Plans and

Team

Monitor & Manage Changes to Cyber Systems baseline

Configuration

Investigate Unauthorized

Changes to Baseline Configuration

Test Configuration

Changes

Assess Cyber Systems

Vulnerabilities Annually

Develop & Execute Remediation Plans

Identify Cyber Systems Information Requiring Protection

Protect & Securely

Handle Cyber Systems Information

including storage, transit, & use

Prevent Unauthorized

Retrieval of Information in Reuse or Disposal of Cyber

Systems

In contrast to CIP Version 3, which includes 8 standards, CIP-002-4 through CIP-1

009-4, CIP Version 5 has 2 additional standards: CIP-010-1 and CIP-011-1.61 CIP-010-1 mandates 2

additional, specific and stringent configuration management controls and processes, while CIP-011-1 3

61 See workpaper entitled “CIP-010-1 – Cyber Security and CIP-011-1 – Cyber Security – Information Protection,” 2012.

39

mandates additional and broad protection and secure handling of BES Cyber System Information, 1

including storage, transit, and use. CIP Version 5 requires the identification of BES assets to be 2

categorized into high, medium and low impact ratings for which appropriate controls will be applied as 3

specified by the detailed requirements in each standard. 4

CIP Version 5 includes the following major new requirements: 5

Delegation of authority from the CIP Senior Manager governing the 6

implementation and compliance of CIP standards shall be documented and 7

updated in a timely manner 8

Policies governing the implementation and compliance of the CIP 9

requirements shall correspond to the categorization ratings of the assets 10

Access (electronic and/or physical) will be provisioned only after meeting all 11

pre-requisites, e.g., personnel risk assessment, cyber security training and/or 12

role-based training, and authorization by designated resources 13

Periodic audit of authorization records vs. provisioned access in the BESs 14

Periodic audit of implemented access of all users accounts, user account 15

groups, or user role categories, and audit that their specific, associated 16

privileges are correct and are those that the company determines to be 17

necessary 18

Interactive remote access to BESs will need to be protected by intermediate 19

devices or proxy systems62 20

Inbound and outbound traffic permissions are required for network traffic 21

traversing through electronic access points 22

Two or more different physical access control methods are required for 23

high/medium impact rated BESs and associated assets 24

Inventory and manage default, shared, or privileged accounts, including 25

individuals who have authorized access, and enforce periodic password 26

changes 27

Implement and monitor baseline configuration; authorize, test, and verify 28

configuration changes prior to operational implementation 29

62 For the definition of “intermediate device,” see workpaper entitled “Secure Interactive Remote Access,” North American

Electric Reliability Corporation, November 2010.

40

Implement controls for the protection of BES system information including 1

storage, transit, and use. 2

b) Program Approach 3

The program will utilize cross functional teams from SCE’s Regulatory 4

Operations, Transmission & Distribution, Operations Support, Information Technology, Generation, and 5

Power Procurement Operating Units so the appropriate stakeholders, staffing resources, and 6

management are included in the compliance activities. All SCE personnel that support, maintain, or 7

manage the in-scope assets must be trained and adhere to the controls as mandated by NERC. 8

In addition, this program focuses on developing and implementing new or 9

enhanced business processes and systems as well as organizational roles and responsibilities to manage 10

and sustain NERC CIP compliance within SCE. 11


Table III-16 Recorded Costs (Nominal $000)


$3,726.2 $2,787.6 $4,806.1 $7,242.2 $1,092.2

The recorded costs from 2010 to 2012 included the following projects: 13

NERC CIP Document Management Work Flow Project (2010-2011) – This project 14

implemented functions automating work flow for evidence generation, attestation, 15

storage, and audit preparation. ($ 4.89 million). 16

NERC CIP Security Event Monitoring Project (2010-2012) - This project 17

implemented upgrades to the security event monitoring and analysis functions for 18

NERC CIP assets. ($ 0.34 million). 19

NERC CIP Automation Project (2011-2012) – This project implemented a 20

consolidated database for provisioned electronic and physical access to systems in 21

NERC CIP compliance scope, and included functions for electronic and physical 22

access management reporting, access revocation work flow, integration with human 23

resources, and training systems for NERC CIP training management and reporting. 24

($2.23 million). 25

41

NERC CIP Common Cybersecurity Services Project (2011-2012) – This project 1

implemented a set of functions for hardening electronic security perimeters against 2

cyber intrusions and attacks, and includes PKI (digital certificates authentication), 3

boundary enforcement, application rules enforcement, device hardening, and auditing 4

requirements. ($ 5.68 million). 5

The total forecast amount for 2010-2012 was $26.278 million. The total recorded 6

expenditure for 2010-2012 was $13.141 million. The discrepancy between forecast and recorded totals 7

is due primarily to the extended regulatory proceedings in the development and approval of NERC CIP 8

standards. This was not anticipated in 2009 when we submitted our 2012 GRC, and led to deferral of a 9

major portion of forecast capital expenditures to future years to mitigate risks of technology 10

obsolescence as a result of the change in expected compliance timeline for CIP Version 5. 11

Table III-17 Project Capital Cost Forecast

(Nominal $000)

$5,100.0


2013 2014

$4,800.0 $6,525.8

2015

$7,000.0

2016

$4,800.0

2017

Over the five-year period, we forecast a total of $9.87 million of labor expenses and 12

$18.36 million of non-labor expenses (a combination of specialized hardware and software). During 13

2013, the project focus is on CIP-002 through CIP-007 where we estimate $1.35 million in labor and 14

$3.45 million in non-labor expenses. Then for years 2014 through 2017, the project will include all ten 15

CIP standards for the remaining cost of $8.52 million in labor costs and $14.91 million in non-labor 16

expenses. 17

The cost forecast63 discussed below is based on our experience implementing the 18

previously mandated NERC CIP requirements. We forecast labor and non-labor expenses based on the 19

current understanding of the NERC CIP requirements and the significant changes to the mandate that are 20

approved or in process of regulatory approval. SCE uses a standard methodology to forecast capitalized 21

expenditures for most new capital projects and refreshes of existing applications as discussed in Chapter 22

I, Section E of this Volume. 23

63 See workpaper entitled “NERC CIP Cost Breakdown.”

42

Due to the prolonged process to complete the standards development cycle for the major 1

changes we had anticipated in the past, we deferred a major portion of our capital funding from the years 2

2010-2012 to the years 2014-2017 based on the understanding that CIP Version 5 was submitted to 3

FERC in January 2013 for regulatory approval. We anticipate, based on past approval timelines of CIP 4

Version 3 and Version 4, the approval process will complete by early 2014, and CIP Version 5 will 5

become effective by first or second quarter of 2016. However, given the increased focus of the White 6

House, Congress, and state governments on cybersecurity, we anticipate there may be additional 7

mandates from FERC beyond what is already submitted in CIP Version 5, and we account for this 8

assumption in our capital forecast for 2017.64 We may need to make adjustments when the final results 9

of the regulatory approval process are known. 10

We have made the following assumptions to develop our cost forecast: 11

Costs are forecast based on our current understanding of the proposed NERC CIP 12

revisions 13

Previously implemented systems will be scalable to meet the expanded scope of the 14

NERC CIP revised standards 15

Re-evaluation and/or replacement of existing systems to meet the broader scope are 16

not contemplated and costs for those activities are not included 17

Labor hours for implementation and enhancement work are based on a blended rate 18

and the rate is provided in the assumption section of the cost estimation worksheet65 19

Costs address the significant changes to scope of the existing program based on 20

FERC-mandated changes projected for implementation in the 2013–2017 timeframe 21

Deferred projects due to delays in regulatory proceedings will need to be 22

implemented in this period 23

Significant network infrastructure improvements will be required and will need to 24

allow for security monitoring and protection at remote bulk electric substations. 25

The forecast capital funding will be used to implement and maintain compliance with 26

NERC CIP Version 5, which will require the following: 27

64 2013 FERC LEXIS 676.

65 See workpaper entitled “NERC CIP Cost Breakdown.

43

Make significant network infrastructure improvements to allow for security 1

monitoring and protection at remote bulk electric substations 2

Implement technical controls to protect Bulk Electric System (BES) information in 3

storage and in transit 4

Automate configuration monitoring, configuration change detection, logging, and 5

unauthorized configuration change alerting 6

Implement interactive remote access controls including remote desktop controls, 7

encrypted communication tunnels, proxy systems, malware prevention, and network 8

access quarantine 9

Implement remote access to role-based NERC CIP training for contractors, 10

consultants, vendor support personnel, and SCE employees in outlying service areas 11

Role-based training registration, tracking, compliance alerts, and reporting 12

Implement inbound and outbound traffic monitoring, logging, and security events 13

alerting for electronic security perimeters 14

Implement advanced access controls (e.g., biometrics) 15

Automate shared and privileged account management processes 16

Upgrade and expand monitoring, logging, and security events alerting for physical 17

access control systems66 18

Project management and support costs to run projects. 19

66 See SCE-07, Vol. 4, Chapter II, Testimony of Jana Monroe, for the request associated with physical control systems

necessary to comply with NERC CIP v5.

44

Table III-18 Project Cost Breakdown

(Nominal $000)

Description 2013 2014 2015 2016 2017

CIP‐002 ‐ Asset Identification 404 210 216 106

CIP‐003 ‐ Security Management 460 210 137 106

CIP‐004 ‐ Access Management 2,410 1,120 1,620 965 920

CIP‐005 ‐ Electronic Security Perimeters 710 910 985 1,736 1,386

CIP‐006 ‐ Physical Security 1,410 614 321 59 106

CIP‐007 ‐ Systems Security Management 270 1,144 1,056 236 1,066

CIP‐008 ‐ Incident Response 94 57 59

CIP‐009 ‐ Recovery Planning 94 57 59

CIP‐010 ‐ Configuration Management 795 1,840 772 716

CIP‐011 ‐ Information Protection 891 644 561 694

Total NERC CIP Capital 4,800 6,526 7,000 4,800 5,100

6. Conclusion 1

To date, SCE has been successful in keeping its NERC CIP cyber assets secure. We have 2

also effectively maintained compliance with the current NERC CIP standards. In 2012 SCE 3

successfully completed its first CIP audit with the Western Electricity Coordinating Council (WECC). 4

One lesson learned from this audit was the need to strengthen our shared and privileged accounts 5

management processes. Compliance with the new NERC CIP mandates (Revised Definition of BES and 6

CIP Version 5) will require us to further improve our organizational capabilities for the management of 7

shared and privileged accounts. This section requests approval for $28.2 million in total incremental 8

capital funding for the period 2013-2017. Due to the delays in regulatory proceedings we deferred a 9

major portion of our capital funding from the previous period (2010-2014) to this period (2013-2017).67 10

These funds will allow SCE to continue to develop, implement, and enhance its systems, tools, physical 11

and electronic security access controls, related business processes, policies, and training programs to 12

improve the management of SCE’s BES cyber systems and assets (currently known as critical cyber 13

67 Capital funding requested in the 2012 GRC for period 2010-2014 was $39.8 million. Recorded 2010-2012 capital costs

were $13.1 million compared to 2010-2012 forecast of $26.3 million, with a difference of ($13.2 million). This capital funding request for 2013-2017 is $28.2 million.

45

assets), and maintain compliance with the standards as mandated by FERC and NERC. Our estimates of 1

required work and costs are reasonable and are based on the best available information.68 2

Maintaining compliance with current and future NERC CIP standards is a critical part of 3

protecting the reliability of the Bulk Electric System. Non-compliance could result in significant fines 4

of up to $1,000,000 per incident per day,69 may compromise reliability and security of the 5

interconnected Bulk Electric System (designated by Department of Homeland Security as part of the 6

Energy Sector National Infrastructure), and loss of credibility with our federal and state regulators and 7

our customers. 8

68 For labor costs estimates we use a lower blended rate than the one we used for our past period ($90/hour for this period

as compared to $105/hour for the past period) due to efficiencies gained as more internal resources are now proficient with NERC CIP compliance and implementation.

69 See workpaper entitled “Sanction Guidelines,” Section 3.21, North American Electric Reliability Corporation, Appendix 4B, p. 9, January 31, 2012.

46

IV. 1

EXPANDED CAPABILITIES 2

A. Service Management System 3

1. Background 4

The Service Management System leverages a business view of IT services, enabling the 5

IT support organization to quickly resolve or escalate issues and problems, improve root cause isolation, 6

and provide higher levels of business user satisfaction. The Service Management System also helps to 7

establish the basis for effective IT service management by documenting the unique attributes of each 8

configuration item (CI) in the infrastructure, including applications. 9


The technology for controlling configuration management is evolving rapidly in support 11

of more complex systems. Currently SCE has installed the product called HP Service Manager Version 12

7.10, which has several problems: 13

1. By the end of 2013, we will require a significant product upgrade or replacement to 14

enable supporting the maturity of IT business processes for enterprise change and 15

release management along with the underlying configuration management capability. 16

2. The HP product line does not support a detailed level of application discovery for 17

applications running on servers and mainframes located in SCE’s data centers. 18

3. The HP product lacks the automatic application discovery capability that is required 19

in our new data center when running 24X7 operations where the server environment 20

is changing due our capability to virtualize70 the server configurations. 21

After our initial application installation in 201171 using HP Service Manager Version 22

7.10, SCE planned on upgrading this version to the latest supported version by HP when it became 23

available. Also, the 24x7 operation of complex data centers located in Rosemead, Irvine and Alhambra 24

require maintaining the HP Service Management System on the vendor supported versions of the 25

product in order to ensure continued reliability. However, after further analysis, SCE determined that it 26

would be more cost effective and strategically beneficial to move away from the current HP product and 27

replace it with the industry leading integrated Service Management suite by BMC consisting of the 28

70 A virtualized server configuration provides an environment for a user to run several software-created “virtual” machines,

each with its own separate operating system, on a single hardware server.

71 The Configuration Management Database Project (CIT-00-DM-DM-000001) was forecast in the 2012 GRC.

47

products Remedy ITSM 8.0 and Atrium CMDB (Configuration Management Database).72 In addition, 1

the BMC products will bring all ITIL73 processes into one tool, simplify process integration and simplify 2

the use of the tool at SCE where many of the data center processes are based on ITIL. 3

The BMC products Remedy ITSM 8.0 and Atrium CMDB (Configuration Management 4

Database), which are integrated together by BMC, support a detailed level of application discovery for 5

applications running on servers and mainframes located in SCE’s data centers. This capability is 6

especially needed for discovering where at any moment the applications are being housed using our 7

virtualized server configurations. This information is needed for solving computer and application 8

problems and planning server maintenance. 9


The table below illustrates the recorded and forecast expenditures for the Service 11

Management System. SCE recorded $2.11 million for the period 2008-2012 as depicted in the table 12

below. 13

Table IV-19 Service Management System Expenditures

(Nominal $000)

2008 2009 2010 2011 2012

$0.00 $0.00 $0.00 $0.00 $2,110.00

Recorded Cost (2015 Case)

a) Recorded Expenditures 14

In 2012 we spent $2.11million to purchase BMC’s Remedy ITSM 8.0 and Atrium 15

CMDB to replace the aging Service Management System, HP Service Manager Version 7.10, in order to 16

address the business requirements outlined above. The BMC products integrate various ITIL processes 17

using the configuration management database and discovery technology as the central repository of data 18

center asset information. This allows users an end-to-end view of all the technology assets, and the 19

workflow needed to support the assets, throughout their lifecycle. As such, the new Service 20

72 See workpaper entitled “Remedy ITSM 8.0 and Atrium CMDB ROI Analysis for Supporting ITIL Processes.”

73 The Information Technology Infrastructure Library (ITIL) is a set of practices for IT service management (ITSM) that focuses on aligning IT services with the needs of business.

48

Management System will include the following capabilities from BMC, which also align with our work 1

practices: 2

Remedy Service Desk (Incident & Problem Management) 3

Remedy Change Management (Includes Release Management) 4

Remedy Asset Management 5

Remedy Knowledge Management 6

Service Request Management (Service Catalog) 7

Atrium Service Level Management 8

Atrium Analytics and Reporting 9

Service Management Process Model 10

Atrium Discovery and Dependency Mapping 11

Configuration Management Database (Atrium CMDB) 12

b) Forecast Expenditures 13


new capital projects and refreshes of existing applications as discussed in Chapter I, Section E of this 15

Volume. In 2013 we estimate $2.210 million to install, configure and deploy Remedy ITSM 8.0 and the 16

Atrium CMDB (see table below and workpaper forecast).74 This activity will include system 17

integration, process realignment and end user training.75 18

Table IV-20 Service Management System

(Nominal $000)

2013 2014 2015 2016 2017

$2,209.90 $0.00 $0.00 $0.00 $0.00

Capital Cost Forecast (2015 Case)

4. Conclusion 19

For the forecast period, we estimated capital and expenses to install the new Service 20

Management System to support the rapidly evolving IT environment for SCE. The new Service 21

74 See workpaper entitled “Forecast Expenditures Service Management System.”

75 See workpaper entitled “Investment Memo for Service Management System.”

49

Management System will bring our ITIL processes into one tool, simplify our process integration, and 1

provide us with an end-to-end view of our technology assets, which will allow us to more efficiently 2

support those assets. 3

B. Enterprise Data Management Services 4

1. Data Masking and Subsetting Project 5

Table IV-21 Data Masking and Subsetting Project

Project Name Data Masking and Sub-setting Project

Portfolio IT

Application Age n/a

Replacement Date Various

Estimated Costs $1.14 Million

a) Background 6

Data management services for the enterprise should be developed as a focused, 7

centralized effort to properly manage both development and operational complexity for data stored in 8

multiple platforms and technologies. This approach is more cost effective than having individual areas 9

creating disparate data solutions. Database technologies are changing quickly, providing opportunities 10

to more efficiently meet SCE’s data storage needs. 11

This project will implement a technology solution and operational processes for 12

securing our test data. It will enable us to discover and mask confidential data fields so the values are 13

changed into “fake” identities. An example of confidential data is personal information for Edison 14

customers. In most cases there is no requirement to keep copies of confidential data in our test 15

environments. When test data is needed it should be prepared by masking any confidential data fields so 16

we minimize the risk of it being improperly viewed or handled. The requested solution will also allow 17

us to make smaller subsets of data for testing. It will do this in a way that does not compromise our 18

50

ability to develop and test applications. Following these practices to properly safeguard our 1

confidential data supports SCE’s corporate privacy policy.76 2

b) Business Requirements 3

(1) Problem Statement 4

Today, a common practice is to make a full unmodified copy of 5

production data for use in our development and testing environments. Having production volumes of 6

data is unnecessary for most development and testing purposes. Test environments are generally more 7

accessible than production. Having unmasked confidential data in test environments presents an 8

unnecessary risk for exposure or loss of confidential data. 9

Protecting data privacy and ensuring our confidential data is not exposed 10

is the most important business need to be addressed by this project. With some exceptions, production 11

data is regularly copied without any masking or hiding of confidential data to our test environments. A 12

recent internal survey showed that over 30 of 70 test databases refreshed from production during a three 13

month period contained some form of confidential (personal) data.77 Sub-setting the data in our test 14

environments to have smaller test databases is another business need. It will save costs for data storage 15

by making management of test data more agile and efficient as we work with smaller and more easily 16

managed test data sets. 17

(2) Recommended Approach 18

We will purchase and implement tools that will support effective 19

management of test data including (a) identifying confidential data in our databases, (b) defining and 20

implementing the masking rules to change the values of those confidential fields into something that is 21

not confidential but is still useful for development and testing, and (c)sub-setting of production data 22

volumes into smaller test databases. We will implement this capability and these operational processes 23

to subset and mask test data for selected business critical applications. We will align organizational 24

roles and responsibilities to support this function. 25

We will use an RFP process to find commercial tools that will 26

automatically subset data and mask confidential fields based on user configuration. We will find and 27

select tools that support our different database management systems (e.g., DB2 and Oracle). Ideally all 28

of the tools will be from a single vendor that can be used as an integrated solution. Engagement with the 29

76 See workpaper entitled “Edison’s Corporate Privacy Policy.”

77 Our internal review of our application testing practices discovered the use of confidential data for testing software.

51

business Data Governance function needs to occur to clearly define our requirements. A technology 1

architecture needs to be defined and implemented to support those requirements and the data masking 2

and sub-setting functions. We believe this will include a set of masking/sub-setting tools on application 3

servers along with a staging database environment where the data would be copied to and stored for sub-4

setting and masking. The prepared data could then be loaded into a non-production environment for use 5

by application development and testing teams. 6

The scope of this project would be to define business requirements and 7

priorities and select, acquire and implement the right set of tools to mask and subset our data for test 8

environments. The project will include setting up a masking process for selected critical databases only. 9

The data masking process will integrate with organizational roles and responsibilities that will allow 10

masking to be developed and implemented for other databases as funding and resources become 11

available after this initial project is complete. 12

The following are project sub-elements: 13

Document data masking and sub-setting requirements 14

Select masking and sub-setting tools to purchase 15

Negotiate for and purchase tools 16

Select targeted databases 17

Identify confidential data in targeted databases 18

Determine detailed rules for masking data 19

Determine detailed rules for sub-setting data 20

Design solution architecture 21

Install new servers 22

Install masking and sub-setting software on new servers 23

Discover confidential data fields in targeted databases 24

Configure and test data masking rules 25

Configure and test data sub-setting rules 26

Implement sub-setting and masking scripts 27

Develop roles and responsibilities 28

Train teams for new roles 29

Document new procedures. 30

52

Modify existing development and testing procedures as needed. 1

Operationalize data sub-setting and masking 2

Key benefits include: 3

Significantly reduced risk of data privacy breach 4

More efficient and secure management of test data 5

Reduce storage requirements and cost for test databases 6

c) Recorded and Forecast Expenditures 7



Volume. SCE requires an estimated $1.143 million in funding where we plan to spend $0.667 million, 10

$0.263 million, $0.100 million, and $0.113 million, for each of the years 2014 through 2017, 11

respectively.78 The cost estimation details for this project are based on the following actions and 12

preparations in connection with acquiring the software tools79: 13

Continued vendor support for database platforms including Oracle, SQL 14

Server, DB2 and Teradata. 15

Acquisition of a software tool for confidential data discovery, data masking 16

and data sub-setting. 17

Implementation of the purchased tools on application servers. 18

Implementation of database staging environments where the masking and sub-19

setting operations will be performed. Assume that existing lower cost 20

environments (e.g., packaged virtual solutions) could be used for this need. 21

Development of a masking process for a limited number of application 22

databases to be decided based on a later prioritization (limited by available 23

funding). 24

This solution will not replace the current data masking and sub-setting process 25

used for the Customer Service System (CSS) database. 26

78 See workpaper entitled “Forecast Expenditures for Data Masking and Subsetting Project.”

79 See workpaper entitled “Investment Memo for Data Masking and Subsetting Project.”

53

Support for the tool and the process will reside with the Data Management 1

function in IT’s Enterprise Information Management & Architecture 2

organization. 3

Sufficient space is available on existing Teradata servers to support masking 4

activity. 5

Vendor agrees to pre-paid maintenance for data masking software. 6

d) Conclusion 7

This project will better protect for data privacy so our confidential data is not 8

exposed to unauthorized or accidental disclosure, while not compromising our ability to develop and test 9

applications using realistic data. 10

C. Shared Enterprise Integration Services and Upgrades 11

1. Integration Product Refresh and Upgrade Deployments 12

Table IV-22 Shared Enterprise Integration Infrastructure

Project Name Shared Enterprise Integration Infrastructure

Portfolio IT

Application Age Various



a) Background 13

The purpose of the Shared Enterprise Integration Infrastructure project is to 14

upgrade and enhance our Service-Oriented Architecture (SOA) that supports a wide range of our 15

applications and associated interfaces. SOA is a software design and architecture based on structured 16

collections of discrete software modules, known as “services,” which collectively provide the complete 17

functionality of a large software application. The purpose of SOA is to allow easy interaction of a large 18

number of computers that are connected over a network. Every computer can run an arbitrary number of 19

54

services that are built in a way that they can exchange information with any other service available 1

through the network without human interaction and without the need to make changes to the underlying 2

services themselves. 3

There are many advantages to using a SOA. SOA allows users to connect 4

services in various configurations to create ad hoc applications built around the existing services. 5

During the development of new applications, it takes much less time to use an existing service that to 6

build that capability over and over again. This results in a lower cost of development. Once a service is 7

establish and tested, it can perform the same reliable function over a wide variety of ad hoc applications. 8

Changes to the underlying application will not affect the service and therefore enhancements and 9

upgrades are often faster and less costly. Furthermore security and reliability are often enhanced as the 10

services are built and tested once. Instead of building a custom solution for each new application, once a 11

service is tested, it will work the same way for every additional application that “plugs into it.” Thus it 12

becomes a more reliable solution and leaves less chance that there could be a breach in security through 13

an additional interface. 14


Our SOA requires maintenance and upgrades since most of our services are based 16

on vendor supported software. Keeping near-current with these modules is important as upgrades often 17

provide important security updates vital to maintaining a safe and secure environment. Almost $10 18

million of our request is for these upgrades to existing software as described in Table IV-23. 19

We are also building out new services to accommodate the increasing complex 20

environment of applications that are required to meet business and regulatory demands. One of the most 21

important of these new services is the Grid Control Center Operational Bus. This new service will 22

provide an electronic communications highway designed to provide the California Independent System 23

Operator (CAISO) with timely, secure, robust and flexible delivery of operational status information 24

about the SCE electric power grid. Without such a bus, we would have to build separate interfaces from 25

all of the devices and systems from which CAISO wants operational data. Additionally this bus will 26

allow CAISO to send information directly back to the SCE devices and applications. This new service 27

is estimated to cost approximately $10 million. 28

Other smaller service enhancements are also planned during 2014-2017. A brief 29

description of these other services can be found in the workpapers for this project.80 30

80 See workpaper entitled “Additional SOA Enhancements.”

55


SCE needs to maintain and expand its SOA infrastructure. As vendors 2

upgrade their software, SCE analyzes the advantage of the upgrades and associated upgrade costs. The 3

deciding factors include, but are not limited to, whether the upgrades will provide security 4

enhancements, bug fixes, functionality improvements, and increased speed,81 and the availability of 5

version support. 6

When new business needs arise (e.g., the need to share data with CAISO 7

in a real-time or near-real-time environment) we examine cost effective SOA services that we can reuse 8

to lower our total development costs over time. The use of standardized SOA component services 9

provides many benefits, including those which we have discussed above. We would expect this trend to 10

continue and expect our re-use of SOA services and expansion of our SOA capabilities to increase over 11

time. 12


Our request provides a balanced approach to upgrading several of our 14

current software service products as well as adding new capabilities that will provide immediate 15

business benefit (e.g., the Grid Control Center Operational Bus) as well as develop or procure services 16

that can be reused in the future. Table IV-23 illustrates the planned implementation date of these 17

upgrades and enhancements. Our upgrades are planned around vendor software release dates (and end 18

of support dates for older versions). Our new capabilities are planned to coincide with business driven 19

capability delivery dates that may be externally driven (e.g., CAISO) or in coordination with larger 20

project requests. 21



new capital projects and refreshes of existing application as discuss in SCE-05, Volume 1, Chapter III, 24

Section 3.c. Our total request for 2013-2017 is $24.45 million, which is detailed in Table IV-23. A 25

more detailed breakdown of these expenses can be found in the project workpapers.82 26

81 Some of our services send data through networks. Some enhancements improve latency or speed of these network

transactions.

82 See workpaper entitled “Investment Memo for Shared Enterprise Integration Infrastructure.”

56

Table IV-23 Funding Requirements

(Nominal $000,000)

Sub‐Project Description 2014 2015 2016 2017 Total

Complex Events Processing 0.000 1.317 0.000 0.000 1.317

Business Rules Management 0.000 0.659 0.000 0.000 0.659

.Net and JEE Services Environment 0.267 0.000 0.067 0.000 0.333

Enterprise Services Monitoring Environment 0.533 0.000 0.134 0.000 0.667

Grid Control Center Operational Bus 0.000 3.293 3.341 3.753 10.387

SAP PI/PO (EAI middleware, BPM platform)

upgrade and refreshes 0.853 0.000 0.234 0.000 1.087

Services repository and registry configuration and

upgrade 0.000 0.856 0.367 0.751 1.974

Websphere ESB – upgrades and refreshes 0.000 0.033 0.000 1.501 1.534

Datapower appliance upgrades/refreshes 1.493 0.000 0.935 0.000 2.429

MFT (managed file transfer) upgrade/refresh 0.800 0.000 0.000 0.000 0.800

FME upgrade and refresh 0.085 0.000 0.120 0.195 0.401

ETL (IBM Info Server) upgrade 0.768 0.948 0.067 0.000 1.783

Business Objects Data services platform upgrade

and refresh 0.907 0.988 0.000 0.188 2.082

Annual Subtotals and Total 5.707 8.094 5.265 6.388 25.454

Funding (in millions)

Project

Shared

Enterprise

Integration

Services and

Upgrades

New

Upgrades

d) Conclusion 1

Providing integration and SOA as centrally located shared services accessible by 2

the enterprise will avoid the proliferation of duplicative technologies, services and costs. Complex 3

Events Processing (CEP) enabled Business Activity Monitoring will provide real time dashboards to 4

become more responsive to market and customer demands. End-to-End situational awareness will 5

provide tools to improve operational efficiency and reduce costs. CEP will allow real time monitoring 6

and analysis of events from various sources on the electrical network. Real time processing of 7

Advanced Metering Infrastructure data will be used by demand response programs. Usage profiling and 8

proactive service delivery solutions will be enhanced by responding to events as they happen, rather than 9

after the fact. 10

57

D. Data Warehouse Upgrades 1

1. SAP Business Warehouse (BW) HANA Enterprise Data Warehouse Upgrades 2

Table IV-24 SAP BW HANA Enterprise Data Warehouse

Project Name SAP BW HANA Enterprise Data Warehouse

Portfolio IT

Application Age October 2012

Replacement Date January 2015


a) Background 3

SAP Business Warehouse (BW) is an integrated Enterprise Data Warehouse 4

system at SCE. It stores data sourced from SCE’s primary transactional systems, such as finance, 5

human resources, work management, customer information, assets, and other business areas. The BW 6

Data Warehouse is used for analytics, reporting, and decision support by virtually all of SCE’s 7

Operational Units. SAP BW was implemented in July, 2008 and several older-technology disparate 8

database systems were decommissioned after the data was migrated to SAP BW. In October 2012, SAP 9

BW was migrated from a core DB2 database to a core SAP HANA database. Regular SAP license 10

upgrades and hardware to account for data growth in the normal course of business are required. 11



Data growth from the normal course of business occurs on a daily, weekly, 14

and monthly basis. Examples include finance data, such as costs and accounts payable; human 15

resources data such as employee information; customer relationship management data such as business 16

partner and customer service contracts; Transmission and Distribution data such as assets and work 17

management; and SONGS data such as nuclear outage management. About 13% percent data growth 18

58

per year83 has been experienced after data archiving techniques were employed to minimize active data 1

requirements. 2


In January 2015, purchase 0.75 Terabytes of HANA Enterprise License 4

for $0.8 million 5

In January 2015, purchase 10 nodes of IBM HANA appliance (512 GB 6

size each) for $1.2 million 7

In February 2015, install the hardware as extensions to the existing 8

systems, and extend the HANA software across the new footprint. 9




Volume. SCE requires $2.00 million in funding as illustrated in Table IV-25 below.84 This forecast is 13

based on our previous and similar work. This estimate includes the cost of additional software and labor 14

costs for the purchase, integration, and implementation of the SAP upgrade solutions.85 15

Table IV-25 SAP BW HANA Enterprise Data Warehouse Upgrades

(Nominal $000)

2013 2014 2015 2016 2017

$0.00 $0.00 $2,000.00 $0.00 $0.00

Capital Cost Forecast

d) Conclusion 16

Expansion of the SAP BW HANA enterprise data warehouse is designed to 17

mitigate operational issues caused by data growth from the normal course of business. 18

83 See workpaper entitled “SAP…Project,” IT Capital Request – Working paper, April 29, 2013.”

84 See workpaper entitled “Forecast Expenditures for SAP BW HANA Enterprise Data Warehouse.”

85 See workpaper entitled “Investment Memo for SAP BW HANA Enterprise Data Warehouse.”

59

E. Business Intelligence 1

1. Business Intelligence Tools Upgrade Refresh 2

Table IV-26 Business Intelligence Tools Upgrade Refresh

Project Name Business Intelligence Tools Upgrade Refresh

Portfolio IT




a) Background 3

Business Intelligence (BI) is a set of methodologies, processes, architectures, 4

technologies and services which help transform raw data into meaningful and useful information for 5

actionable business decision making. BI provides SCE the essential capability to gain insight into all 6

types of data in order to identify new opportunities and define and implement strategies and services for 7

cost, efficiency, process and operational improvements. 8

These BI technologies and services provide SCE the insight on historical, current 9

and predictive views of business operations via common capabilities such as reporting, analytics, 10

business performance management, online analytical processing, benchmarking and predictive analytics. 11

SCE must stay current with these technologies to meet the demands of the organization and leverage 12

large volumes of data in faster and easier ways to respond timely to customer trends and business 13

operations. 14


In 2005 SCE chartered the SAP Enterprise Resource Planning (ERP) project to 16

eliminate the inefficiency associated with obsolete and disparate software systems, and to integrate the 17

organization’s data and processes into a unified system. As part of each release of the SAP ERP 18

program, SCE successfully implemented the associated BI processes, technologies and services required 19

60

to support analytics and reporting for both historical and current views of business operations. Since 1

then, SCE has expanded this approach to include the BI processes, technologies and services in other 2

systems as well as with SAP, thus increasing the amount of data requiring analysis and reporting. 3


The Business Intelligence Tools Upgrade Refresh project will upgrade the 5

infrastructure and software as required to continue to effectively operate BI capabilities at SCE. Regular 6

upgrades and refreshes are required in order to address software issues and scale the installation of the 7

BI applications based on data growth and usage. This will allow for optimal performance of the BI 8

applications used across the organization. 9

As these products are used by more users, it requires the size of the 10

environments to be reviewed on a regular basis. Sizing is based on how the data will be viewed, the 11

volume of data to be analyzed, the frequency in which data will be distributed, the number of people 12

using the tools and the products to be used. The need to keep the environment current with upgrades to 13

the operating system, application and hardware is required to maintain acceptable performance 14

according to product vendor requirements specifying their supported operating system versions and 15

minimum server hardware capabilities. Otherwise, performance issues will surface resulting in manual 16

efforts, as well as data quality and integrity issues, reducing the efficiency, effectiveness and availability 17

of critical information required for business decision making. 18

As the BI software products and services continue to evolve, technologies 19

such as cloud, mobile, exploration, enhanced data visualization, and predictive capabilities are now 20

standard components of most BI products. As new functionalities are introduced, SCE must keep the 21

existing products current to meet the demands required for business decision support and analysis. 22

Failure to maintain the products with upgrades and refreshes puts the organization at risk of not 23

providing timely and efficient data analysis to ensure we are providing the safest, lowest cost, most 24

reliable solutions to our ratepayers. 25


The implementation of the Business Intelligence Tools Upgrade Refresh 27

will be performed every other year, lagging behind the product vendor releases which are normally 28

published every 12 – 18 months. BI tool products are typically released more often than other software 29

products.86 SCE plans to upgrade and refresh the BI products approximately six months after the 30

86 See workpaper entitled “Hype Cycle for Business Intelligence, 2012,” Gartner Research, August 13, 2012.

61

product vendors release new versions to ensure the stability of the products prior to implementation at 1

SCE. These BI products are key platforms that support all of SCE’s reporting and analytics. There will 2

be two planned upgrades during this GRC cycle targeted for implementation in 2015 and in 2017. 3


The implementation of the Business Intelligence Tools Upgrade Refresh project 5

will be targeted for 2015 and 2017 with a cost of $461,000 and $401,000 for these upgrades, with a total 6

cost of $862,000. The timing of the implementations are planned to match the product vendor software 7

releases, as well as the growth of data and product usage required by the business for operations. The 8

$862,000 total expenditure includes labor and software costs.87 9

Table IV-27 Business Intelligence Tools Upgrade Refresh

Forecast Costs (Nominal Dollars)

Year Forecast Capital Expenditure 2013 $0 2014 $0 2015 $461,000 2016 $401,000 2017 $0 Total $862,000

These labor costs cover technical resources and will be provided by a combination 10

of internal and external resources. Some external resources will be provided by SCE’s offshore model, 11

which is the standard development practice used by SCE, and some will be provided by our strategic 12

integrators using cost estimates based on similar size projects and experience.88 13

d) Conclusion 14

BI provides SCE the essential capability to gain insight into all types of data in 15

order to identify business trends and new business opportunities and further define and implement 16

strategies and services for cost savings and operational efficiencies, process improvements, and 17

operational improvements. 18

87 See workpaper entitled “Forecast Expenditure for BI Tools Upgrade Refresh.”

88 See workpaper entitled “Investment Memo for BI Tools Upgrade Refresh.”

62

F. Business Analytics 1

1. Business Analytics 2

Table IV-28 Business Analytics

Project Name Business Analytics

Portfolio IT




a) Background 3

The Business Analytics Initiative will leverage SCE’s existing business 4

intelligence (BI) platform and tools to develop essential reporting and analytics capabilities to 5

accommodate the continued growth of data as well as the evolving information needs of SCE’s business. 6

This requires additional capabilities to search, explore, share, acquire, transform and visualize data from 7

multiple sources in an efficient manner in order to turn it into actionable information and formats, such 8

as dashboards, reports, alerts, plans, and operational metrics. This project is also required to add the 9

capability to show geographic location and related information. 10


The development of these capabilities will reduce costs for the organization by 12

driving down business and IT labor efforts through self-service, standard reporting, predictive analysis, 13

and reduced data manipulation, all of which result in more time to analyze information for more 14

informed decision making. 15


As the amount and complexity of data at SCE continues to grow (in terms 17

of the volume, variety and velocity of data), it is essential that the business organizations have the 18

capabilities to understand, analyze and to quickly turn the data into actionable information for business 19

decision making. In particular, there are a number of key areas requiring the development of additional 20

capabilities that do not currently exist or are inefficient or inadequate. Examples include standard 21

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enterprise reporting, data visualization, and advanced and predictive analytics. Today, there are multiple 1

“standard” reports resulting in inconsistencies, duplication and a lack of one version of the truth. As the 2

data quantity and complexity continue to grow, it has become extremely difficult to quickly and 3

effectively absorb information, spot patterns, identify aberrations, and see hidden relationships that are 4

not readily apparent in traditional tabular or graphical based BI solutions. This impacts the ability to 5

determine or even predict the best course of action to take based on the information available. 6

The impact of this gap in capabilities has never been more evident than 7

now as we have recently experienced severe storms and did not have these capabilities to easily 8

consume and understand the information for critical decision making.89 This is because the data was 9

coming in inconsistently from disparate systems and could not be aggregated in a manner to be useful 10

for decision making. The volume and rate of data increase in the areas of power trading and grid 11

reliability are also good examples, because of the need to analyze dynamic, real-time data, and 12

demonstrate the need to leverage our platform to develop these essential capabilities. Addressing 13

business trends and reliability events based on the real-time data will help improve business operations 14

and reliability, while reducing overall costs. 15


The Business Analytics Initiative includes improvements to the Standard 17

Enterprise Reporting tools needed to enhance our existing enterprise reporting. This includes the 18

refinement of standards around BI data governance and report design processes, and the creation of a 19

common set of user training material. The initiative will focus on the identification and development of 20

consistent reporting standards across the enterprise as well as the consolidation of similar or duplicate 21

reports within our current reporting systems and tools. This will result in improved usability of data, 22

and ensure accurate, consistent and controlled data (one version of the truth), as well as result in the 23

capability for better business decision making and reduced costs through improved operational 24

efficiencies. 25

The Business Analytics Initiative also includes data visualization tools 26

which will allow SCE to communicate information more clearly and effectively through graphical 27

means. One particular area using advanced and predictive analytics tools will allow SCE to exploit 28

patterns found in historical and transactional data to identify business risks and opportunities. The 29

89 One of the findings of the SCE Storm Response analysis and recommendations discussed in SCE-05, Vol. 2, Part 2,

Section II.A “Storm and Grid Operations Management Projects.”

64

development of data visualization and advanced and predictive analytics tools with our computing 1

environment will maximize the accessibility to multiple sources of data while providing the ability to 2

visualize the information in a way that draws maximum insight from the information. The initial focus 3

for the development of data visualization capabilities will be in the areas of situational storm awareness, 4

as well as smart meter and grid operational awareness. The initial focus for the development of 5

advanced and predictive analytics will be in the areas of power delivery asset utilization and 6

replacement prioritization as well as energy demand modeling for better purchasing decisions. 7

The development of these capabilities will be spread across 5 years. It will 8

start in 2014 and continue through 2017, with a total cost of $3.71 million. The implementation over 5 9

years is a phased approach to match the anticipated growth in data 90 and to develop the necessary 10

structure in the data warehouse to meet the reporting and analytics needs. The expenditures are for labor 11

costs for the analysis, design, development, and implementation of these capabilities. 12


Table IV-29 Business Analytics Forecast Costs

(Nominal Dollars)

Year Forecast Capital Expenditure

2013 $0

2014 $960,000

2015 $1,922,500

2016 $523,400

2017 $300,200

Total $3,706,100

These forecast expenditures cover functional and technical resources and will be 14

provided by a combination of internal and external resources. Some of the external resources will be 15

provided by SCE’s offshore model, which is the standard development practice used by SCE, and some 16

will be provided by our strategic integrators. We developed our forecasts using cost estimates based on 17

90 See SCE-05, Vol. 1, Chapter III, Section A. 4, “Disk and Tape Storage Refresh,” analysis and results on pp. 83-88.

65

similar size projects and experience.91 In addition, the detailed cost/benefit analysis can be found in the 1

workpaper for this project.92 2

d) Conclusion 3

The Business Analytics Initiative will leverage SCE’s existing business 4

intelligence (BI) platform and tools to develop essential reporting and analytics capabilities to 5

accommodate the continued growth of data as well as the evolving information needs of SCE’s business. 6

G. Data Archiving Project 7

1. Data Archiving 8

Table IV-30 Data Archiving Project

Project Name Data Archiving Project

Portfolio IT

Application Age 2012

Replacement Date January 2015


a) Background 9

We continue to use our transactional systems to store historical data. This is 10

costlier than maintaining a separate data storage system because we presently maintain the historical 11

data in the same quality of storage that is used for current data, and we degrade performance when there 12

is too much data stored in the system. The transactional systems are not designed to support the large 13

data movements needed in data archiving processes. This project will develop and implement a data 14

archiving infrastructure, processes, archiving and retrieval strategies and capabilities for supporting the 15

ERP system and other applications used by the Operating Units (e.g., the energy trading systems used by 16

the Power Supply Operating Unit). The new data archiving infrastructure will provide the means to 17

91 See workpaper entitled “Forecast Expenditures for Business Analytics.”

92 See workpaper entitled “Investment Memo for Business Analytics.”

66

store and retrieve data for reporting purposes and, when appropriate, the means to delete the data. This 1

entails reviewing the company's records and data policies, and setting up the data archiving system in 2

such a way that these policies can be applied and governed (e.g., ensuring the system’s data retention 3

storage durations are aligned to the appropriate corporate-specified retention periods for such data). 4


The Data Archiving project will implement a cost effective data archiving 6

infrastructure to better manage growing system storage needs and comply with SCE’s records and data 7

policies, as well as with legal and regulatory requirements. Establishing an archiving project after a 8

large ERP system implementation is common because the ERP transactional systems are not specifically 9

designed to store and retrieve large amounts of historical data. The project will utilize a lower cost per 10

gigabyte storage infrastructure to save the large volumes of historical data. 11


The key business requirements of this project are to store archive data less 13

expensively and to improve system performance by moving data that is not needed for current 14

processing outside of the transactional system storage infrastructure. The transactional systems utilize 15

more expensive high-speed data storage infrastructures needed to keep up with the higher computing 16

speeds of the transactional applications. The data archiving infrastructure does not require the more 17

expensive high-speed data storage infrastructure because operational requirements only require specific 18

historical data to be available for use within a reasonable timeframe. Other historical data may be 19

deleted after use requirements are met according to applicable SCE policies, laws and regulations. 20


This project will provide a strategy and a technical solution for storing 22

data outside of the transactional systems. This project will evaluate different storage types and locations 23

and transfer methods. It is scheduled to begin in 2014 and continue through 2017. 24

SAP data archiving solutions provided by SAP or from approved SAP-25

vendors are the only methods supported by SAP to remove application data from the ERP system 26

databases in a consistent, secure and comprehensive manner. Data archiving validation is ensured 27

through the use of checks performed by the archiving program. Implementing the SAP data archiving 28

solution will allow users to select specific types of data stored on the ERP transactional databases, such 29

as accounting documents, material master records or HR master data, and remove the data from the 30

database, without having to know the specific database table design of the data. The selected archived 31

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data is stored in a file system and from there can be moved to other storage media. For security reasons, 1

the archived data is not deleted from the original database until the archive files have been read and 2

confirmed to be correctly copied and stored. 3

In the case of the Power Supply Operating Unit’s archival requirements, 4

IBM Optim Tools are currently the deployed and supported solutions for searchable data and 5

information repositories. The IBM Optim Tools are compatible with the Power Supply Operating Unit 6

applications to better ensure consistency through the use of checks performed by the archiving program. 7

Licenses for new versions of the IBM Option Tools will be procured and the new software will be 8

implemented as part of the Data Archiving project. 9

The primary benefits to be achieved by the Data Archiving project are a 10

less expensive data storage infrastructure and a reduction in transactional application server memory 11

usage. This will lead to lower costs by utilizing a less expensive near-line and off-line data storage 12

capability. As the volume of data grows, there is a tendency to use increasingly expensive hard drives to 13

store the data and add more server memory if an alternative solution is not deployed. The investment in 14

more expensive types of infrastructure can be shifted over time to a less expensive infrastructure if the 15

archiving solution is implemented. An additional benefit that will be achieved when the data archiving 16

solution is deployed would be that the frequency of regular data backup is reduced and the data can be 17

recovered at a faster rate. Also, finding and producing data in compliance with legal requirements is 18

simplified. Data access speed increases because searches can be limited to only the data requested 19

rather than searching across large volumes of transactional data. Performance is another aspect which is 20

greatly improved with an archiving solution as databases are optimized following data archival. 21



new capital projects and refreshes of existing applications as discussed in Chapter I, Section E. SCE 24

requires $3.70 million in funding for the Data Archiving project. The SAP solution is $2.5 million and 25

the IBM Optima Tools solution refresh for the Power Supply Operating Unit is $1.2 million. Forecasts 26

are derived from current vendor pricing.93 This estimate includes the cost of software, license and labor 27

costs for the purchase, integration, and implementation of the SAP and IBM solutions.94 28

93 See workpaper entitled “Forecast Expenditures for Data Archiving Project.”

94 See workpaper entitled “Investment Memo for Data Archiving Project.”

68

d) Conclusion 1

The Data Archiving project will develop and implement infrastructure, processes, 2

archiving and retrieval strategies and capabilities for the ERP and Power Supply data stores. 3

Implementing this capability will provide the means for the timely storing and of retrieving business 4

data for reporting purposes and, when appropriate, the means to delete the business data. 5

H. Enterprise Platform Core Refresh 6

Table IV-31 Enterprise Platform Core Refresh

Project Name Enterprise Platform Core Refresh

Portfolio IT

Application Age 2008

Replacement Date 2013


a) Background 7

The Enterprise Platform Core Refresh is for SAP. SAP, a Commercial-Off-The-8

Shelf (COTS) software system, was implemented in a series of three releases from 2008–2010, and the 9

software license contract with SAP requires periodic major version upgrades. 10

SAP is the enterprise-wide system used for the back-office financial management, 11

human resources and supply chain management, work management, enterprise asset management, 12

customer relationship management and Governance, Risk and Compliance.95 The scope of the SAP 13

system and associated processes are essential for the operations of all the organizations within the 14

company as described below. 15

95 Governance, Risk and Compliance typically encompasses activities such as corporate governance, enterprise risk

management (ERM) and corporate compliance with applicable laws and regulations.

69

(1) Finance 1

SAP Finance software functionality encompasses financial, regulatory, 2

and managerial accounting information and processes. The finance software is designed to record 3

financial transactions in a manner consistent with external reporting requirements. The related SAP 4

applications included in the proposed Enterprise Platform Core Refresh project scope are Financial 5

Accounting and Consolidations, Managerial Accounting, FERC Accounting, Fixed Asset Accounting, 6

Accounts Payable, Accounts Receivable, Non-Energy Billing, Budgeting, Treasury Cash Management, 7

and Treasury Long Term Planning. 8

(2) Human Capital Management 9

SAP Human Capital Management (HCM) software functionality 10

encompass human resource information and processes. SAP HCM provides integrated, enterprise-wide 11

functionality that provides real-time access to information for workforce decision-making for both 12

employees and managers throughout the employee life cycle. The related SAP applications included in 13

the proposed project scope are Employee Records, Organization Hierarchies (e.g., access to 14

organizational charts), Timekeeping and Payroll (used for weekly timesheet recording and biweekly 15

salary payments), Compensation (used for planning and providing merit raises and cash bonuses), 16

Employee Performance Management (used for semi-annual employee performance appraisals), 17

Training/Learning (used for elective and mandatory internal training), and Recruiting. 18

(3) Supply Chain Management 19

SAP Supply Chain Management software functionality encompass 20

procurement, material management and document/records management information and processes. The 21

applications included in the proposed project scope are Material Management; Supplier Relationship 22

Management, which provides the capability for enhanced purchasing activities including, but not limited 23

to requests for quotes, requests for proposals and requests for information from vendors; Supplier Portal, 24

which provides suppliers with a self-service portal function to receive purchase orders, enter time 25

worked and enter invoices; and Document/Records Management, which provides the capability to store, 26

categorize, search and access the procedures utilized by SCE’s Nuclear Operating Unit under the 27

regulation of the Nuclear Regulatory Commission as well as the scanning and storage of invoices for 28

processing accounts payable invoices. 29

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(4) Enterprise Asset Management 1

SAP Enterprise Asset Management (EAM) software functionality 2

encompasses work management and asset management information and processes. The related SAP 3

applications included in the proposed project scope include Plant Maintenance, Project Systems, C-4

Folders, and Project & Portfolio Management. This set of applications provide the capability to track 5

and maintain information related to the location, age, design characteristics, inspection, maintenance and 6

operating statistics, installation, removal, replacement and salvage of SCE utility plant assets. The Work 7

Management business processes involve the planning, scheduling and execution of work across the 8

Nuclear, Transmission and Distribution, Power Production, Operations Support, and IT Operating Units. 9

Work Management for the Nuclear Operating Unit also includes the Work Clearance Management and 10

Safety Tagging software functionality that are the basis for worker safety at the SONGS and their 11

Corrective Action Program (CAP) that allows for the identification, monitoring and completion of all 12

issues in the nuclear facilities. The purpose of the nuclear industry’s corrective action process is to 13

identify, document, evaluate, trend and rectify conditions adverse to safe plant operations and, where 14

necessary, to prevent the future recurrence of these adverse conditions. 15

(5) Analytics and Reporting 16

SAP Analytics and Reporting software functionality encompasses 17

reporting and portal information and processes. The applications included in the proposed project scope 18

include the Business Information Warehouse (BW) and the associated reporting tools (also known as 19

Business Intelligence or BI) and the Enterprise Portal application, which provides employees with a 20

single point of access to SAP and non-SAP information sources including SCE’s intranet. SAP BW 21

provides data warehousing functionality, a business intelligence platform, and a suite of BI tools. 22

Business information from SAP applications and external data sources can be integrated, transformed, 23

and consolidated in SAP BW. 24

(6) Customer Relationship Management (CRM) 25

SAP Customer Relationship Management (CRM) software functionality 26

encompasses the processes and workflow dealing directly with customers. The related SAP applications 27

included in the proposed project scope include Sales, Marketing and Service modules. SCE’s Customer 28

Service Operating Unit, the primary user of the software, has the responsibility of serving over 4.8 29

million customers and delivering over $3 billion demand side management programs (over a three-year 30

cycle). The software allows the end-to-end program enrollment through payment for the energy 31

71

efficiency, some demand management, and solar programs (both customer and vendor payments). It 1

also allows the ability for vendor partners, who deliver the programs on the company’s behalf, to use 2

CRM to receive, process and track work activity (through the Supplier Portal). CRM is also evolving to 3

be the primary data source for customer and business partner contacts for various purposes other than 4

billing. CRM is fully integrated with the other SAP modules, primarily Finance and HCM, as well as 5

with key legacy systems such as the Customer Service System and SCE.com. 6

(7) Governance, Risk and Compliance 7

SAP Governance, Risk and Compliance software functionality 8

encompasses compliance-related transactions, processes, and reporting. The related SAP applications 9

included in SAP Governance, Risk and Compliance software functionality are Access Management, 10

Process Controls, Compliance Management System, and Policy Management. This capability involves 11

functionality such as regulatory requirement intake, management and reporting of compliance catalog 12

items, evaluation of potential non-compliance events, responsive action plans, and management of 13

human driven controls. This functionality allows SCE to measure, monitor, manage and report on 14

compliance activities. 15

(8) NetWeaver and SAP NetWeaver Process Integration (SAP PI) 16

SAP NetWeaver is the SAP product used to integrate and connect all the 17

SAP applications and the Business Information Warehouse (BW) into one large system. Netweaver 18

enables all the SAP business applications to work together in a similar fashion to the way Microsofts 19

Windows operating system supports its PC applications such as Excel and Word. Additionally, 20

Netweaver has the capability to integrate other SCE non-SAP applications with the SAP applications to 21

allow sharing and exchanging of data. 22


During the period 2011-2013, one major SAP software product upgrade to a new 24

version (which we term a “major refresh”) will be completed. After this major refresh, the next major 25

refresh will be completed during the 2015-2016 period. SAP also provides “support packs” which 26

provide bug fixes and minor enhancements to the SAP products. The support pack upgrades will occur 27

in the years when a major refresh is not occurring. We plan to install the support pack upgrades in 2014, 28

early 2015 and 2017. The major refresh is forecast to require $14.687 million and the support pack 29

upgrades are forecast to require $2.568 million for a total of $17.255 million dollars in this period. Each 30

upgrade will involve system analysis, modifications to eight existing SCE SAP related custom software 31

72

packages, and more than 300 interfaces to other SCE systems, testing, and implementation. This 1

forecast is based on the internal IT application costing models for SAP development based on our 2

experience from the recent ERP program and the 2011 through 2012 upgrades. This allows us to 3

leverage our knowledge of the cost of similar SAP installations and upgrade work, along with the size 4

and configuration of the current system. 5


As with most COTS, SAP periodically updates its software by releasing 7

support packs and enhancement packs. SAP generally releases support packs and enhancement packs 8

every year. 9

Support packs deliver fixes for problems in the software reported by SAP 10

product customers and specialized computational changes (e.g., legal-related updates needed to align 11

with changes in the federal tax laws). SAP recommends that customers apply support packs upon 12

release to keep the installed software current. 13

Enhancement packs make changes to the software system’s functions such 14

as restructuring the system modules for technical efficiency (e.g. moving the employee succession 15

planning function from the recruiting module to the main human capital module), adding functions to 16

meet regulatory demands (e.g. adding the international accounting standards that will be required for 17

U.S. businesses in the future), and adding new business functions based on client demand. 18

The general software industry practice advises staying within two versions 19

(versions refer to the major upgrades, and the support packs are minor revisions to the versions) of the 20

currently-available product version in order to ensure support from the vendor, and to mitigate risks due 21

to security problems and failure as a result of vendor obsolescence and technology obsolescence.96 22


Upon completion of the final major release of the ERP Project in May 24

2010, SCE began implementing the SAP support and enhancement packs together every other year. 25

Although SAP releases new versions of its software every year, the plan is for SCE to implement a 26

support and enhancement pack upgrade every year for minor enhancements and software fixes, and a 27

refresh to a new version of the software every three years. This strategy ensures we are not installing the 28

newest versions, which may contain bugs (common with new software products) that will be fixed in 29

96 See A.10-11-015, SCE-05, Vol. 3, Section entitled “Software Asset Management”, pp. 9-12 for discussion about vendor

obsolescence and technology obsolescence, and support of software versions by the vendors.

73

later releases of these versions, while minimizing our risk from using technologically obsolete older 1

versions. This approach is a cost effective way of reducing labor installation costs while keeping the 2

SAP software current. All the SAP enhancement packs and maintenance packs are released annually 3

and cover all parts of the SAP systems and applications, but our proposed upgrades are targeting only 4

the software functionality described above in the background section. 5


SCE requires $17.26 million in funding (see forecast by year in Table IV-32 7

below) and the cost details for SCE labor, contract labor, and software licenses are in the project 8

workpaper.97 The forecast estimate is based on our previous similar work during 2008 through 2012.98 9

This estimate includes the cost of additional software and labor costs for the purchase, integration, and 10

implementation of the SAP upgrade solutions.99 11

Table IV-32 Capital Cost Forecast

(Nominal Dollars)

$5,400,000 $1,066,700 $4,610,100 $4,677,000 $1,501,300


2013 2014 2015 2016 2017

Table IV-33 Recorded Costs

(Nominal Dollars)

2008 2009 2010 2011 2012

$0 $0 $0 $1,183,000 $8,029,000

Capital Cost Forecast

d) Conclusion 12

Similar to most COTS products, SAP generally releases support packs (to fix 13

problems and deliver legal-related updates) and enhancement packs (to add new functionality) every 14

97 See workpaper entitled “Forecast Expenditures for Enterprise Platform Core Refresh.”

98 See SCE-05, Vol. 3, Section entitled “Software Asset Management”, pp. 61-64.

99 See workpaper entitled “Investment Memo for Enterprise Platform Core Refresh.”

74

year. SAP recommends that customers apply support packs upon release to keep the installed software 1

current. In order to minimize the risks of running obsolete software for critical processes, SCE intends 2

to implement SAP support pack and enhancement pack upgrades every year and a major refresh of the 3

software to a new version every three years. In addition, our software license agreement contract with 4

SAP requires SCE to stay within the product version currently supported by SAP in order to receive 5

SAP support for bug and security software repairs.100 This ensures continued support from the vendor 6

(SAP), compliance with changes in federal and state laws (e.g., tax changes), and minimizes the impact 7

of system bugs, while mitigating the cost of keeping the SAP software current. 8

100 See workpaper entitled “Justifying Business Application Software Maintenance Fees,” Gartner Research, June 21, 2004.

75

V. 1

PROJECTS LESS THAN $1 MILLION 2

A. List of projects 3

Between 2013-2017, we have selected specific capitalized software projects. Our review of the 4

entire application portfolio prioritization ensures that these are the projects most required by SCE. 5

These projects are summarized in the table below, along with their forecast capital costs. 6

Table V-34 Estimated Software Project Less Than $1Million for 2013-2017

(Nominal $000)

CIT OU Project Description 2013 2014 2015 2016 2017Total

Forecast

CIT-00-OP-OM-000002 IT Command Ctr Automation 100.0$ -$ -$ -$ -$ 100.0$ CIT-00-DM-DM-000040 IT Geographical Information Application -$ 924.0$ -$ -$ -$ 924.0$ CIT-00-OP-NS-000322 PS PPD - Big Creek 800.0$ -$ -$ -$ -$ 800.0$ CIT-00-SD-PM-000132 PS Energy Planing Platform Phase 3 (EPP3) 720.0$ -$ -$ -$ -$ 720.0$ CIT-00-SD-PM-000133 PS Energy Forecasting Platform (EFP) 900.0$ -$ -$ -$ -$ 900.0$

Totals 2,520.0$ 924.0$ -$ -$ -$ 3,444.0$ B. Brief justification 7

We do not provide written justifications for capitalized software projects forecast to be less than 8

one million dollars. The table above lists software projects which cost less than one million dollars in 9

capital funding and are for either IT software tools or capitalized software projects that started before 10

2013 and are now completing in 2013.11

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VI. 1

ORG UNIT SOFTWARE PROJECTS 2

A. Proposed Capitalized Software Projects 3

Between 2013-2017, we have selected 39 specific capitalized software projects. Our review of 4

the entire application portfolio prioritization ensures that these are the projects most required by SCE. 5

These projects are summarized in the table below, along with their forecast capital costs. We then 6

provide a more detailed description of each proposed capitalized software project, including a 7

background description of the application, the business requirement, the recorded and forecast 8

expenditures, and our conclusion. 9

Table VI-35 Estimated Capitalized Software Project Expenditures for 2013-2017

(Nominal $000)

CIT OU Project Description 2013 2014 2015 2016 2017Total

Forecast

CIT-00-SD-PM-000136 CC Master Access Project (MAP) 10,550.0 1,806.0 - - - 12,356.0 CIT-00-SD-PM-000141 CC FASB Projects (Multiple) - 5,040.0 - - - 5,040.0 CIT-00-SD-PM-000142 CC Tax Department Repairs Project 1,500.0 840.0 - - - 2,340.0 CIT-00-SD-PM-000139 CC C-CURE 9000 Upgrade 5,034.2 - - - - 5,034.2 CIT-00-DM-DM-000039 CC IWMS/CAD/CAFM system upgrade - 3,360.0 - - - 3,360.0 CIT-00-SD-PM-000064 CC Enterprise Compliance Management System 7,000.0 - - - - 7,000.0 CIT-00-SD-PM-000144 CC Electronic Document Management/Records Management 2,100.0 4,704.0 11,400.0 8,600.0 5,800.0 32,604.0 CIT-00-SD-PM-000110 CS Dynamic Pricing 10,446.5 600.0 - - - 11,046.5 CIT-00-DM-DM-000022 CS SCE.com Strategic Upgrade 1,624.1 - - - - 1,624.1 CIT-00-DM-DM-000054 CS SCE.com Future Upgrade - - - - 12,600.0 12,600.0 CIT-00-DM-DM-000024 CS SCE.com R2 29,010.0 13,800.0 - - - 42,810.0 CIT-00-SD-PM-000163 CS ESC Stabilization (Order Optim, SCMAS, DW3, CGM, SW Enhanc, 4,420.0 - - - - 4,420.0 CIT-00-DM-DM-000025 CS MSO Integrated Work Management 3,000.0 3,700.0 8,398.8 4,917.5 4,650.0 24,666.3 CIT-00-DM-DM-000032 CS SCE.com / CRM Integration - - - 23,000.0 15,700.0 38,700.0 CIT-00-SD-PM-000106 CS Advanced Speech Recognition / Text to Speech Technologies - 5,040.0 - - - 5,040.0 CIT-00-SD-PM-000107 CS Customer Alerts and Notifications - 3,400.0 6,800.0 - - 10,200.0 CIT-00-SD-PM-000171 CS Outage Program R2: Long-Term Outage Comm - - 5,500.0 4,100.0 - 9,600.0 CIT-00-DM-DM-000033 CS CSBU Customer Data Warehouse - - 10,000.0 18,000.0 - 28,000.0 CIT-00-SD-PM-000174 CS Prepay - 1,600.0 - - - 1,600.0 CIT-00-SD-PM-000170 CS GRC Phase II Non-Dynamic Pricing Rates - - 6,500.0 - - 6,500.0 CIT-00-SD-PM-000105 CS Enhanced Meter and Usage Capability-CSBU - 6,700.0 - 9,900.0 - 16,600.0 CIT-00-SD-PM-000172 CS SmartConnect Monitor&Analysis (SCMAS) - - 5,100.0 - - 5,100.0 CIT-00-SD-PM-000169 CS Hiperwall Hardware Refresh - - 1,900.0 - - 1,900.0 CIT-00-SD-PM-000100 CS PEV Self-Service Automation - - - 2,500.0 - 2,500.0 CIT-00-DM-DM-000017 CS Customer Service System Enhancements - - - 5,000.0 7,000.0 12,000.0 CIT-00-OP-NS-000383 CS Cell Relays - IT Portion (Hardware of $1 - - - - 17,300.0 17,300.0 CIT-00-SD-PM-000209 CS HAN - Future Upgrades/Standards - - - - 6,000.0 6,000.0 CIT-00-SD-PM-000023 PS Data Management Platform Upgrade Phase 3 1,270.0 - - - - 1,270.0 CIT-00-SD-PM-000164 PS CAISO Market Enhancements (2013) 5,300.0 - - - - 5,300.0 CIT-00-SD-PM-000069 PS CAISO Market Enhancements (2014-2017) - 6,790.0 7,000.0 7,000.0 6,000.0 26,790.0 CIT-00-DM-DM-000045 PS Energy Procurement Information Center Replacement - - - 2,800.0 3,000.0 5,800.0 CIT-00-SD-PM-000112 PS Renewable Contract Management System 5,000.0 15,520.0 - - - 20,520.0 CIT-00-SD-PM-000176 PS Energy Trading and Risk Management (ETRM) System Replacemen - - - 6,000.0 6,000.0 12,000.0 CIT-00-SD-PM-000181 PS Common Data Store (CDS) and Power Supply Data and Reporting ( - - - 3,600.0 3,600.0 7,200.0 CIT-00-DM-DM-000028 PS Usage Measurement System - - 1,500.0 - - 1,500.0 CIT-00-SD-PM-000149 PS Generation Management System 1,500.0 194.0 - - - 1,694.0 CIT-00-SD-PM-000182 PS Aggregated Demand Response - - 4,150.0 1,400.0 250.0 5,800.0 CIT-00-SD-PM-000178 PS Market Systems Replacement - - - 3,000.0 2,800.0 5,800.0 CIT-00-SD-PM-000183 PS Fundamental Modeling Platform - - 750.0 750.0 - 1,500.0

Subtotals for CC, CS and PS in SCE-05, Vol. 2, Part 1 87,754.8 73,094.0 68,998.8 100,567.5 90,700.0 421,115.1 Note: SCE has included several Customer Service capital software projects in the 2015 GRC revenue requirement that have been requested in other proceedings or were approved in earlier non-GRC Commission decisions. These projects are not included in the table above. Please refer to Workpapers SCE-05, Vol 02, Book D. pp 179A-179E.

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B. Safety, Security & Compliance 1

1. Master Access Project 2

a) Background 3

The Safety Security and Compliance Operating Unit is requesting a total of $12.4 4

million in capital expenditures for a capitalized software project to enhance compliance tasks for the 5

current NERC CIP-004 Version 3 (CIP-004-3) standard and meet future compliance requirements 6

required under NERC CIP-004 Version 5 (CIP-004-5) standard by October 1, 2015.101 Standard CIP-7

004 pertains to the management of electronic and physical access and mandatory, time bound 8

qualifications such as training and background checks.102 9

The Master Access Project (MAP) is intended to enable SCE’s compliance with 10

the upcoming CIP-004-5 pursuant to the established policy direction determined by SCE in alignment 11

with NERC reliability standards. MAP will implement: (1) an enterprise-wide master repository of 12

personnel data with access, specific access rights, training, and background check qualifications; and (2) 13

enforce common controls to enable SCE to meet mandatory compliance requirements of NERC standard 14

CIP-004. The master repository will include the storage of access authorizations, records of access 15

provisioning, de-provisioning, scheduled reviews, completion dates of qualifications such as training 16

and background checks, as well as other information required to prove compliance. Common controls 17

such as workflows to enable system administrators to complete access revocations in real-time within 18

mandated timeframes,103 track the status of qualifications, and apply mandated actions104 on 19

qualifications prior to the expiration of their validity will be implemented as a part of MAP. 20

101 See SCE-09, Chapter VIII, Corporate NERC Critical Infrastructure Protection (CIP) testimony.

102 Pursuant to NERC standard CIP-004-3, all person who have been granted access to SCE’s facilities and systems that have been determined to be in scope for the NERC CIP standards must meet certain prerequisites prior to being granted such access and must maintain these qualifications on an ongoing basis. Training courses must be completed in advance of being granted access and must be completed once a calendar year in order to maintain a valid qualification to retain access. In addition, a 7 year back ground check must be passed by all individuals prior to being granted such access, and the background check must be conducted every 7 years hence.

103 Pursuant to NERC standard CIP-004-3, access has to be removed within 24 hours when an individual with access to NERC facilities and systems is terminated for cause and within 7 calendar days when SCE determines that such access is no longer needed for reason other than a termination. Pursuant to NERC standard CIP-004-5, access revocation has to be completed within 24 hours or the end of the next calendar day under certain conditions.

104 Training has to be completed within 15 calendar months of prior completion and the background check has to be refreshed every 7 years. The MAP project will send reminders to affected personnel to complete these actions or will automatically take alternative action such as removal of access.

78

The project is divided in phases whereby the project planning, process blue print 1

work, and system design will be completed in 2013. Development, testing, and training will be 2

completed in 2014. The Master Access Project is scheduled to be implemented for a pilot group by June 3

2014. 4


SCE’s NERC-related access management compliance has thus far been performed 6

by means of numerous stand-alone systems and manual processes. Further, the number of facilities in 7

scope for SCE’s Transmission and Distribution Operating Unit is expected to increase from 8

approximately 17 in 2013 to approximately 120 in 2015. While all these new facilities are not manned 9

by SCE personnel 24 hours a day, the number of personnel impacted by this substantial increase in 10

number of facilities is expected to grow. The management of multiple qualifications as well as access 11

revocation rules mandated in CIP-004-5 will render current methods to maintain compliance 12

unsustainable. SCE utilizes SAP as its Governance Risk and Compliance management system. The 13

MAP project is designed to bring these compliance tasks into the SAP Governance, Risk, and 14

Compliance management system. The systems and processes currently in use will be challenged 15

primarily due to: 16

Stricter regulations and near real-time capability demands of NERC: Access 17

revocations have to be performed immediately on multiple systems when 18

personnel with access to certain NERC impacted facilities or systems have 19

been separated from the company. 20

Inefficient current system design: Approximately 30 different data sources, 21

each requiring access to authorized personnel, results in incompatible 22

processes and manual tasks, which cause delays and limit our ability to scale. 23

The new changes with CIP-004-5 will further affect people, processes, and 24

technology, as described below. 25

People: SCE compliance personnel will have to apply the new controls 26

mandated in CIP-004-5. Support personnel across SCE responsible to 27

maintain training and background check records will have qualifications to 28

ensure compliance. System administrators responsible for the provisioning 29

and de-provisioning of NERC access will have to include workflows from 30

MAP into their tasks. Managers of personnel with NERC access will use this 31

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system to actively manage and monitor tasks that will enable SCE to maintain 1

compliance. 2

Processes: Changes to compliance processes will result in new or modified 3

controls that will affect systems across SCE within the scope of the NERC 4

CIP standards. Areas impacted include the time it takes to revoke access to 5

NERC protected systems for terminated personnel, to automate the 6

provisioning of access for new and existing employees to NERC protected 7

systems, and to consolidate all NERC CIP personnel evidence (training and 8

access) into a single data repository. Moreover, having the consolidation of 9

access management will provide the capability to more frequently monitor 10

near real-time access to NERC CIP assets. In addition to MAP, SCE will 11

develop new or modified internal processes to leverage the efficiencies of the 12

new capabilities offered by MAP and comply with NERC CIP standards. 13

Technology: Changes to information systems include: (1) the consolidation 14

of access management functions into a single system; (2) automation of 15

physical and electronic access by provisioning/de-provisioning access to 16

NERC CIP source systems; (3) the ability to allow managers to initiate 17

revocation of access when needed; (4) near real-time integration between 18

Human Capital Management105 and access management that will provide the 19

latest personnel training information to access management; and (5) 20

integration with the Enterprise Compliance Management System (ECMS) for 21

controls monitoring and evidence collection. 22


Funding needs for the MAP are expected to be $12.4 million.106 This forecast is 24

based on the internal IT application costing model and the details are available in the workpaper cited 25

above. The Master Access Project is underway in 2013 and is expected to be implemented for a pilot 26

group in June 2014 with the general roll out by January 2015. 27

105 Human Capital Management is an SAP module that tracks training, qualifications, and other personnel data.

106 See workpaper entitled “Forecast Expenditures Master Access Project.”

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d) Conclusion 1

Implementing the MAP involves changes to the current system design and 2

business processes at SCE, as described above. This will allow SCE to automate processes, build a 3

centralized data repository, consolidate access management, and allow for real time automated 4

provisioning/de-provisioning to NERC CIP source systems. This will assure that SCE is in compliance 5

with CIP-004-5 in accordance with NERC standards. 6

C. Financial Services 7

1. Financial Accounting Standards Board Lease Project 8

a) Background 9

Financial Services is requesting $5.04 million in capital expenditures and $1.5 10

million in incremental O&M expenditures for a 2015 project associated with implementing major 11

revisions to United States Generally Accepted Accounting Principles (commonly referred to as U.S. 12

GAAP) relating to leases. 13

U.S. GAAP are accounting rules established by the Financial Accounting 14

Standards Board (FASB) for the preparation and reporting of financial statements. The Securities and 15

Exchange Commission (SEC) requires all SEC registrants, including SCE, to prepare financial 16

statements using U.S. GAAP. Accordingly, SCE must comply with major accounting modifications to 17

key U.S. GAAP standards, including revenue recognition, financial instruments, and leases. The new 18

lease standard (expected to be released in 2014) will require significant, company-wide process and 19

system changes in order to address the FASB’s extensive overhaul of the current accounting rules. 20

These new rules, which represent a major shift in accounting practices, will require the implementation 21

of new processes and systems, the conversion of all outstanding leases to a different accounting model, 22

and the establishment of opening balances for contracts. Consequently, a new capital software project is 23

required for compliance with the FASB lease standards. 24

Under the new rules, the majority of leases that are currently measured as expense 25

(and/or revenue) will now require capitalization as assets and offsetting liabilities on the balance sheet. 26

In addition, the maintenance of the new accounting model will require significant analytical activities in 27

order to recognize and measure lease transactions properly. Moreover, the new model will require 28

extensive tracking and ongoing measuring activities (to address required re-measurement 29

considerations) that do not currently exist in company procedures. Accordingly, due to the large number 30

81

of company leases (over 4,000), we expect to implement new processes and software to accomplish 1

these new requirements. 2

The FASB is expected to issue its final lease rules in late 2014, with the new 3

accounting requirements effective for the year 2017. It is expected that the new rules will include a 4

retrospective obligation to report lease transactions under the new accounting model for 2015 and 2016 5

as well. Therefore, SCE will be required to implement the required new processes and systems in 2015 6

in order to minimize the period for which data must be recalculated to the beginning of 2015. 7


SCE uses SAP as its main financial system. The new lease accounting software 9

could be either configured within a SAP module or as a stand-alone software application that will need 10

to be configured separately and interfaced with SAP. As discussed above, the extensive FASB changes 11

will trigger numerous information system changes, which will affect the following people, processes, 12

and technology: 13

People: Operating and accounting personnel will need to understand and apply 14

the new lease accounting rules to be implemented. In addition, training for system and process changes 15

will affect accounting, business, and technology personnel throughout SCE. 16

Processes: Changes to processes will affect information systems. Areas 17

impacted include the financial monthly closing cycle, chart of accounts, and financial statement 18

preparation. In addition, the required disclosures and the underlying data needed for the new accounting 19

rules will result in the growth of accounting data, as SCE will be required to calculate the present value 20

of a leased asset and a related lease liability, and then track the amortization over the life of the leased 21

asset. In contrast, the current practice is (effectively) to record monthly payments. SCE will need to 22

report lease transactions under current GAAP in 2015 and 2016, and must also capture lease information 23

under the new accounting model. Therefore, SCE will need to develop new or modified processes to 24

maintain parallel treatments for the same set of events and transactions. All of these process changes 25

will drive changes to SAP and possibly other systems in order to maintain adequate process and systems 26

controls. 27

Technology: Changes to information systems will include analysis, 28

configuration, testing, and implementation of the new accounting rules. In addition, changes to 29

disclosures, charts of accounts, and financial statement presentations will require changes to input 30

screens, data structures, and application interfaces. The retrospective transition requirements associated 31

82

with the new lease requirements may require the re-computation of voluminous amounts of historical 1

data. 2


A system-related estimate cannot be completed with precision due to that fact that 4

the new FASB lease accounting rules will not be released until 2014. To estimate the cost of upgrading 5

SCE’s systems to comply with the new rules, SCE contacted two software vendors (including the 6

manufacturer of SCE’s current system). These vendors are familiar with the emerging revised 7

accounting rules, the potential increase in transactional volume associated with the rules, and the scope, 8

scale, and integrated nature of SCE’s ERP system environment. Based on the vendors’ knowledge of 9

the potential requirements and SCE’s specific circumstances, they estimated system-related costs (e.g., 10

system planning & analysis, software purchase, design, construction, and configuration) to be 11

approximately $3.8 million. In addition, we expect that extensive testing will be required, amounting to 12

approximately $1.24 million in capitalizable internal and external costs directly related to the setup and 13

operation of the system (e.g., system project management and testing), for a total of $5.04 million. The 14

project is expected to last one year and to be completed in 2015.107 15

In addition to the capital costs above, SCE has estimated $1.5 million in 16

incremental, non-capitalizable O&M associated with assessing the accounting changes, communicating 17

the changes, performing process redesign, and implementing and monitoring the new processes.108 That 18

figure is based on the number of lease contracts, the approximate amount of employee time needed to 19

review and assess the contracts’ financial impact, and the necessary training. The new accounting 20

model is complex and requires a sophisticated level of judgment in order to properly recognize, 21

measure, and report lease transactions. The company’s lease contracts and transactions are voluminous 22

and total hundreds of millions of dollars. A lack of qualified and highly trained personnel to maintain 23

the new lease accounting activities could compromise the quality of SCE’s financial statements. 24

Therefore, the adequacy of processes, communication, and training associated with this implementation 25

project are critical to its success. 26

107 See Revenue Procedure (RP) No. 2011-43, available at http://www.irs.gov/irb/2011-37_IRB/ar11.html (Last visited on

July 2, 2013).

108 See workpaper entitled “Forecast O&M Project Costs for FASB Project.”

83

d) Conclusion 1

The implementation of new FASB-mandated accounting rule changes will drive 2

extensive changes to SCE’s accounting practices and policies. The change to lease accounting, in 3

particular, will affect multiple organizations, change many existing processes and information systems, 4

and require that staff clearly understand the new rules. Early and thorough planning, and the 5

implementation of this software upgrade, will likely reduce the number of manual processes that can 6

drive higher ongoing maintenance associated with accounting activities and subsequent adjustment and 7

true-up transactions. 8

2. Tax Department Repairs Project 9

a) Background 10

Financial Services is requesting a total of $2.34 million in capital expenditures for 11

a software project to comply with Internal Revenue Service (IRS) Revenue Procedure No. 2011-43 (RP 12

2011-43).109 Issued on August 19, 2011, the procedure provides a safe harbor method of accounting by 13

which taxpayers may determine whether expenditures to maintain, replace, or improve transmission and 14

distribution linear property could be immediately expensed as a repair for tax purposes. The tax benefits 15

associated with this deduction reduce SCE’s cost-of-service tax expense.110 16

RP 2011-43 requires a specific measurement of each unit of property (UOP) 17

within each electrical circuit. It also requires utilities to identify specific circuits where replacements or 18

improvements are performed. Like many other utilities, SCE’s current software systems do not contain 19

sufficient detail to determine the size of each specific circuit or capture circuit information for all work 20

orders.111 Transition rules, which allow taxpayers to measure each UOP based on an average circuit 21

within a county, may be used only until December 31, 2013. RP 2011-43 currently requires all 22

taxpayers to have systems in place to provide circuit information for work orders completed on or after 23

January 1, 2014. 24

For SCE to comply with RP 2011-43 and to maintain the flow-through tax 25

benefits for ratepayers, SCE must: (1) enhance current work-management systems to capture circuit 26

information about repairs for eligible work orders; (2) determine the UOP quantities by circuit on an 27

109 See Revenue Procedure (RP) No. 2011-43, available at http://www.irs.gov/irb/2011-37_IRB/ar11.html (Last visited on

July 2, 2013).

110 See SCE-10, Vol. 2, Pt. 4 for the estimated benefit for the forecast years 2015 to 2017.

111 A work order is a document created to account for labor and material costs for each job or purchase.

84

annual basis; and (3) acquire software capability to process repairs deductions and provide supporting 1

documentation for external audits. 2


SCE uses various work-management software programs (including Design 4

Manager (DM), Consolidated Mobile System (CMS), and the SAP Project System module) to design, 5

plan, schedule, and maintain its circuit replacement and maintenance work. Maintenance and repair 6

work is tracked by work order type and maintenance activity type. Additionally, SCE uses SAP Finance 7

and Controlling software modules and PowerPlant software to record and calculate labor, material, and 8

other costs for plant assets. SCE’s work-management software and plant accounting systems are 9

integrated, allowing us to identify maintenance and replacement costs by work order. 10

RP 2011-43 provides that if 10 percent or less of the UOP of a linear property is 11

replaced, the replacement cost could potentially be deductible as repairs. The 10 percent must be 12

measured on a circuit-by-circuit basis, which requires the specification of the circuit on which asset 13

addition or replacement is being performed. The identification of the specific circuit where work is to 14

be performed must be captured at the time when the work order is created in SCE’s work-management 15

software programs (DM, CMS, and SAP). At present, that software cannot capture the required 16

information. In order to ensure the 10 percent replacement test can be conducted, SCE must enhance its 17

work-management software to require circuit assignment during work-order creation, and also to train 18

engineers, field planners, crews, and field accounting personnel to populate circuit information when a 19

work order is created. Data conversion is also necessary to populate circuit information for 20

approximately 60,000 work orders created before the software enhancement and personnel training. 21

In addition to identifying circuits in work orders, the proper performance of the 10 22

percent replacement test requires SCE calculate UOP quantities by circuit on an annual basis. This 23

requires the collection of UOP quantities by circuit, using equipment and circuit data from our 24

geographic information system. SCE must either procure or develop software capability to test each 25

work order against the UOP quantity by circuit to determine if the work order meets the 10 percent 26

replacement test criteria. This software must also be able to summarize the total costs of eligible work 27

orders, produce supporting reports for tax filing, and store cost details and other work order 28

characteristics to provide documentation for external auditors. SCE’s current software programs have 29

none of these capabilities. 30

85

RP 2011-43 is a new requirement specific to utilities with linear assets, which 1

unfortunately limits the available software options. SCE evaluated whether to process the calculations 2

manually or instead procure software (such as the software company PowerPlant’s Tax Repairs module) 3

to perform them. The manual-processing option was ruled out because it is time-consuming and prone 4

to errors. PowerPlant recently released a new Tax Repairs module for compliance with RP-2011-43. 5

Because SCE already uses PowerPlant’s software modules for fixed-asset accounting and tax 6

depreciation, implementing PowerPlant’s Tax Repairs module will provide a seamless integration 7

between cost data for accounting and tax processing. SCE will need to upgrade the current PowerPlant 8

system to enable the concurrent processing of the fixed-asset accounting, tax depreciation, and Tax 9

Repairs modules. 10


SCE’s Tax Department Repairs Project is expected to cost $2.34 million. This 12

forecast is based on the internal IT application costing model.112 13

The Tax Department Repairs Project is scheduled to commence in 2013 and be 14

completed by 2014. 15

d) Conclusion 16

Implementing the requirements of RP 2011-43 will involve changes to SCE’s 17

business procedures, work management and accounting software, and software capability. These 18

changes are necessary for SCE to continue to provide ratepayers with the flow-through tax benefit 19

associated with the tax-repair deduction. 20

D. Corporate Center (Formerly Operations Support) 21

1. CCURE Upgrade 22

a) Background 23

Many SCE facilities, including all major buildings, control centers, and 24

generation facilities, are protected by a centrally-controlled alarm and event management system. This 25

physical access control system (PACS) logs all access and attempted access to SCE facilities in 26

connection with the Corporate Security ID badging system. The PACS maintains a real-time database 27

of all persons authorized to enter specific SCE facilities and manages access to facilities based on the 28

status of the badge holder, i.e., employee, vendor, contingent worker, or contractor. 29

112 See workpaper entitled “Forecast Expenditures for Tax Department Repairs Project.”

86

The existing PACS application was installed in 1998. This legacy system is now 1

at or above its full reliable capacity, and is unable to accommodate the significant addition of facilities 2

or secured areas within facilities. The currently-installed version also has technical limitations that 3

prevent integration with other security and compliance systems. These limitations include reliance on a 4

non-standard database format, non-scalable architecture, 32-bit operating environment, and performance 5

issues. 6

The PACS is already over-capacity, as it was designed to integrate up to 150 7

alarm panels (as recommended by the original equipment manufacturer) to maintain a high reliability of 8

operation. There are currently more than 340 alarm panels connected to the PACS and it has become 9

significantly unstable, such that it enters a failed state every few months, requiring a system reboot. 10

Federal critical infrastructure protection standards (NERC CIP-006) require SCE to implement 11

additional security access controls at locations governed by the NERC CIP Standards.113 Additionally, 12

in keeping with good security practices, SCE installs incremental security access and tracking controls 13

in some additional locations each year. During 2014-2017, Corporate Security plans to add 14

approximately 200 new alarm panels for NERC-regulated and non-NERC locations, including 15

substations, service centers, payment centers, and other buildings. The projected growth of SCE alarm 16

system and access control needs will further degrade the stability and reliability of the current PACS by 17

adding demand to an already resource-constrained computing environment. 18

The limitations of the current PACS create a growing risk to real-time security 19

monitoring of facilities and NERC assets. The lack of expansion capacity in the existing system 20

effectively precludes its use for monitoring and access controls for additional facilities, including 21

controls required by NERC CIP Standards. Therefore, SCE is upgrading the PACS to a more current, 22

higher capacity, and scalable version. 23


The PACS upgrade project is necessary to address the above-described limitations 25

of the current version and to meet the projected growth of SCE’s physical security system needs. The 26

new PACS must meet the following key requirements: 27

Scalable to meet expected growth in the number of facilities requiring security 28

services 29

113 See SCE-07, Vol. 04, for a detailed discussion of the NERC CIP access control requirements.

87

Integrate security management, access control, alarm monitoring, badging, 1

digital imaging and biometric recording 2

Manage intrusion alarms 3

Provide extensive reporting capabilities 4

Provide access control and monitoring for all SCE facilities, including custom 5

clearance and remote administration. 6


The PACS upgrade project began in late 2012 and we spent $91,000 on it in 2012. 8

The 2013 project costs for the PACS upgrade project are forecast at $5.034 million.114 The project is 9

expected to complete in 2013 and the system will run in parallel with the existing system until a year 10

later, in 2014, when the older system will be decommissioned. 11

The objectives and scope for the upgrade project include: 12

Create a scalable system that meets 99.9 percent reliability and 15 minutes 13

response time required by NERC CIP v5 (NERC CIP-006 Standard) 14

Migrate the 110+ sites from the existing PACS to the new PACS 15

Deploy independent Satellite Application Servers (SAS) to segregate NERC 16

and Non-NERC alarm groups 17

Implement a new architectural solution to allow for unlimited expansion of 18

the alarm system 19

Deploy migration tool and real-time report engine. 20

Additionally, the upgraded PACS solution will integrate with the Edison Security 21

Operation Center (ESOC) Physical Security Information Management System (PSIM) tool and 22

Enterprise Visitor Management system. As PACS will provide all alarm events and access management 23

for the ESOC while the incident and alarm events will be managed through the PSIM, the PACS 24

upgrade is critical to the success of the ESOC project. 25

SCE’s ability to comply with NERC CIP v5 Standards, in particular NERC CIP-26

006, is also dependent on the PACS upgrade. The current system cannot handle the projected increase 27

in locations requiring heightened NERC CIP-006 access controls. The upgraded PACS, which will be 28

configured to monitor and protect NERC sites, will allow SCE to comply with these Standards. 29

114 See workpaper entitled “PACS Cost Breakdown.”

88

The PACS upgrade solution will be designed to minimize the potential for 1

physical and electronic tampering of the physical security application. Access to the application 2

environment will be logged electronically at all times with a 24/7 audit trail. Data from all alarm 3

facilities, including NERC specified areas, door groups, event groups, intrusion zones, and card readers, 4

will be used for real-time reporting. The real-time reporting will provide improved situational 5

awareness to the Corporate Security and Cybersecurity teams, resulting in improved evaluation of and 6

response to physical threats. 7

d) Alternatives Considered 8

Two other options were considered in connection with the PACS upgrade project: 9

(1) complete replacement of PACS, and (2) creating a secondary, independent PACS environment. The 10

first option (complete replacement) would require SCE to replace all alarm panels at current alarmed 11

facilities. This is based on the design and deployment of the current alarm system solution, where all the 12

current alarm system panels are unique to the PACS software. This option was rejected because it 13

would not be cost-effective to replace all alarm system components compared to upgrading the existing 14

application. 15

The second option (building a second independent environment) would create 16

operational challenges in maintaining two access control systems. Implementing this option would 17

require the IT and Corporate Security departments to increase staff to operate multiple application 18

environments. Additionally, security personnel would need to use two different computing 19

environments to monitor security alarms, increasing operational risks and challenges. This solution was 20

not considered viable because of the operating challenges in coordination, communication, and response 21

management. As a result, SCE plans to upgrade the existing PACS to the current version to address 22

reliability and scalability issues. 23

e) Conclusion 24

SCE is upgrading the current PACS environment to the new version of the 25

software to achieve scalability and efficiency needed by Corporate Security to manage alarm events, 26

access controls, and security incidents. The new PACS system will be integrated into the ESOC to 27

improve real-time monitoring with a more stable and scalable PACS environment, as well as to meet 28

NERC CIP-006 standards for monitoring physical access to NERC-regulated sites. 29

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2. Integrated Work Management System/CAD/CAFM System Upgrade 1

a) Background 2

The Corporate Real Estate Department (CRE) currently manages an existing SCE 3

portfolio of more than 226 non-electric facilities containing approximately 6.5 million square feet of 4

space at 79 locations.115 Of the approximately 17,900 SCE employees and contingent workers 5

employed at year-end 2012, approximately 14,000 are seated employees and contingent workers 6

occupying traditional office space within SCE’s facilities. “Churn” is a numerical reflection of the 7

movement of employees within and between SCE office facilities in a given year. CRE estimates that 8

SCE experiences an annual personnel “churn” of 20 to 30 percent of the SCE employee population or 9

approximately 3,000 to 5,000 SCE employees who relocate to a different office each year. In addition, 10

the average age of SCE’s non-electric facility portfolio is 36 years and those facilities require constant 11

maintenance and repair to provide a safe and reliable work environment for SCE’s workforce. The need 12

to address and anticipate facility requirements is a continuous challenge due to regulatory compliance 13

commitments (e.g., permitting and building code requirements), organizational movements, and 14

demands for flexible workspace. To optimize and efficiently manage space utilization, CRE urgently 15

requires a facility technology system to integrate current facility data with alternative facility strategies 16

and enhance SCE’s ability to meet facility planning and management needs. 17


CRE currently manages SCE’s extensive non-electric portfolio using a variety of 19

computing tools and manually integrating those tools with financial, human resource, and operational 20

data contained within SCE’s SAP Enterprise Resource Program. Our current process for managing and 21

tracking facility space and personnel moves utilizes multiple types of software including a Computer 22

Aided Facility Management (CAFM) system (which contains only partial information on non-electric 23

SCE facilities), electronic Computer Aided Design (CAD) facility drawings, Access databases and Excel 24

spreadsheets. With respect to regulatory compliance matters, CRE manually monitors and tracks facility 25

permitting and building code requirements. These are highly labor-intensive and inefficient processes. 26

In order to manage SCE’s facility portfolio in a more productive and effective manner, CRE needs an 27

integrated work management system (IWMS) employing and consolidating accurate and current data 28

115 “Non-electric facilities” refers to all facilities that are not directly used in generating, transmitting, or distributing

electricity. Examples of non-electric facilities include business offices, warehouses, customer call centers, customer service centers, and computing centers.

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and CAD drawings about SCE’s non-electric facility portfolio and equipment, workforce and 1

operational needs. IWMS would execute the following facility related functions: (1) Strategic Master 2

Planning; (2) Work Management; (3) Facility Asset Management; (4) Facility Condition Indexing; and 3

(5) Sustainability Review. IWMS will result in bi-directional integration with SAP Human Capital 4

Management (HCM) module to the existing CAFM system. 5

(1) Strategic Master Planning 6

In order to accurately align space optimization with SCE’s operating unit 7

needs, CRE requires IWMS to support Strategic Master Planning by providing detailed space inventory 8

information and related analysis functions. IWMS will allow CRE to more proactively manage growth 9

and consolidation by gaining the ability to: (a) develop program requirements based on department 10

inventories and space requirements, (b) summarize costs associated with changes in occupant headcount, 11

(c) develop a space requirements program for merged departments, (d) generate reports that graphically 12

document space usage trends by department, (e) reduce “churn” rate through proactive space planning, 13

(f) reveal gaps between business demands and space availability and (g) analyze best fit facility planning 14

scenarios. IWMS will also increase SCE’s ability to efficiently allocate space by: (a) implementing 15

space plans that will improve our organization’s operational effectiveness, (b) recording how much 16

space each employee or department should be allocated and creating potential layouts, (c) comparing 17

layouts using summary reports, (d) mapping space availability with forecasted future demand (by 18

headcount, equipment or on a project basis), (e) tracking overall inventory of space and current and 19

planned occupancy, (f) allocating costs according to specific business rules, (g) visually exploring space 20

planning scenarios with interactive supply and demand analysis, and (h) addressing facility modification 21

impacts (e.g., lease terminations and renewals, new facilities or demand-side actions such as headcount 22

reductions). 23

(2) Work Management 24

CRE is currently utilizing SAP Enterprise Asset Management (EAM) 25

notification process to capture, track, and dispatch maintenance tasks, and create work orders. Although 26

the process is a centralized, self-service portal, the form is not tailored to properly identify specific 27

maintenance or change requests. This results in a manual effort to translate a maintenance or change 28

request into a more detailed notification to implement the maintenance or change request. With IWMS, 29

CRE would be able to coordinate work schedules, resource allocation and cost assessments. IWMS 30

would allow for (a) automated dispatch of urgent maintenance or change requests to the appropriate 31

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service provider or SCE personnel without the need for manual intervention, (b) identification of 1

available service and projected response and completion time, (c) creation and maintenance of damage 2

code selections that assigns requests based on need and required resources, (d) automated routing and 3

transmission of requests for required approvals, and (e) automated conversion of maintenance requests 4

into work orders through SAP ERP to capture costs and process of invoices. 5

(3) Facility Asset Management 6

CRE does not have an effective tool in place to track and manage 7

compliance requirements of facilities and facility equipment and systems and to maintain and utilize 8

facility equipment data such as historical maintenance and service activities, specifications, purchase 9

date, expected lifetime, warranty information, service contracts, and spare parts. IWMS would allow for 10

centralized monitoring of regulatory and other compliance requirements and automated alerts and 11

reminders (both to CRE and other responsible organizations within SCE) regarding compliance 12

activities needed to address those requirements. Implementation of IWMS would also manage 13

preventative maintenance programs for facility equipment by: (a) capturing and tracking facility 14

equipment details (including warranty information), (b) capturing and tracking work and cost history to 15

help maximize productivity and extend asset life, (c) monitoring asset and location conditions to enable 16

proactive, rather than reactive, maintenance that helps avoid unplanned downtime, (d) developing 17

preventative maintenance programs and corresponding maintenance work schedules, (e) automatically 18

creating maintenance notification and route for scheduled maintenance jobs. 19

(4) Facility Condition Index 20

CRE’s Facility Managers lack a tool to capture and track the operation, 21

condition and strategic value of SCE non-electric facilities and facility equipment. Having a common 22

repository of condition assessments will help evaluate the risks and financial impact of the condition of 23

our facility and equipment assets. This data can provide a comprehensive view of the necessary 24

maintenance items and associated costs across the facility portfolio. It can then serve as the basis for 25

CRE’s strategic facilities capital plan. With IWMS, Facility Managers could: (a) record and track key 26

information about facility equipment including state of repair, required maintenance, safety issues, and 27

adverse conditions, (b) create an objective, systematic framework for prioritizing work on buildings, 28

systems, and equipment, (c) rate how each asset performs in areas, such as life safety, regulatory 29

demands, and operational support, to objectively identify assets in need of immediate responsive action, 30

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(d) utilize assessments to trigger corrective and preventive work orders and (e) generate multi-year 1

capital budgets based on corporate risk mitigation strategy and operational priorities. 2

(5) Sustainability 3

SCE’s energy efficiency goals require CRE to manage critical information 4

on energy performance or water usage of facilities, and sustainability projects like energy retrofits. CRE 5

needs the ability to collect and analyze critical workplace asset information that integrates energy 6

consumption and emission data and unearths opportunities for improved energy efficiency and energy 7

savings at the building level and across the facility portfolio. IWMS would allow CRE to accurately 8

measure the environmental impacts of SCE facilities and opportunities to improve environmental 9

performance. This system can integrate with other rating systems to calculate and score certification 10

credits and assess the environmental performance against internal and industry benchmarks to identify 11

underperforming facilities. 12

c) Recommended Approach 13

SCE plans to acquire a Commercial Off The Shelf (COTS) Integrated Work 14

Management software package, which integrates the various business needs and data as described in the 15

Business Requirements section above. In recent years, the commercial software industry has made 16

significant advances in the design and production of software packages designed for the management of 17

extensive corporate facility portfolios. These software packages integrate data from SAP ERP and other 18

systems and provide real estate specific functionality for the analysis, use and reporting of this data. 19

As described in greater detail above, IWMS would give CRE an critical tool to 20

assign and track facility and equipment needs by (a) integrating the SAP ERP functionality currently 21

utilized for maintenance requests and work orders, (b) supporting workflow routing, (c) providing 22

customized user interface to support corporate personnel changes and moves, (d) collecting and 23

reporting data contained in maintenance and change requests to better tackle staffing and preventative 24

maintenance needs, (e) ensuring data integration from various sources, and (f) providing an interactive 25

database housing information relating to SCE’s facilities and their major systems and equipment to 26

enable more productive and efficient facility asset management. IWMS also provides an automated 27

process to monitor and track regulatory requirements and records of compliance for those facilities and 28

facility equipment and systems. 29

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d) Forecast Expenditures 1

Funding needs for IWMS are anticipated to be $3.36 million.116 This forecast is 2

based on the internal IT application costing model. The implementation of IWMS will require one year 3

(2014) during which the COTS IWMS package would be selected, acquired and installed, IWMS will 4

then be configured and integrated with SAP and other existing software, and the conversion of existing 5

data from multiple sources into the new system will be accomplished. 6

As of March 2013, CRE reduced its overall employee headcount by 42 FTEs due 7

in part to anticipated productivity benefits arising from proposed implementation of IWMS. Although 8

the number of CRE employees has decreased, the overall workload has not and is greatly burdened by 9

the lack of IWMS. As set forth in greater detail below, implementation of IWMS allows for retention of 10

certain cost savings associated with CRE’s reduction in force without the detrimental productivity loss 11

that would ordinarily result. 12

Planning: Strategic Master Planning over the past several years has relied on a 13

combination of FTEs and outside consultants whose master plans and survey-related services incur costs 14

in the hundreds of thousands of dollars. IWMS would allow this task to be performed with just FTE 15

resources and avoid costs associated with retention of outside consultants. Labor associated with 16

Annual Space verification surveys would also no longer be needed as our data would be housed in a 17

central database and maintained internally. IWMS would also greatly reduce the Planning cycle time for 18

employee moves since it would be automated through IWMS, instead of having to manually retrieved 19

the information from other systems. CRE estimates the planning-related cost savings to be 20

approximately $950,000 over 3 years reflected in CRE’s non-labor forecast and the aforementioned 21

CRE reductions in force. 22

Work Management: IWMS’s enhancements to CRE’s maintenance and change 23

request forms will reduce the time employees spend to manually enter the request by prefilling available 24

existing information that is pertinent to completing the form. CRE estimates work management related 25

cost savings of $520,000 over the next 3 years reflected in CRE’s reductions in force made in 26

anticipation of IWMS implementation. 27

Facilities Management: IWMS will enhance warranty tracking of equipment and 28

reduce unneeded payments tied to such equipment. CRE estimates a savings of $525,000 over the next 29

3 years. 30

116 See workpaper entitled “Forecast Expenditures Integrated Work Management System/CAD/CAFM Upgrade.”

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Reporting: Regular, integrated reporting would be one of the greatest benefits 1

from IWMS. Currently, reporting of facility condition and compliance requirements are gathered from 2

multiple sources of data and is a highly labor intensive effort. CRE personnel time spent monitoring and 3

recording compliance with regulatory requirements and gathering and normalizing the facility condition 4

data taking them away from time needed for other important functions, including analysis of facility 5

condition data. IWMS would allow for the centralization of relevant data for specified reports and 6

establish automated and periodic outputs for methodical analysis. CRE estimates the reporting-related 7

efficiencies gained through IWMS would yield a savings of approximately $780,000 over the next 3 8

years reflected in CRE’s reductions in force made in anticipation of IWMS implementation. 9

Table VI-36 below summarizes SCE’s projected costs and benefits for IWMS 10

during the 2014-2017 period. 11

Table VI-36 IWMS Costs & Benefits (2013-2017)

(Nominal $000)

2013 2014 2015 2016 2017 TOTAL

SCE CostsTotal $0 $750,281 $31,054 $31,054 $31,054 $843,443

Vendor Costs $0 $2,612,526 $0 $0 $0 $2,612,526

Annual Costs $0 $3,362,807 $31,054 $31,054 $31,054 $3,455,969

Benefits1. Planning $0 ($249,712) ($450,288) ($249,712) ($949,711)2. Work Management $0 ($173,329) ($173,329) ($173,329) ($519,988)3. Facility Management $0 ($262,500) ($175,000) ($87,500) ($525,000)4. Reporting $0 $0 ($260,017) ($260,017) ($260,017) ($780,051)Annual Benefits $0 $0 ($945,558) ($1,058,634) ($770,558) ($2,774,750)

Net Cost $0 $3,362,807 ($914,504) ($1,027,580) ($739,504) $681,219NPV (6%) $0 $0 ($862,739) ($969,415) ($697,645) $642,660

e) Conclusion 12

SCE needs to manage its non-electric facility portfolio in a more efficient and 13

productive manner. However, SCE’s current tools and manual processes do not provide adequate 14

support to do so. Therefore, SCE plans to spend $3.36 million to implement IWMS. 15

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3. Enterprise Compliance Management System 1

a) Project Overview 2

The Enterprise Compliance Management System (ECMS) is a software-based 3

system designed to track compliance requirements and the controls in place to meet those requirements. 4

The system also manages the performance of compliance tasks when appropriate. We proposed the 5

project in SCE’s Test Year 2012 GRC, and the Commission ruled that: “it is reasonable to implement 6

the [E]CMS on a company-wide basis to more effectively manage compliance needs.”117 We 7

commenced this authorized project in 2012. Now, we are updating the Commission as to the status of 8

this project and the associated recorded and projected project spending. 9


The Enterprise Compliance Management System establishes core compliance 11

processes for each organization to prevent, monitor, detect, and respond to actual and potential non-12

compliance events. 13

It facilitates the company’s ability to identify, document, and track new or 14

changing compliance requirements; 15

It provides a current, centralized repository for compliance requirements and 16

corresponding controls; 17

It establishes processes for validating compliance requirements, monitoring 18

control activities, testing and revising controls, detecting and managing 19

compliance-related issues, and evaluating and responding to actual or 20

potential non-compliance events;. 21

It standardizes roles and responsibilities to drive consistency and 22

accountability across the company; 23

It provides metrics and reports to provide visibility at the Operating Unit level 24

and the Company level regarding compliance-related activities, so that 25

managers can actively monitor those activities; 26

It identifies all SCE Operating Units, functions, and activities impacted by a 27

particular compliance requirement. 28

117 See A.10-11-015, SCE-07, Vol. 2, Ch. V, pp. 76-79; D.12-11-051, p. 504.

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This system will improve SCE’s ability to effectively adjust to changing regulatory requirements, and 1

our ability to track and ensure completion of the associated compliance controls and tasks. 2

In developing the ECMS system, SCE evaluated eleven off-the-shelf products, 3

and also examined the SAP Governance, Risk, Compliance module. Since SCE uses the SAP system, 4

the SAP module best fit our requirements at a comparable price, and facilitated much greater integration 5

with other existing and future operating systems that are configured for SAP. 6

c) Implementation Schedule 7

We commenced implementing the ECMS project during 2012. The project has 8

continued into 2013, and the core functions of the project will be operational in July 2013. During 2012, 9

we completed the design of the system, and built and tested the functions that allow us to input 10

requirements and catalogue compliance items. In July 2013, the following components will be 11

operational: 12

Intake Requirements – Review and approval process by which a law, 13

regulation, statute, or decision is analyzed to identify and document 14

compliance requirements that affect SCE operations. 15

Develop New/Modify Existing Control(s) – Processes for developing new 16

control(s) or modifying existing control(s) to meet identified or changing 17

requirements when issued by a regulatory body. 18

Catalog Management – Processes for periodically validating the catalog to 19

verify accuracy of controls, requirements, and other related attributes; as part 20

of this capability, we can revise controls as warranted. 21

Controls Testing – Processes for tracking the testing of how effective the 22

controls are; these capabilities support both independent testing and self-23

testing. 24

NERC Self-Certification – Processes supporting the Western Electricity 25

Coordinating Council’s requirement that registered entities annually certify 26

compliance with the North American Reliability Corporation’s (NERC’s) 27

reliability standards. 28

Issue Management – Processes for managing and tracking potential 29

compliance issues, so that SCE can proactively guard against non-compliance 30

items occurring. 31

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The first Compliance Programs to utilize ECMS are as follows: 1

Energy Regulation Compliance Program (ERCP), which manages compliance 2

requirements issued by the CPUC, CEC, and FERC; 3

NERC Compliance Program (NCP), which manages compliance requirements 4

issued by the NERC on reliability and critical infrastructure protections (CIP); 5

Human Resources Compliance Program (HRCP), which manages compliance 6

requirements issued by federal, state, and local agencies with jurisdiction over 7

conditions for employment (Title VII, NLRA, and FEHA), wage and hour 8

laws (FLSA), related state laws, unemployment, disability management 9

(FMLA), other employee rights (ADA, HIPAA) and benefits (ERISA and 10

IRS); and 11

Privacy Compliance Program (PrCP), which manages compliance 12

requirements issued by federal, state, and local agencies with jurisdiction over 13

identity theft prevention, protecting personally identifiable information, and 14

protecting private information (FCRA, PCI, HIPAA). 15

In 2013, we are developing an implementation plan to apply the ECMS 16

capabilities to SCE’s remaining compliance programs. 17

d) Recorded and Forecast Expenditures 18

Table VI-37 Comparison of Recorded to Forecast Expenditures

2012 Recorded 2013 Forecast Total Forecast Expenditures

$4.103 million $7.000 million $11.103 million

As discussed above, we commenced implementing the ECMS project in 2012. 19

Table VI-37 We recorded $4.1 million in capital expenditures in that year. SCE forecasts capital 20

expenditures of $7.0 million118 in 2013 to complete the project. In total, the project’s total costs are now 21

forecast as $11.1 million. Importantly, this amount is less than the $16.25 million cost we estimated 22

when the Commission approved the project in SCE’s 2012 GRC. We have obtained project savings 23

118 See workpaper entitled “Forecast Expenditures Enterprise Compliance Management System.”

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from vigorously negotiating with vendors, carefully adjusting the project schedule to do less work in 1

parallel, and identifying and gaining efficiencies during detailed project planning. 2

e) Conclusion 3

The Enterprise Compliance Management System will provide important 4

compliance management capabilities across many SCE compliance areas. SCE will complete this 5

project during 2013 at a total estimated cost of $11.1 million, which is several million dollars less than 6

what we originally forecast when the Commission approved the project. 7

4. Electronic Document Management/Records Management 8

a) Background 9

The company’s enterprise tool for managing “unstructured content” is the 10

Electronic Document Management and Records Management (eDMRM) system. Unstructured content 11

refers to documents (work-in-progress) and completed records that are not part of a structured database 12

and are created using office productivity products such as word processing or spreadsheet software. 13

Unstructured content includes all types of documents and records related to public safety, transmission 14

and distribution operations, engineering and construction documentation, equipment and apparatus 15

specifications, employee files, and customer billing. Trading, regulatory, and compliance records are 16

also considered part of unstructured content. Unstructured content includes file types such as MS Word, 17

MS Excel, “.pdf,” “.jpeg,” “.tiff,” “.awd,” and “.avi.” These file types are managed in eDMRM, with 18

appropriate indexing and security permissions assigned. 19

While day-to-day operations have become increasingly dependent on electronic 20

records and documents, the unstructured content lacks a pre-defined structure of information that allows 21

for effective search and retrieval. The documents and records do not contain, for example, metadata 22

tags to identify who the author is, what the version number is, or who has access privileges to the 23

document or record. Additionally, the unstructured content does not contain information that would 24

allow periodic deletion in accordance with a systematic Company-wide records retention policy. 25

Finally, the content lacks information that allows it to be linked to previous versions, and therefore lacks 26

a sound audit trail. 27

The lack of an organized structure for unstructured content has created a 28

challenging environment where it is increasingly less feasible to manage documents and records for both 29

operational and compliance purposes. Unless we implement additional technology, even relatively 30

straightforward tasks such as (a) gaining access to the latest design specification or a safety checklist, or 31

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(b) searching through a list of a thousand MS Word documents for litigation support purposes, or (c) 1

answering a regulatory data request, become a very long, inefficient, and error-prone process. 2

To add the required structure to these records and documents, we must implement 3

an incremental technology, called a “managed repository.” eDMRM is such a managed repository. 4

Managed repositories provide: 5

Custom metadata tagging, such as title and author information, so that we can 6

reduce time and error rate when searching for and retrieving documents, 7

records, and information; 8

Enforcement of access privileges and prevention of unauthorized access or 9

modification; 10

Version control capabilities; 11

Enforcement of automated records retention policies; 12

Secured document collaboration, with both internal parties and external 13

vendors; 14

Efficient document routing and approvals; and 15

Credible audit trail when creating and modifying documents. 16

In 2009, the Company purchased the OpenText software, which is the commercial 17

name for the eDMRM. We have implemented OpenText on a limited basis to manage documents and 18

records related to major transmission and distribution projects, NERC CIP evidence, Federal Aviation 19

Administration compliance, Transmission & Distribution Advanced Technology, and Power 20

Procurement Finance. Based on our experience with this limited deployment, we believe the OpenText 21

software provides a solid foundation for our management of unstructured content. 22


SCE’s Transmission and Distribution, Engineering Design Construction 24

Standards organizational unit conducted a survey in 2010 to identify opportunities for improving 25

operations and directly contributing to enhancing reliability of operations. Among the issues identified 26

in the survey, several were related to problems with unstructured content. These issues include the lack 27

of a single, centralized repository for quickly and easily storing and retrieving engineering standards, 28

specifications, and safety checklists. The survey indicated that lack of access to the latest versions of 29

these records can increase non-conformance of construction standards to specifications. The availability 30

of a central repository was cited as a critical success factor in improving productivity of operations. 31

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Table VI-38 below is a table summarizing the various business problems and risks 1

associated with managing unstructured content and the mitigating capabilities of eDMRM. 2

Table VI-38 Mitigating the Risk Associated With Managing Unstructured Content

Problems and Risks Mitigation Through eDMRM (OpenText)

Operational Delays - Critical reliability operations are potentially delayed due to lack of immediate accessibility to important documentation (e.g., equipment specifications, engineering drawings and job routines/procedures) for performing operations.

Enhance accessibility and speed of retrieval by implementing, custom metadata tags and advanced search capabilities of eDMRM.

Public Safety/Inflated Costs - Field construction and engineering jobs currently depend on manual access to the latest engineering drawings and specifications of the impacted asset, resulting in delays, inaccurate retrieval, and increased costs. The delay in retrieving documentation may impact public safety.

eDMRM Drawing Management solution provides: (1) the ability to consistently check-out and check-in logical grouping of assets and related sub-components; (2) controls for security, versioning, and access; and (3) audit trails to ensure transparency and ability to retrieve history.

Emergency Response – The ability to respond to emergencies or disasters events in an accurate and precise manner is less than optimal due to lack of required controls and accessibility to vital records

eDMRM supports the Company’s business resiliency plans, with its ability to operate on redundant failover architecture. eDMRM’s version management capabilities ensure the latest and best versions are retrievable on an expedited basis in emergency scenarios.

Security and Access controls – One of the key compliance requirements of NERC CIP Privacy, CEII is to ensure appropriate security and access protection to documentation related to Critical Cyber Assets, Personally Identifiable Information and Critical Energy Infrastructure Information. The current system of managing these documents in shared drives and document libraries without basic controls and assurance poses a high degree of compliance risk.

Implementation of eDMRM’s Security Clearance module provides the Company with the ability to apply an appropriate access permission model to protect these records from unauthorized access and possible tampering.

Evidence Management – Although the evidence of a completed inspection can be found in the ERP/SAP system, the actual readings or diagnostic tests are located in file shares, document libraries, and “My Documents.” Lack of visibility of the entire Maintenance and Inspection record impedes the Company’s ability to quickly respond to regulatory data requests.

OpenText extended ECM solution with SAP provides the ability to link SAP data to the actual diagnostic record to so that we have a complete and accurate record. The solution also provides for cross-functional workflow (through SAP or OpenText), including managing all security access permission consistently across ERP/SAP.

Legal Hold Management - Potential for mismanagement or tampering of critical business records that exist on file shares or document libraries, due to lack of controls or tools to apply Legal Holds.

OpenText’s Legal Hold management capabilities enable SCE to apply necessary controls to manage documents/records that are subject to a Legal Hold.

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(1) eDMRM Benefits Over Alternatives 1

The Company has extensively implemented SAP as the enterprise-wide 2

platform to systematically manage business operations. While SAP comprehensively captures business 3

transactional data, it does not have the ability to capture related unstructured content. For example, the 4

SAP system captures utility pole loading inspection information, but does not have the ability to capture 5

the associated diagnostic checklist that the field worker has completed. Integrating SAP transactions 6

with the associated unstructured content – the actual diagnostic record in this example – will eliminate 7

operational inefficiencies and expedite responses to regulatory data requests. SAP has announced that 8

OpenText is the product of choice for integrating electronic documents with its transactional data. The 9

Company will benefit from implementing the OpenText capabilities to enable integration with our 10

current and widespread use of SAP. 11

The Company’s core operations are highly reliant on engineering 12

drawings. Effectively managing and mitigating the unstructured nature of these drawings will result in 13

operational efficiencies. It is imperative that the document and records management solution we select 14

possesses the capability to support the unique requirements for the engineering drawings. Very few 15

document and records management products have this capability. OpenText’s Drawing Management 16

capabilities satisfy the majority of SCE’s complex requirements. 17

There are a number of products that provide document and record 18

management capabilities. However, there are very few vendor products that comply with the rigorous 19

requirements of the United States Department of Defense (DOD) Standard 5015.2, which is an industry 20

benchmark for electronic Records Management capabilities. OpenText has been certified to meet the 21

rigorous DOD 5015.2 standards. 22

Additionally, Gartner, a leading information technology research and 23

advisory company, has identified OpenText as an industry leader (in Gartner’s “magic quadrant” rating) 24

when comparing leading Enterprise Content Management providers.119 25

Several utilities and major corporations across North America have 26

successfully implemented OpenText for managing unstructured content. Below is a representative list 27

of companies using OpenText: 28

Duke Energy 29

119 See workpaper entitled “Gartner Study” for further details.

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Public Works and Services - Government of the Northwest Territories 1

Santee Cooper 2

Conoco Phillips 3

Central Vermont Public Service 4

Missouri River Energy Services 5

Tennessee Valley Authority 6

As discussed above, the Company initially purchased OpenText enterprise 7

licenses in 2009, and established hardware and software server infrastructure along with limited 8

implementation of OpenText libraries. Because of this limited deployment, the Company is not yet 9

obtaining the full benefits of its investment. By implementing eDMRM across the Company to manage 10

all unstructured content, the Company will be well-equipped to mitigate risks associated with managing 11

unstructured content, and reap the benefits (including cost avoidance) of improving operations. 12

(2) Additional Benefits 13

The primary reasons for fully implementing eDMRM are to improve the 14

Company’s operations, improve regulatory compliance, and mitigate risks. In addition, full 15

implementation provides several “soft” benefits for the Company. With full implementation, search and 16

retrieval of documents and records should be greatly enhanced, resulting in significant improvement for 17

typical knowledge workers’ productivity. According to a study performed in 2001 by the International 18

Data Corporation, a leading intelligence and advisory firm that analyzes technology trends: 19

“An enterprise employing 1,000 knowledge workers 20

wastes $48,000 per week, or nearly $2.5 million per 21

year, due to an inability to locate and retrieve 22

information.”120 23

Additionally, eDMRM will improve the Company’s ability to enforce 24

legal holds on documents and records subject to pending litigation or investigations. Implementing 25

eDMRM will result in migrating documents and records from uncontrolled file shares and document 26

libraries into eDMRM, where we can protect relevant documents and records from being deleted or 27

altered. As part of the implementation, “Redundant, Obsolete, and Trivial” data (or ROT data) that has 28

accumulated in Company file shares and document libraries will be identified and deleted. This culling 29

120 See workpaper entitled “International Data Corporation Study,” The High Cost of Not Finding Information – An IDC

White Paper, p. 7, July 2001.

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of data helps mitigate the risk of inaccurate data being presented during e-discovery efforts and reduces 1

the costs of e-discovery. For every gigabyte of ROT data deleted, approximately $7,500 in legal review 2

costs can be avoided. This figure is calculated as follows: 3

1 GB = 7,500 to 10,000 documents 4

Average attorney can review 50-100 documents per hour 5

Attorney review of 1 GB = 75 – 200 hours 6

Average attorney’s billing rate is $100 - $150/hour 7

Once stored in eDMRM, SCE can more systematically and timely dispose 8

of documents and records pursuant to the Company’s Records Retention Schedule. 9

By migrating documents and records from file shares, document libraries, 10

and My Documents, cost savings are achieved by transferring documents and records from high-cost 11

Storage Area Network (SAN) storage to low-cost Write Once Read Many (WORM) storage. This 12

represents an additional cost savings of approximately 20 percent per year related to SAN storage. 13

c) Implementation Overview 14

The full implementation of eDMRM company-wide is planned as a multi-phased 15

effort from 2013 through 2017. The implementation plan is based on a combination of factors, 16

including risk, change management, and operational priorities. Discuss below the key components of 17

the implementation. 18

d) Key Steps of Implementing Project 19

(1) Basic Document/Records Management 20

The first phase is providing users company-wide access to basic features 21

of eDMRM. This phase includes identifying and training content managers. This is a critical role for 22

providing day-to-day administration of document and records management activities. In addition, this 23

phase includes developing computer-based training material and change management workshops, and 24

establishing service desk and problem-solving processes and personnel. Additional activities include 25

development and training with respect to Active Navigation, a software product that will help clean up 26

Redundant Obsolete Trivial (ROT) data. 27

(2) Public Safety 28

Public Safety documents and records are related to operations that may 29

impact Public Safety. These are critical documents and records that need to be managed diligently so 30

that appropriate personnel can readily and securely access the material. This phase includes identifying 31

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all the repositories that contain Public Safety documents and records, preparing the data for migration 1

into eDMRM, and preparing data migration strategies. Additionally, we will develop a metadata 2

schematic to “tag” these documents for quick and easy retrieval. 3

(3) External Access Collaboration 4

This phase includes establishing a secure infrastructure and process for 5

enabling document collaboration with external vendors and partners. 6

(4) Auto-Classification Proof of Concept 7

This phase involves conducting a proof of concept to evaluate the 8

feasibility of implementing auto-classification (to automatically classify documents and records). Auto-9

classification can potentially reduce the need for manual intervention on a day-to-day basis. 10

(5) Email Management 11

Emails carry important business records for the organization. This phase 12

of implementation will include setting up technical integration between the Company email system and 13

eDMRM. It also includes migrating individual email archives into eDMRM and integrating each 14

department’s folder structure into email. 15

(6) Engineering Drawing Management 16

Implementation of eDMRM will include converting three obsolete 17

engineering drawing legacy systems, migrating drawings into eDMRM, standardizing the lifecycle 18

process for drawings, developing a hierarchy to organize components of engineering drawings, and 19

enhancing search capabilities. The implementation also encompasses putting in standard viewers for 20

opening drawings maintained in different file formats, including PLS-CADD (Power Line Systems-21

Computer-Aided Design and Drafting), AutoCAD (a computer-aided design software product), and 22

TIFF (tagged image file format). We must also migrate over 800,000 construction and engineering 23

drawings (identified as critical) into eDMRM. 24

(7) Company-wide Library Implementation 25

This phase includes a comprehensive Company-wide implementation of 26

approximately 200 document libraries. Implementation will involve, for each library, analyzing current 27

business operations, establishing a user-friendly document folder structure, gathering security 28

requirements, and developing an access permission model for the identified folder structure. 29

Additionally, it will be necessary to scope the migration effort for every library, cleansing these 30

documents of ROT data, and mapping the cleansed documents to the newly-identified folder structure. 31

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Basic workflows will be implemented for document routing and approval. We will develop Records 1

Series Identifiers to enforce the Company’s Records Retention Schedule. We will also develop the 2

metadata configuration based on specific business needs to help simplify the process of searching for 3

and retrieving documents. To help smooth adoption of these capabilities by users, we will train users 4

and implement change management strategies. Below, we provide a “snapshot” of the key components 5

involved in a typical library implementation effort. 6

Table VI-39 Typical eDMRM Library Implementation

1. SONGS Implementation – This phase includes decommissioning two existing legacy 7

document management systems, including the SAP Document Management module that 8

SAP no longer supports. We will also migrate documents from those legacy systems into 9

eDMRM. 10

2. My Documents – This phase includes migrating MS Windows-based My Documents over to 11

eDMRM, for every employee of the Company, desktop by desktop. The phase includes 12

implementing e-discovery and Legal Hold controls, and addressing change management and 13

user training. 14

e) Forecast Expenditures 15

(1) Cost Reasonableness 16

Based on information provided by Gartner, a leading information 17

technology research and advisory company, it appears that the approximate cost to implement a 18

document and records management system for 20,000 users is $60 million.121 The current estimate for 19

121 See A.10-11-015. SCE-04, Vol. 4, pp. 75-87, Customer Service Business Unit.

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implementing eDMRM Company-wide is $32.604 million. That investment, coupled with the $16 1

million that the Company has already invested in OpenText, is in line with the Gartner estimate , 2

particularly when, as here, our estimate includes implementing complex Engineering Drawing 3

Management, cleaning up legacy data, migrating data and records, and integrating with and leveraging 4

SAP capabilities. 5

(2) Forecast Cost by Year 6

Table VI-40 below provides the estimated costs of completing the 7

implementation of eDMRM through 2017. 8

Table VI-40 eDMRM Implementation Cost Summary

(2013-2017)

5 year Summary 2013 2014 2015 2016 2017 TOTAL

Basic DM/RM $1,200,000 $1,400,000 $2,600,000

Public Safety $610,000 $900,000 $1,510,000

External Access $240,038 $240,038

Auto Class POC $50,000 $50,000

eMail $1,500,000 $1,900,000 $3,400,000

Drawing Mgmt $904,048 $850,000 $1,754,048

All OUs $4,633,000 $4,644,000 $4,633,000 $13,910,000

SONGS $2,850,000 $2,850,000 $5,700,000

My Documents $1,167,011 $1,106,035 $1,167,580 $3,440,626

Total $2,100,038 $4,704,048 $11,400,011 $8,600,035 $5,800,580 $32,604,712

f) Conclusion 9

Through the implementation and expanded deployment of eDMRM, SCE will put 10

in place reasonable processes and information infrastructures to mitigate the challenges of ever-11

proliferating information in the electronic age. This will promote appropriate information-sharing 12

across the Company, while providing more accurate and complete information. This project will also 13

put appropriate controls in place to secure sensitive information. Ratepayer interests are served when 14

information critical to system reliability, security, and safety is managed in a sound manner. Ratepayers 15

also have an interest in data privacy and appropriate control of access to data. By prudently spending on 16

records management capabilities, we serve these vital ratepayer interests. 17

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E. Customer Service 1

1. Dynamic Pricing 2

a) Background 3

(1) Project Overview 4

In D.09-08-028, the Commission adopted a number of dynamic pricing 5

rates, effective October 1, 2009. SCE was required to propose additional default and opt-in dynamic 6

pricing options for residential, small commercial, and agricultural customers by January 1, 2012, 7

contingent upon the Commission’s approval of the rates no later than October 1, 2011. Due to various 8

delays, the Commission agreed to the new effective date of April 1, 2013 for the dynamic rates. The 9

rates are currently available. However, due to defaulting requirements, some classes of customers may 10

not default to these rates until as late as first quarter, 2015. 11

With the knowledge these rates needed to be implemented, in the 2012 12

GRC, CS requested and received approval for the Dynamic Pricing project.122 Because of the delay in 13

approving the additional default and dynamic pricing options, part of the Dynamic Pricing 14

implementation schedule has shifted into 2013 and 2014, necessitating SCE to request funding for the 15

Dynamic Pricing project again. 16

(2) Scope 17

The Dynamic Pricing project has several different applications in its 18

scope. While systems had to be enhanced to allow for the changes in rates and default options, new 19

energy cost tools were developed to provide customers with better understanding of their rates and the 20

relationship between their usage patterns and their electricity costs. The scope of this project includes: 21

Enabling calculation and billing of new rates in CSS; 22

Automating the rate change default process; 23

Developing and implementing customer opt-out and Capacity 24

Reservation Level (CRL)123 change capability; 25

Developing and implementing an on-line rate analysis tool; 26

Enhancing and expanding the current My Account Billing tools; 27

122 In D.12-11-051, p.855, the Commission approved the Dynamic Pricing project. The Results of Operation (RO) model

authorized $34.10 million for the expenditure and inflation adjustment.

123 In D.09-08-028, Attachment H, the CRL allows customers to pay a fixed charge for a predetermined portion of their load, and pay the dynamic price for usage above the CRL.

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Developing online customer support tools, such as Web Chat, to assist 1

customers with billing, rate and other inquiries; 2

Developing and implementing reporting capabilities; 3

Enhancing and expanding the CSS training region; 4

Updating Electric Service Planning’s DM System, Energy Analytics, 5

and Encost Systems to include the new rates; and 6

Developing and implementing a common back-end for all rate analysis 7

tools.124 8

(3) Implementation Schedule 9

The Dynamic Pricing project began in 2010 with the blueprinting of the 10

project. Work on the dynamic pricing rates, defaults, and online rate comparison and analysis tools 11

started in 2011, but were not completed until 2013. Customer service tools such as Web Chat, Web 12

Collaboration, and Web Call-back as well as a mobile application customers can access on smart phones 13

were initiated in 2011 and implemented initial scope in 2012, with expanded scope to be delivered in 14

2013 and 2014. The CSS training region for customer contact employees to learn the components of the 15

new dynamic rates, rate tools, and respond to customer inquiries will implement in 2014. 16

b) Recorded and Forecast Expenses 17

SCE is requesting $10.4 million in 2013 and $600,000 in 2014 to complete the 18

work started and already underway for the Dynamic Pricing project. These dollars are not incremental 19

to the $33.06 million already approved by the Commission but rather spend that was pushed into 2013 20

and 2014 primarily because of regulatory delays.125 21

The following table, Table VI-41, shows the total recorded and forecast costs for 22

the Dynamic Pricing project. 23

124 See A.10-11-015, SCE-04, Customer Service Business Unit, Vol. 04, pp. 75-87.

125 The estimated cost of the Dynamic Pricing is $1.5 million below what the Commission originally approved in D.12-11-051.

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Table VI-41 Dynamic Pricing Project Costs by Year

Recorded 2010-2012 and Forecast 2013-2014 (Nominal $ Millions)

Year 2010 2011 2012 2013 2014 TotalCosts 0.1$ 10.3$ 11.2$ 10.4$ 0.6$ 32.6$

c) Conclusion 1

Dynamic pricing rates, which SCE was ordered to implement in D.09-08-028, 2

will provide benefits to SCE and its customers in the form of increased price response and improved 3

customer energy management, which can lessen the need for additional supply-side generation capacity. 4

To enable these rates, SCE must make modifications to several of its information technology systems. 5

This project was already approved in D.12-11-051, but the project will now have costs in 2013 and 6

2014. 7

2. SCE.com Strategic Upgrade 8

a) Background 9


This SCE.com Strategic Upgrade project was requested in the 2012 GRC 11

and approved by the Commission in D.12-11-051.126 The project replaces the current SCE.com 12

infrastructure and migrates existing core applications to a new platform that will support the continued 13

use of the website as a robust source of information for rates, programs and services, as well as enable 14

new self-service tools for customers to complete routine transactions online. The project spans four 15

years, beginning in 2011 and ending by 2014. An additional part of this project focuses on the future 16

vendor updates, which typically occur 18 to 36 months after implementation and are needed for 17

continuous vendor support, enhanced features, introduction of new capabilities, and enhanced security. 18

SCE’s customers conduct business with SCE through the SCE.com 19

website. The website was first developed almost 10 years ago, and was initially intended to serve as an 20

online informational source for customers, providing details about rates, programs, and services. Over 21

time, the site grew to have more transactional capabilities that allowed customers to view their 22

electricity usage, display and print bills, and make payments. Residential, commercial and industrial 23

126 D.12-11-051, p. 859, approved the forecast costs in 2011 and 2012 with a 10% reduction for all SAM projects including

SCE.com.

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customers can also use the website to analyze their energy usage. The website infrastructure is 1

comprised of multiple components, including custom-coded applications as well as COTS packages that 2

support the various transactional capabilities, content management, and web analytics reporting. 3

Because many technology components of the website are no longer supported by the respective vendors, 4

the website needs to be replaced in order to address the technology obsolescence issues. 5

As stated in the Customer Service Policy testimony, SCE-04, Vol. 1 Ch. 6

III, SCE is changing its way of doing business with customers. SCE is addressing customers’ desires to 7

do more business through electronic channels. The modernization and upgrading of SCE.com as the 8

primary channel for customer self-service is at the center of SCE’s customer service model. SCE.com 9

will be a primary contact for SCE’s customers. With the increase in complex technologies and rates 10

enabled by Edison SmartConnect®, such as HAN functionality and devices, PEVs, Peak Time Rebates, 11

Critical Peak Pricing, and TOU pricing, SCE must reduce the number of routine transactions it handles 12

through customer service representatives, so that these representatives may provide more consultative 13

services for customers. 14

(2) Scope 15

(a) Completed Scope 16

The SCE.com Strategic Upgrade project must both improve the 17

customer experience and address the technology obsolescence problem. The existing Microsoft .NET 18

framework version 1.1 is no longer supported by Microsoft. The current system is obsolete from both a 19

business and technology perspective. SCE has implemented the new IBM WebSphere Customer 20

Experience Suite that includes various middleware and software products, such as WebSphere Portal, 21

WebSphere Commerce, Web Content Management (iWCM), WebSphere ESB, Tivoli Federated 22

Identify Manager (TFIM), and Portal Search Engine. The first release of the SCE.com Strategic 23

Upgrade was implemented in the first quarter of 2013. In order to migrate SCE.com to a new platform, 24

the new and old platform must co-exist for a period of time. The old platform will eventually be 25

decommissioned at the completion of the project. 26

The IBM Content Management tool was implemented and 27

provided SCE.com with platform integration and the ability to rapidly deploy content updates. Business 28

users can produce content without intervention from the IT department. Utilizing the new content 29

management tools, SCE streamlined and redesigned the website by reducing the total number of English 30

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pages from 2,500 to approximately to 400. The majority of these pages were then translated into four 1

different languages: Spanish, Chinese, Korean, and Vietnamese. 2

Training materials and computer-based training modules were 3

developed to teach internal departments, such as CCC, BCD and CP&S, about the redesigned site 4

navigation, user migration, and registration and profile management improvements. 5

For the first time, SCE is now able to offer its customers services 6

through mobile applications. Customers are now able to report outages and street light outages through 7

their mobile devices. Through Google Maps, customers are provided an at-a-glance view of current 8

outages across SCE’s territory with one-click access to additional details on the outage, such as the 9

cause of the outage, the status of the repairs, and the estimated restoration time. At this time, this 10

offering has only been optimized for iPhones and Android smart phones. In order to provide mobile 11

functionality for other smart phones and tablets, additional foundational work is required. (See the next 12

section, Device Flexibility or Mobile-First, for more information.) 13

(b) Current Scope 14

With the implementation of the IBM WebSphere, SCE must build 15

a new foundation for existing products and services. SCE will decommission or migrate over 50 16

different .NET applications to the WebSphere platform to create one holistic system that will enable a 17

consistent and expandable user experience, no matter what device the customer is using. 18

(i) Foundational Functionality 19

Release two will begin the first part of 2013 and continue 20

into 2014. The foundational framework will include the following five components. 21

(a) Device Flexibility 22

Mobile-First provides a multiplatform foundation 23

that delivers content parity for any device. Currently, SCE.com is optimized to support desktops and 24

laptops. Mobile-First will optimize the entire website to provide operational efficiencies by eliminating 25

the need to create separate websites optimized for mobile device access. By auto-detecting device 26

access format requirements, the webpages will resize and present content appropriate for the device. 27

(b) Bundling and Product Services 28

With a few simple questions and/or actions, SCE 29

will be able to provide relevant program and service recommendations through the use of a simplified 30

enrollment process. Based on data analytics and segmentation, customers receive a customized list of 31

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product offerings. Customers are able to enroll in multiple programs or services through a single 1

enrollment process. The simplified enrollment process will lead to increased customer satisfaction and 2

increase customer participation in the various programs. 3

(c) Customer Engagement 4

Customer Engagement will broaden SCE’s reach 5

from just account holders to all energy consumers and will deliver energy management solutions 6

through engagement and education. This suite of capabilities will provide new growth opportunities and 7

enable new features that are currently being developed. 8

(d) Personalization 9

Predictive analytics based on SCE.com data 10

collected from the user based on usage, behavior, feedback, and attributes will tailor the customer’s 11

online experience. Through the use of segmentation and analytics, more targeted, efficient marketing 12

and communication can be provided to the customer. 13

(e) Social 14

Social marketing and commerce functionality will 15

enable enhanced targeted education and outreach through social channels, as well as a channel for 16

customer advocacy. Through social media sites, such as Facebook and Twitter, SCE can proactively 17

reach customers regarding programs and services through the customer’s preferred channel. 18

(ii) Existing Application Migration 19

The foundational framework described above will be 20

incorporated as part of the existing application migration activities. More than 50 applications and 21

product offerings will be decommissioned or migrated to the new platform. Some of the basic 22

applications include: 23

(a) Online Turn-On, Turn-Off, or Transfer 24

Through the use of the Remote Service Switch 25

(RSS), customers can initiate or change their service any time online. Customers are able to request a 26

turn-on, turn-off, or transfer of their account 24 hours a day, 7 days a week, and the process occurs right 27

away.127 An order confirmation email will be immediately sent to the customer followed by an order 28

completion email once the service has been completed. Currently, this functionality is delivered by a 29

127 For customers who opt out of the Edison SmartConnect® program or non-residential customers, the process is still

automated, but the transaction will take longer to process.

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third-party vendor. This project will deliver this capability from the new SCE.com platform, thereby 1

eliminating the need for the third-party application and services. 2

(b) Billing and Payment Options 3

Customers will be able to view their bill using their 4

smart phone or tablet through a mobile-optimized website. Customers can also pay their bill using a 5

secure online payment module that will accept payments via credit card, debit, or a third party. After the 6

payment is made, customers will receive a confirmation of the payment. 7

(c) Account Information 8

While many of the account information items were 9

provided under the prior platform, this project will migrate these same offerings over to the new 10

platform so that customers will now be able to access these same offerings through any mobile device. 11

Customers will have access to usage data, usage diagnostic and analysis tools, and enhancements to 12

build in alerts with Call To Action functions. An alert is send to customers notifying them that they 13

need to pay a bill or reduce their energy consumption to meet their budgeted energy usage for the 14

month. Customers can respond to this alert by clicking to take action. 15

The user authentication and security features will 16

also be enhanced to allow modified access controls to approved third parties or external sources. These 17

can be vendors to whom customers grant access to their account information, such as property 18

managers, financial advisors, and guardians of special needs customers. 19

(d) Alerts 20

Alerts proactively notify customers of key account 21

information or issues like outages, high bills, and usage limits and are sent via the customer’s channel of 22

choice (e.g., phone, text, or email). Alerts through SCE.com are currently limited to Budget Assistant, 23

Save Power Day, and planned outages. Future alerts in development include proactive high bill, past 24

due bill, restoration of service after outage, and turn-on. 25

The system changes and enhancements discussed 26

within this alerts section are incremental to functions delivered as part of the Alerts and Notification 27

project also requested in this GRC. The Alerts and Notification project will establish the overall 28

enterprise system so that alerts and notifications can be sent. The SCE.com Strategic Upgrades will 29

enable the development of the functionality for SCE.com to become a channel for targeted messages 30

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from the Alerts and Notifications System and deliver the various messages through the SCE.com 1

platform. 2

(e) Rate Analysis 3

The rate analysis tool was developed as part of the 4

Dynamic Pricing project and built on the new SCE.com platform. However, the tool will be enhanced to 5

include the foundational functionality referenced above. Customers will be able to continue to analyze 6

what the best rate is for their usage but will be able to do it from a computer or any mobile device. 7

(f) Outage Center 8

As discussed earlier, as scope completed in Release 9

One, customers were provided access to mobile-optimized outage center website and Apple/Android 10

Outage applications for selected devices. This project will migrate the SCE.com outage center 11

applications to the new SCE.com platform while applying the foundational functionality referenced 12

above. 13

(g) Virtual Customer 14

While customers are utilizing the online tools or 15

SCE.com, they can click-to-chat with a customer service representative if they have any questions or 16

problems with their customer experience. 17

(h) Product Offerings 18

SCE.com will be moving to a new self-service 19

model that leverages IBM WebSphere Commerce and Marketing products to enable a “shopping cart” 20

and “check out” approach to enrolling in SCE Products/Services. Customers will be able to perform 21

tasks ranging from turning on/off service on a property to signing up for rebates or alerts programs, all 22

through a unified process referred to as “Opportunity to Order.” 23

Unlike today’s SCE.com, where product enrollment 24

processes vary significantly based upon the products selected, the Opportunity to Order process follows 25

standard process steps for all product offerings in the SCE.com Product Catalog. The standard 26

Opportunity to Order process will reduce friction for our customers by reducing the complexity and 27

eliminating the inconsistencies of SCE’s current online enrollment processes across the product 28

portfolio. This will lead to increased conversion rates for individual products and create higher attach 29

rates for cross-sell products. 30

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The SCE.com Product Catalog contains SCE 1

products/services including “bundles” and “Lifestyle Plans” that are available for online enrollment 2

utilizing the Opportunity to Order Process. Product Bundles and Lifestyle Plans can be created in the 3

catalog, provided that the individual components in those bundles and plans also exist in the catalog. 4

A customized list of product offerings can also be 5

provided to the customer based on the data analytics and segmentation of the customer gathered through 6

the customer’s usage, behavior, feedback, and attributes. 7

(iii) Future Upgrades and Standards 8

As part of the Strategic Upgrade Program, SCE will be 9

implementing the IBM WebSphere Customer Experience Suite. The new platform will provide a 10

number of capabilities and functionalities that SCE could not achieve with the prior obsolete platform. 11

In order to maintain the most current commercially available major release and maintain vendor support, 12

SCE plans to implement and upgrade in alignment with the WebSphere roadmap during the 2017 13

timeframe. Any new version of the product will require evaluation for the need and compatibility of the 14

requirements. Costs for license renewals and growth in user population, professional services, and 15

departmental support will be included in the upgrade. 16


The SCE.com Strategic Upgrade project spans five years. It began in 18

2011 and is expected to end by 2014. After the new platform has been implemented, vendor updates 19

will be required by 2017 to maintain continuous vendor support. The upgrade will also provide for 20

enhanced features, introduction of new capabilities, and enhanced security. 21


(1) Current System and Process 23

SCE.com’s prior platform and architecture were not able to support the 24

changing business needs of SCE and its customers. The prior system had reliability risks. The 25

SCE.com applications lacked standards-based design that renders the entire system difficult to maintain 26

and scale. Extensive reprogramming efforts would have been needed to accommodate the expected 27

increase in the types and volumes of transactions SCE expects in the near future. Thus, in the 2012 28

GRC, SCE requested and received approval to replace the current SCE.com infrastructure with a 29

platform that would be able to support the changing business needs of SCE and its customers. 30

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(2) Alternatives Considered 1

SCE analyzed the replacement of SCE.com website and its associated web 2

applications. It was not a viability option to extend the life of the website by replacing just the obsolete 3

technology components. In addition to the obsolete components, such as the Microsoft Web Content 4

Management System 2002 (no longer supported by the vendor), many of the web applications in the 5

website were written in an older programming language using earlier platforms and styles, such as 6

.Microsoft's .Net 1.1 and .Net 2.0 technologies which are obsolete. 7

The prior SCE.com website was completely custom developed. It had 8

become maintenance-intensive due to the varying ages and styles of the component applications. The 9

website lacked the kind of out-of-the-box capabilities of more modern web platforms, leading to longer 10

lead times and greater effort to add new capabilities. 11

The alternative to developing a replacement for SCE.com was to purchase 12

a vendor developed package, which would be integrated and allow the vendor to provide future software 13

development, support and avoid obsolescence, while SCE would focus on the content of the SCE.com 14

website. 15

(3) Cost-Benefit Analysis 16

This system is obsolete and no longer supported. As such, a cost-benefit 17

analysis was not used in determining the need for this project. The prior SCE.com website was custom 18

developed. It had become maintenance-intensive due to the varying ages and styles of the component 19

applications. Extensive reprogramming efforts would have been needed to accommodate the expected 20

increase in the types and volumes of transactions SCE expects in the near future. 21


The forecast capitalized software costs of $44.4 million in 2013 and 2014 are to 23

complete the work started and already approved for the SCE.com Strategic Upgrade project. An 24

additional amount of $12.6 million is forecast to implement the IBM WebSphere Customer Experience 25

Suit. The costs are comprised of labor, hardware, licensing and contingency costs.128 Estimates for IT 26

support are based upon prior experience with similar projects and vendor quotes. Based upon various 27

types of developmental or COTS projects, labor rates, contingency levels, and cost components are 28

128 See workpaper entitled “Forecast Expenditures for SCE.com Strategic Upgrade.”

117

utilized to develop the overall cost estimate of the project.129 The system modifications required for 1

these enhanced products are considered a large COTS project under IT’s estimating method. 2

The following tables, Table VI-42 and Table VI-43, shows the total recorded and 3

forecast costs for the SCE.com Strategic Upgrade project and the forecast cost for the SCE.com Futures 4

Upgrades, respectively. 5

Table VI-42 SCE.com Strategic Upgrade Costs by Year

Recorded 2010-2012 and Forecast 2013-2014 (Nominal $ Millions)

Year 2010 2011 2012 2013 2014 2015 TotalCosts -$ 8.7$ 15.5$ 30.6$ 13.8$ -$ 68.6$

Table VI-43 SCE.com Future Upgrades

Forecast 2013-2014 (Nominal $ Millions)

Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ -$ -$ 12.6$ 12.6$

d) Conclusion 6

SCE continues to encourage customers to utilize the SCE.com website as a low-7

cost option for simple and frequent customer inquiries. An increasing number of customers favor online 8

access for enrollment in programs and simple inquiries over calling and speaking with a customer 9

service representative. Many of the technology components of the prior website platform are no longer 10

supported. The website needed to be replaced in order to address the technology obsolescence issues. 11

In D.12-11-051130, the Commission approved SCE’s request to update the SCE.com platform. This 12

project continues the work that SCE started in 2011. 13

129 See SCE-05, Vol. 1, Ch. II; and workpapers in the same volume entitled “2015 GRC IT Capital Estimates TEMPLATE

v1.doc” and “GRC Estimation Worksheet TEMPLATE v1.1.xls.”

130 D.12-11-051 is the Decision to SCE’s 2012 GRC.

118

3. Edison SmartConnect® (ESC) Project Stabilization 1

a) Background 2


This project includes system stabilization efforts performed in 2013 to 4

existing Edison SmartConnect® systems, including the ESC Monitoring and Analysis System 5

(SCMAS), ESC Meter Services Organization (MSO) Order Optimization Project, ESC Data Warehouse 6

Stage 3, and other system enhancements implemented within the ESC system portfolio in 2012. System 7

stabilization refers to the activities to ensure proper system performance. Stabilization efforts include 8

documenting and addressing system problems, and improving overall system performance. These 9

activities are critical because the new systems are live and these activities limit potential disruption to 10

business activities. Stabilization efforts often require new development and training. Funding for 11

system stabilization is usually included in the cost of the project. However, because the implementation 12

of these systems were funded through the ESC Program, the funding for system stabilization costs 13

incurred after 2012 must be funded through the GRC. 14

(2) Scope 15

(a) SCMAS 16

The SCMAS system is the main interface used to monitor and 17

analyze the ESC Meter and Communications System. It acts as an umbrella for a single point of entry 18

and control for NMS, SEM, CRA, security, and visualization. SCMAS Phase 1 provided the data 19

repository for the storage of data collection from field devices and data from ancillary sources required 20

for monitoring and analytics, created a Rules Engine that provides data analysis and correlation using 21

rules to identify events and incidents, delivered incident and activity management tools, provided 22

situational awareness through the real-time visualization of incidents and system issues, and delivered a 23

reporting system to support SOC processes and the analysis of incidents. SCMAS Phase 1 was 24

implemented in November 2012, and stabilization efforts for this phase are scheduled to be completed 25

by the end of 2013. 26

(b) MSO Order Optimization Project 27

The MSO Optimization Project implemented functionality to 28

optimize the process for working orders in the field for ESC meters (e.g., pick-up reads, turn-on/turn-off 29

orders, disconnect/reconnect orders). Specifically, the project implemented new mobile solutions and 30

scheduling software to support automated optimization of meter reading and field service orders and 31

119

enable the decommissioning of obsolete legacy systems. These solutions are required to provide 1

enhanced resources and work order scheduling efficiencies for a reduced field workforce. The MSO 2

Order Optimization Project was implemented in June 2013 with stabilization efforts scheduled to be 3

completed in July 2013. 4

(c) ESC Data Warehouse Stage Three 5

Stage Three of the ESC Data Warehouse implemented 6

functionality for load research services, demand forecasts, settlements, and aggregated demand 7

response, among other functionalities. ESC Data Warehouse Stage Three was implemented in October 8

2012, and stabilization efforts were completed in January 2013. 9

(d) Other System Enhancements 10

In December 2012, SCE implemented numerous enhancements to 11

the ESC System Portfolio, including enhancements to the ESC Data Warehouse to improve analytics, 12

usability, security and governance. Other back office systems were enhanced to allow for Budget 13

Assistant enrollment, intra-billing cycle tools, work order system improvements, automated test scripts 14

for future enhancements, and HAN device testing and functionality improvements. Stabilization for 15

these enhancements was completed in March 2013. 16


The ESC system stabilization efforts are scheduled to start and end in 18

2013. 19


(1) Current Systems and Processes 21

The system stabilization efforts support the SCMAS, MSO Optimization 22

Project, ESC Data Warehouse Stage Three, and the other system enhancements described previously. 23

No other systems and processes are impacted by these system stabilization efforts. 24


SCE has not considered alternatives because the system stabilization 26

efforts are required as part of the implementation of the respective systems. The system costs have 27

already been incurred. This project allows SCE to work through any problems that were unforeseen 28

during the implementation process. 29

120


SCE did not perform a cost-benefit analysis for this project because the 2

system stabilization efforts are required as part of the completion to these system implementations. 3


The cost for the ESC Project Stabilization project is $4.4 million, and is 5

comprised primarily of labor expense.131 6

Table VI-44 below illustrates the forecast expenditures of the Customer Service 7

System project by year. 8

Table VI-44 Capital Forecast Expenditures for

the Edison SmartConnect® Stabilization Project (Nominal $ Millions)

Year 2013 2014 2015 2016 2017 TotalCosts 4.4$ -$ -$ -$ -$ 4.4$

d) Conclusion 9

The ESC Project Stabilization efforts in 2013 were integral to the ESC systems 10

and systems enhancements implemented in 2012. System stabilization includes activities to ensure 11

proper system performance. Any system problems discovered at implementation need to be addressed 12

and corrected. 13

4. Meter Service Organization (MSO) Integrated Work Management Systems Project 14

a) Background 15


MSO was formed from different organizations within Customer Service 17

and the Transmission and Distribution Operational Unit (TD), with each group bringing and using its 18

own processes and work management systems to conduct its daily activities. Prior to Edison 19

SmartConnect® (ESC), this was a recognized issue, as the five major systems were disparate and not 20

integrated: Premier Plus 4 Meter Reading, Advantex, Electric Metering Service Tracking (EMST), 21

Meter Shop System (MSS), and Field Automated Test System (FATS). With a large workforce, MSO 22

was able to function and complete the necessary tasks. With the implementation of Edison 23

131 See workpaper entitled “Forecast Expenditures for Edison SmartConnect® Stabilization Project.”

121

SmartConnect®, MSO eliminated 100 percent of its Meter Readers and 75 percent of its Field Service 1

Representatives. With this organizational transformation, the way work is done must dramatically 2

change an integrated work management system, which delivers all work types to field resources in any 3

location as needed to successfully conduct routine and non-routine work, is required. 4

As part of the Edison SmartConnect® program initiative in 2012-2013, 5

MSO initiated the decommissioning and replacement of two obsolete work management systems, 6

ITRON’s Premier Plus 4 Meter Reading system and ABB’s Advantex, as both systems were operating 7

on obsolete technology platforms. This decommissioning project was funded from the Edison 8

SmartConnect® Balancing Account (ESCBA). With the replacement of these two systems, separate 9

functions are being integrated into one system, ClickSoft. Full implementation is expected to occur by 10

November 2013. With the implementation of the work management and the asset management systems, 11

these systems can interface with the Customer Service System (CSS) to extract customer information 12

and work orders to then be displayed within field tools. The field service representatives can be 13

assigned workloads based on geographic locations and difficulty of work. 14

(2) Scope 15

The integration project is split into four different areas of scope: 16

ClickSoft, End-to-End, Obsolescence, and Work Management. 17

(a) ClickSoft 18

The first area will enhance the ClickSoft application functionality. 19

The 2012-2013 implementation of the ClickSoft product for replacement of Advantex and Premier Plus 20

4 will implement Click Schedule and Click Mobile. It does not include the remaining Click modules: 21

Click Forecast, Click Plan, and Click Analyze. This project will implement the remaining vendor 22

modules to provide a full end-to-end work-flow process for field work initiation, planning, scheduling, 23

execution and close (IPSEC model) for the Click product software work management platform. The 24

remaining modules will enable MSO to realize the most effective and efficient use of the new work 25

management platform. 26

(b) End-to-End 27

The second area of scope will implement a single meter asset 28

management system. Today, meter asset information is stored in three disparate and technologically 29

obsolete systems. The obsolete platforms upon which the business information is built faces challenges 30

to evolve with more current technologies, such as Windows 7: 31

122

Meter Equipment System (MES) – Locates the street location 1

of a certain meter number, 2

Meter Shop System (MSS) – Tracks when the meter arrives 3

into inventory and any testing performed, and 4

Meter Tracking Tool (MTT) – Tracks meters into and out of 5

storage. 6

The meter information is being stored in the different systems is 7

inconsistent among systems. The various assets tracked in the systems includes meters, metering units, 8

cell relays, metering tools, Current Transformer and Voltage Transformer, antennas, and range 9

extenders. Additional assets that are not currently tracked but will be tracked with this implementation 10

include: Broadband Global Area Network (BGAN, satellite communications), agriculture pump 11

interruptible devices, transducers, pulse interface boxes, and Time Management Load Control devices. 12

None of the systems are integrated for a view of the life of the meter. The implementation will provide 13

end-to-end automation for the full meter life-cycle. This will allow for the tracking and reporting of the 14

various assets and create an integrated system of asset data for a single source of truth. 15

(c) Obsolescence 16

The next area of scope will replace the three remaining obsolete 17

systems in MSO, which were not included in the Edison SmartConnect® deployment. The three 18

obsolete systems that need to be replaced are the FATS, the MSS, and the EMST systems. (See Section 19

b) Business Requirements, (1) Current Systems and Processes of this Section for more details on these 20

systems.) These systems will be consolidated into one system to allow for an integrated work 21

management platform to efficiently and effectively manage the field workforce. 22

(d) Work Management 23

The last area of scope for the MSO Integrated Work Management 24

project includes the automation of a work management system between T&D and MSO. There is 25

currently no automated system between the two departments. The manual process consists of cross-26

departmental handoffs, phone calls, and instant messages to assign and complete work orders. With the 27

implementation of ClickSoft as MSO’s new work management system, an automated and efficient 28

solution to address emergency situations is needed to provide higher quality services to SCE’s 29

customers. With T&D and MSO operating on the ClickSoft scheduling platform, SCE will eliminate 30

multiple manual processes. By integrating the T&D Click Scheduling function with MSO’s function, 31

123

trouble orders can be assigned to MSO by T&D in emergency situations. The current inefficiencies 1

surfaced during the 2011 emergency windstorm event. Emergency trouble orders from T&D had to be 2

manually transferred to MSO’s field personnel who were supporting the emergency effort. When the 3

work was completed, the same manual process was used to update T&D. 4


The MSO Integrated Work Management System project is scheduled to 6

start in 2014 and end by 2017. 7



The MSO group was formed from different groups within the Customer 10

Service and Transmission and Distribution, with each group bringing and using its own processes and 11

work management systems to conduct its daily activities. Of these systems, five were recognized as the 12

main systems, but all were disparate and not integrated for sharing information. Two of these systems, 13

Premier Plus 4 Meter Reading and Advantex, are being decommissioned and replaced with ClickSoft. 14

There are three other systems that are obsolete and in need of replacement. 15

The EMST is an SCE-developed work management system used by 16

engineering operations for special-purpose engineered meter work orders and projects. It provides the 17

ability to track and maintain engineering prerequisites, such as engineering requirement, design 18

specification, engineering sheet, material, cost, contract, labor, and supplemental data that are mandatory 19

for completion of work by the meter technician. This system was developed in Delphi 7 as a 20

programming language with SQL 2000 as a backend database. Both these technologies are multiple 21

versions behind and obsolete. 22

The MSS is an SCE-developed meter identification, meter tracking, and 23

meter testing software package designed to enter meter data into the MES system. This system was 24

developed in Delphi 7 as a programming language with SQL 2000 as a backend database. Both these 25

technologies are multiple versions behind and obsolete. 26

The FATS is an SCE-developed work management system utilized by 27

Electrical Metering Services to manage electrical meter testing work orders to ensure accuracy of SCE 28

metering systems. This system was developed in Delphi 7 with Visual Basic 2005 as the programming 29

language and SQL 2000 as a backend database. All these technologies are multiple versions behind and 30

obsolete. 31

124


MSO will face great and costly business operation challenges if its core 2

business systems continue to operate in a disparate non-integrated manner. Field resources will be 3

unable to utilize and distribute work in the most effective manner because constraints between systems 4

will not allow for interchangeable work to be assigned across the field workforce. 5

The obsolete platforms upon which the technology is built are facing 6

challenges to evolve with more current technologies, such as Windows 7. This causes additional risk to 7

CS when systems are unable to be upgraded to more current system releases, which are company-wide. 8

SCE reviewed the possibility of implementing the SAP Customer 9

Relationship & Billing (CRB) solution. This functionality allows the system to read, bill, invoice, 10

collect payment, and provide customer service for a utility company. There are many modules within 11

the CRB, but the scope was limited to asset management and meter tracking. The cost estimate for this 12

COTS package was more than if the system were developed internally by SCE. SCE decided on using 13

the lowest cost option. 14


The existing systems are obsolete and no longer supported. The obsolete 16

platforms upon which the business information is built is facing challenges to evolve with more current 17

technologies such as Windows 7. The technology will be disparate or not integrated when SCE has 18

company-wide system upgrades. For these reasons, a cost-benefit analysis was not considered in 19

prioritizing the project. The project will provide cost savings to operations by efficiently staffing and 20

scheduling work assignments by the availability of resources. There are also cost savings from the 21

reduced maintenance costs associated with not having to fix or modify an obsolete platform. 22


The forecast capitalized software costs of $24.7 million for the MSO Integrated 24

Work Management Systems project are comprised of labor, hardware, licensing and contingency 25

costs.132 Estimates for IT support are based on prior experience with similar projects. Based upon 26

various types of developmental or COTS projects, labor rates, contingency levels, and cost components 27

132 See workpaper entitled “Forecast Expenditures for Meter Service Organization (MSO) Integrated Work Management

Systems Project.”

125

are utilized to develop the overall cost estimate of the project.133 The end-to-end project was considered 1

a “large development project” with components being a COTS project. 2

Table VI-45 below illustrates the forecast expenditures of the MSO Integrated 3

Work Management project by year. 4

Table VI-45 Capital Forecast Expenditures for the MSO Integrated Work Management Project

(Nominal $ Millions)

Year 2013 2014 2015 2016 2017 TotalCosts 3.0$ 3.7$ 8.4$ 4.9$ 4.7$ 24.7$

d) Conclusion 5

The MSO Integrated Work Management project is needed to implement and 6

replace MSO’s current disparate and obsolete technology with an integrated work management platform 7

enabling the efficient use of MSO’s field resources. These systems maintain capabilities critical to 8

sustaining business operations within MSO. If the systems are not replaced, MSO will continue to 9

struggle with optimal performance from its field staff as work is not efficiently distributed across all 10

field resources. Challenges will continue in maintaining obsolete technology and will become more 11

difficult as technology continues to evolve. 12

5. Digital Experience Program 13

a) Overview 14

(1) SCE’s Customer Engagement Model Continues to Evolve 15

In the 2012 GRC, the Customer Service Operating Unit (Customer 16

Service) outlined a strategy to meet the increasing desire of customers to do more business through 17

electronic channels.134 SCE introduced a technology-enabled customer service delivery model that 18

upgrades and modernizes SCE.com. The internet joins the Customer Contact Center (CCC) as the 19

primary contact points for customer service. 20

In Exhibit SCE-04, Vol. 1, the evolving Customer Engagement Model is 21

described and has at its foundation the requirement for technology investments to transform SCE’s 22

customer service delivery processes. The Digital Experience Program will integrate customer 23



134 A.10-11-015, SCE 2012 GRC; SCE-04, Vol. 1, Ch. II, pp. 3-8.

126

information that is currently spread across multiple systems into one integrated program. This program 1

will provide a comprehensive view of the customer; increase self-service options; enable and empower 2

our customers to research, evaluate, enroll, and identify future options for managing their energy use. 3

(2) Technology in Customer Self-Service Options Has Advanced Rapidly 4

As discussed in Exhibit SCE-04, Vol. 2, Ch. VIII.B.2, the majority of 5

customers in deregulated markets now prefer multiple self-service channels. Customers are rapidly 6

moving away from paper bills and in-person (including in-home) transactions and moving toward 7

mobile and web-enabled channels. 8

Customers are seeking broader access through multiple channels with 9

more consistency and ease of use. This will result in a transformational shift in the way SCE delivers 10

the customer experience. While the transformation will not happen overnight, it will require an 11

investment in current and new systems. 12

(3) An Investment in Integrated Technology Is Required 13

SCE plans to invest $91.5 million in the 2014-2017 time frame to increase 14

customer self-service options by expanding the digital customer experience. The Digital Customer 15

Experience Program, along with policy changes and targeted marketing will enable growth in multiple 16

self-service channels. This program consists of five critical systems: SCE.com/Customer Relationship 17

Management (CRM) Integration, Advanced Speech Recognition/Text to Speech Technologies, Alerts & 18

Notifications, Outage Communication Improvements, and the Customer Data Warehouse (CDW). 19

(4) The Digital Experience Program Provides Long Term Benefits 20

Building and integrating these systems over the next five years will 21

provide our customers the tools to achieve multiple goals and benefits. With access to multiple easy-to-22

use channels, SCE can reach out to customers to advance personalized programs across their preferred 23

channels. Benefits will be achieved across the three areas shown in the figure below, Figure VI-3. 24

127

Figure VI-3 Digital Experience Benefit Areas

Each of the individual systems requires integrated capabilities that deliver 1

benefits once all systems are efficiently in operation. The combined benefit-cost ratio of these systems 2

is 1.96. Benefit achievement will be staged over time with benefits starting in the early years and 3

substantially increasing after full integration in 2018 and beyond. 4

Not only will this Program achieve quantifiable benefits, but public policy 5

objectives will be advanced by giving SCE better tools to reach out to customers to encourage 6

participation in DSM Programs and increasing outreach to, and participation in programs from, mass 7

market and low income customers. As described in Exhibit SCE-04. Vol. 2, Ch. VIII, low income 8

customers are early adopters of using mobile channels for transacting business with SCE. Industry 9

trends also suggest low income customers are one of the fastest growing segments to use smartphones 10

for online access.135 11

This program will also provide more value to our customer population by 12

increasing the number of channels available for transacting business and communicating with SCE, 13

whether it be by mobile applications for outage information, calling the CCC and transacting business 14

through the Interactive Voice Response (IVR), or using the internet for online billing and payment. 15

135 Table “The Demographics of Smartphone Users Who Go Online Using Their Cell Phone.” Source: The Pew Research

Center’s Internet & American Life Project, April 26- May 22, 2011.

128

(5) Shifting Customer Experience towards Broader Access 1

In 2012, customers primarily used the telephone and computer channels to 2

connect with SCE. The CCC is available 24 hours a day, 7 days a week with several basic service 3

transactions available on SCE.com. Recent changes on SCE.com have allowed for expansion of 4

mobile/Short Message System (SMS) capability. Customers generally still utilize the telephone channel 5

for a majority of transactions and certain basic web transactions are not fully automated, requiring back 6

office processing that is manually performed by employees. 7

By 2018, SCE expects customers will primarily use digital devices to 8

connect with SCE, with customer service representatives available for complex or specialized needs. 9

Expanded channels will include Web-Portal, IVR with advanced speech capability, mobile smart phone, 10

in-home devices, text messaging, and email. The growth in technology towards home area networks and 11

energy efficiency offerings in the home will further drive SCE toward providing customers with a more 12

effective digital experience. This will also require expanded customer support for web and mobile 13

device technical interactions as described in CCC testimony.136 14

Regardless of the channel, customers will require a consistent and easy-to-15

use interface to serve the majority of their needs around the clock. All systems that deliver this 16

functionality will require shared information to deliver the consistent customer experience. The goal 17

will be to provide consistent and tailored experiences on all channels, with immediate and convenient 18

access through customer self-service. Most transactions will be completed in simple online interaction 19

with the customer through their preferred channels. 20

(6) Shifting Customer Experience Impacts SCE’s Self-Service Model 21

SCE’s service delivery model of the past was designed around calls made 22

to the CCC as the primary interaction point for providing basic customer service with other channels for 23

information and secondary support. As described in Exhibit SCE-04, Vol. 2, Ch. VIII, the concept of 24

basic customer care is changing. Basic customer care will include online tools such as Budget Assistant 25

to help customers manage their energy usage, assistance on pairing the smart meter with a home energy 26

management system, notifications to customers on their preferred devices about planned and unplanned 27

outages or triggers for specific energy program limits. In addition, options will be presented through the 28

web interface on personalized energy efficiency programs a customer would be eligible to join. Basic 29

customer service expectations will include more personalized energy management program offerings. 30

136 See SCE-04, Vol. 1, Ch. II.

129

To be responsive to customer needs, this kind of information must be available to customers on all 1

contact channels. 2

Today, each channel is individually managed with little to no cross-3

channel communication, making it difficult to provide consistent messaging to customers. The Figure 4

VI-4 below illustrates the shift that is required to meet customer expectations. 5

Figure VI-4 Customers Move To Self-Service Creates A Shift In How SCE Delivers Service And Information

On the left half of Figure VI-4, above, a customer’s profile is not available 6

to all channels, and business rules are based on the channel used. Feedback from customers is not 7

shared across all the channels. Overall, with this configuration, cross-channel communication can be 8

cumbersome, confusing, and inconsistent. On the right, all customer options for self-service channels 9

come together in a common data warehouse to build and use a common customer profile; integrated 10

business rules are created for all activities. When this happens, the customer’s experience is fluid, 11

consistent, efficient, and reliable. 12

130

(7) Investment in Technology is Required to Meet Customer’s Shifting 1

Expectations 2

The success in meeting customers’ shifting expectations depends upon 3

delivering and sharing the same customer information across all channels of communications and 4

interactions. Regardless of their communication channel used, customers expect timely and consistent 5

response. A customer may first notify SCE of a problem via the website. Later that day, the customer 6

may post an inquiry on social media from a mobile phone wanting a status update. That evening, the 7

customer could decide to call the CCC. In all cases, the customer should be able to provide minimal 8

information to receive a coherent and consistent response. This is possible today only on a very limited 9

basis with the technology in place. 10

Moving from individual stand-alone communication channels where 11

cross-channel information sharing is limited requires an investment in multiple systems to create a 12

digital experience that will enable benefits to begin in 2015 and increase over-time. The business 13

justification requires that all systems operate together to achieve full benefits. The following describes 14

the scope of each system, which, once in operation, will produce the integration of business process and 15

information needed. Full benefits will require both the technology implementation to be stable and for 16

the migration of customer behavior to the new, lower-cost channels. Future operating benefits will be 17

reflected in the 2018 GRC Test Year. The scope of these systems is described below. 18

b) Digital Experience – Systems Overview 19

(1) Upgrade the Interactive Voice Response to Utilize Advanced Speech 20

Recognition (ASR) and Text to Speech (TTS) Technologies 21

(a) Scope 22

This project will upgrade the Interactive Voice Response (IVR) 23

application to increase self-service capabilities. The scope of this project will cover two main areas, the 24

ASR and the TTS capabilities for English and Spanish language interactions. 25

In 2010, the Customer Contact Center (CCC) implemented a new 26

Contact Center infrastructure, both hardware and software. This included a new IVR environment 27

designed with consideration for future speech recognition applications. Application development and 28

software licenses will be required to utilize and deploy the ASR and TTS functionality. Hardware 29

capacity and performance will be evaluated as part of this implementation. 30

131

ASR allows for access to non-numeric information, which will 1

help obtain the customer’s identity. For example, a power outage may more easily be reported using a 2

service address and a phone number. ASR will also simplify the collection of dates and currency 3

amounts from customers, allowing them to speak naturally as opposed to pressing buttons. For example, 4

a customer making a payment will be able to say “one hundred dollars” as opposed to pressing “100” on 5

a telephone; for dates, customers will be able to say “March 25th” versus inputting “0325.” 6

Additionally, ASR can enable the collection of non-numeric information, such as email addresses or 7

home area network device identifiers, that are necessary to enroll customers in programs and notification 8

services. 9

The TTS provides customers audio content on demand without the 10

need to pre-record all content. For example, currently when identifying a customer during an outbound 11

collection call, the customer’s last name or business name is spelled out in the voice recording. With 12

TTS, the customer would be provided a text-to-speech-generated prompt of the customer/business name. 13

This allows for personalization of the customer interaction and improves the professionalism for on-14

demand speech. This ease of use will assist customers to embrace and more fully utilize our self-service 15

offerings to obtain the productivity savings forecast from the CCC in this rate case. Additionally, when 16

obtaining a customer’s service address through the ASR functionality, TTS would be necessary to 17

confirm accuracy and validate the customer’s identity. This is important for customer authentication 18

and privacy protection to ensure the appropriate action is taken on the customer’s account. 19

The ASR capability is an industry standard for telephony self-20

service technology. SCE must invest in ASR to meet customer expectations now and in the future. 21

PG&E, San Diego Gas & Electric, and Southern California Gas Company have all confirmed their use 22

or pending deployment of ASR.137 The ASR and TTS project is a key enabler to encourage the 23

utilization of self-service and low cost features. 24

(b) Project Cost 25

The forecast capitalized software cost of this project is $5.0 26

million. 27

(c) Implementation Schedule 28

This work will be done in 2014. 29

137 Based on verbal discussions with Contact Center personnel from both companies.

132

(2) Alerts and Notification System 1

(a) Scope 2

At present, Customer Service uses a number of disparate systems 3

to generate notifications and alerts to customers for planned outages, Demand Response events, Medical 4

Baseline outage notifications, etc. These separate systems are not optimized for efficiency and make it 5

difficult for SCE and customers to make contact preference changes. This new solution integrates with 6

CRM, which will house and be a single source of data for all customer information, including contact 7

preferences. This system will have a single engine to control all event triggers, or business rules. It will 8

manage the communication of all types of alerts and notifications appropriate for a specific customer, 9

along with the customer’s preferred communication channel. 10

The current as-is state is shown in Figure VI-5 below. All of these 11

systems feed into the Varolii system for sending the alert or notification. Many of these systems depend 12

on manual feed to connect to the current version of Varolii. There is no “traffic control,” and it is 13

possible that conflicting messages may go out to a customer simultaneously. Each of these systems 14

provides its own message channel request. 15

133

Figure VI-5 Current Alerts & Notification Architecture

The proposed configuration for the Alerts and Notification system 1

is shown below in Figure VI-6. 2

134

Figure VI-6 Proposed Alerts & Notification Architecture

Within the CRM database, customers can identify what channel 1

they want SCE to use for each type of alert or notification. For example, a customer may want to 2

receive a notification that his bill is ready through an email, but, for a planned outage, he may prefer to 3

receive a text message on his smart phone. This system will couple the type of alert or notification with 4

the customer’s preference. The feed from various systems will be electronic, thereby eliminating 5

manual feeds. The Business Rules logic will determine how the alert or notification will be sent. 6

This program will promote accurate, timely, non-redundant 7

communication to all SCE customers, government agencies, and business partners. Through 8

implementation of standardized infrastructure, this new technological solution will manage electronic 9

communications through multiple channels in a more efficient and cost-effective manner. 10

135

This program also includes specific scope to develop and maintain 1

a centralized repository to capture customer “Do Not Contact” preferences for meeting “Do Not Call” 2

requirements set forth in various Federal statutes.138 This program will ensure and streamline SCE’s 3

compliance with these laws and will address concerns from customers who submit requests to not be 4

contacted. 5

This new system will offer, among other things, the following 6

high-level system capabilities: 7

Program enrollment, 8

Viewing and maintenance of customer contact information and 9

preferences, 10

Outbound and inbound communications, 11

One-way (outbound communication to customers with a 12

system response to confirm delivery), 13

Two-way (customer response to outbound communication by 14

performing a transaction), 15

Reporting and analytics, and 16

Single source of customer contact data. 17

CS is seeking to replace or upgrade the Varolii Application 18

Programming Interface (API) Express, which requires manual analysis, formatting, and editing of 19

customer contact data, which is then manually uploaded in special files to the vendor. This current 20

solution impedes SCE’s ability to deliver timely, accurate, and non-redundant communication to 21

customers. SCE’s goal is to implement a solution that integrates with SCE’s new single-source 22

architecture, and allows regular, automated synch-ups of the contact database with SCE’s master files. 23

(b) Project Cost 24

The forecast capitalized software cost for this project is $10.2 25

million. 26

138 Mobile Marketing association and Direct Marketing Association Code of Conduct, California’s Shine the Light Law,

FCC Telephone Consumer Protection Act, Telemarketing and Consumer Fraud and Abuse Prevention Act, CAN SPAM Act.

136


The work will be performed over a two-year period from 2014- 2

2015. 3

(3) Outage Communication System 4

In Exhibit SCE-04 Vol. 1, Mr. Furukawa presents the Customer 5

Engagement Model for interacting with our customers. He describes three key components of that 6

model: (1) energy solutions, (2) intelligent delivery and energy advisory services, and (3) effective and 7

enabling customer interactions. As an example of the third component he describes changes to our 8

outage communications to better interact with customers prior to and during outages. The Outage 9

Communication System described in this section builds upon those changes through integration with the 10

other systems contained within the Digital Experience Program. 11

The scope of this project can be categorized in three general areas. (1) 12

Public Safety Interactions, Communication & Reporting, (2) Customer Satisfaction & Feedback, and (3) 13

Outage Tracking. 14

(a) Scope 15

(i) Public Safety Interactions, Communication & 16

Reporting 17

Public safety is always the most important concern for all 18

SCE employees. Yet in many situations we are unable to reach customers to provide them with outage 19

information and in particular to communicate potentially hazardous or unsafe conditions. Through the 20

use of multiple communication channel options and by providing customers the opportunity to select 21

which channels they would prefer for outage type communications, we will be able to more rapidly and 22

effectively provide them information they may need to remain clear of potential hazards. Two–way 23

communications will also be provided via texting/SMS channels and other channel options will be 24

investigated as well. This outage information will automatically be available for broader 25

communication across multiple communication channels to affected customers. 26

This project will also make improvements in the “Report an 27

Outage” application to enable customers to provide photos from their smartphone or PDA device of 28

damage directly to SCE which can be utilized by Outage Communication Centers and planners to ensure 29

crews are promptly dispatched for repairs. 30

137

Another aspect of this work is to be able to communicate, 1

information sent from the Customer’s smart meter, informing them their home or business is without 2

power. For example if a customer is away from home and receives a notification via their pre-selected 3

channel, they can check the online or mobile Outage applications to determine the expected duration and 4

mitigating plans. 5

(ii) Customer Satisfaction & Feedback 6

One gap in SCE’s current outage management programs is 7

the ability to gather customer feedback on experiences and satisfaction immediately after a planned or 8

unplanned outage across all channels of communication. This scope of work will provide the 9

mechanism to acquire customer feedback through whatever channel a customer chooses. This feedback 10

will then be collected, analyzed and used to provide continuous and immediate improvement. More 11

importantly, the immediate feedback loop can identify lingering outage or public safety impacts in a 12

timely manner for SCE to act upon. 13

A Data Mart139 for Service Quality metrics will be setup in 14

the Customer Data Warehouse (CDW) and this Outage Communication project will develop and collect 15

the data elements by capturing the data in the work process. Benefits of capturing this information 16

includes, (1) service quality metrics housed in a centralized location to help manage customer 17

satisfaction, (2) Ad Hoc queries of the data for analysis will be readily available, (3) Routine 18

weekly/monthly/YTD reports will be generated to measure performance at various levels within the 19

organization, and (4) data is exportable. 20

(iii) Outage Tracking 21

Once an outage is identified (either planned or unplanned), 22

a Trouble Ticket is generated. In the scope of this project is the development of a mobile tracking 23

solution so the status of any outage can be updated and the information will be available in real-time to 24

the Outage App, and to the Outage Map application on SCE.com so customers can inquire if an outage 25

is still active, and if not active, when the power was restored, and how long the power was out. 26

Enhancements will also be made to include information on rotating outages, so that the map in SCE.com 27

will have more information available to the customer on the map view. 28

139 Data Mart capability is part of the Customer Data Warehouse project which is a part of the Digital Experience Program.

138

(b) Summary 1

The overall objective of this project is to improve communication 2

to customers before and during outages, through the automation, enhancements and/or integrations with 3

the existing systems. The above-identified capabilities are the highest priority areas to improve public 4

safety, improve communication with our customers, and to improve visibility to outage work. As the 5

design of the Digital Experience Program progresses, this work will need to be done in alignment with 6

the overall Alerts & Notification project and the Customer Data Warehouse. The integration aspects are 7

key to achieving the objectives set forth in the Customer Engagement Model. 8

(c) Project Cost 9

The forecast capitalized software cost for this project is $9.6 10

million. 11

(d) Implementation Schedule 12

This work will be implemented over two years from 2015-2016. 13

(4) Build Out the Customer Data Warehouse 14

(a) Scope 15

(i) Customer Analytics 16

SCE has recognized a growing need for integrated, 17

consistent, and timely data from many sources for reporting and analysis purposes. The ability to 18

perform timely customer analytics is critical to achieving benefits from the Digital Experience Program. 19

Having ready access to customer information to give a 360-degree view of the customer to tailor specific 20

products and services to each customer advances public policy objectives. Using this data, our analysts 21

will know what products and services the customer already has and, by analyzing usage patterns, climate 22

effects, and other data, will be able to recommend next best options for managing energy usage. With 23

this type of data, lifestyle packages aimed at customer segments can be provided through all channels, 24

and energy efficiency offers can be presented to those customer segments with the highest likelihood of 25

adoption. 26

There is also a need to have online access to historical data 27

(i.e., more than three years old) for analysis purposes. In order to study the long-term usage patterns of 28

similarly situated customers to determine the program or rate to offer, easy access to historical data will 29

be required. Today, CS relies on IT programming to create or modify reports to meet this need. This 30

process takes time, extends the offer management cycle time, and limits the amount of analysis that can 31

139

be completed. Given the multiple business functions and groups requiring the same data, this is an 1

opportunity to provide consolidated and consistent data from multiple sources to perform analysis and 2

reporting. 3

(ii) Operations optimization 4

Operations optimization allows SCE to maintain a 5

continuous process of analysis, forecast, plan refinement, and action within the operational activities of 6

the company using customer analytics in the decision-making process. Typical undertakings that benefit 7

from having efficient access to customer data include analysis of fraud risks, investigative activities for 8

energy theft, and marketing promotion analytics for DSM and income qualified programs. 9

(iii) Data Foundation and Governance 10

To effectively build, maintain, and use customer data 11

across the company a framework for information governance is needed to monitor and control the use of 12

data. This governance will provide the proper controls and ownership of data. 13

(b) Proposed Approach 14

SCE proposes to create a federated data warehouse that takes data 15

elements from multiple data stores — such as the ESC Warehouse, Business Warehouse, Customer 16

Service System, etc. — and allows standard tools for analytics and reporting to be used. Separate 17

tailored data marts can be created as subsets of the federated data warehouse for very specific purposes. 18

For example, SCE could conduct market research or mine data to analyze customer usage patterns by 19

certain demographics. Figure VI-7 below graphically depicts the vision for future Customer Data 20

Warehouse. The type of data needed to repeatedly monitor changes in studies could be house in a 21

separate data mart. Customer characteristics could be housed in separate data marts if that type of data 22

is frequently used. This may include customer address history, payment options, energy audit results, 23

program enrollment history, energy usage patterns, to name a few. 24

(c) Project Cost 25

The forecast capitalized software cost of this project is $28.0 26

million. 27

(d) Implementation Schedule 28

This project will be implemented over two years from 20152016. 29

140

(5) SCE.com/Customer Service Relationship (CRM) Integration 1

(a) Scope 2

In support of providing basic customer service as defined above, 3

SCE will utilize SCE.com as a fully viable self-service channel for many routine customer interactions. 4

By empowering customers to complete more transactions on the web, SCE seeks to reduce the number 5

of routine transactions through the CCC so that Customer Service Representatives (CSRs) can meet the 6

anticipated need for consultative interactions with customers on new and more complex technologies 7

and rates. 8

The SCE.com/CRM Integration project will provide key 9

components of offer management (i.e., using customer data to determine appropriate personalized 10

programs and products to offer SCE customers);140 enhance community outreach and improve 11

promotion of programs to customers via content and application syndication, and expand self-service 12

options and enrollments via back-office automation, program(s) migration to CRM. This project has 13

four areas of focus: 14

Develop Offer Management Capabilities – Provide the ability 15

to make offers to customers of SCE programs and services 16

based on their profiles and other data stored in CRM and data 17

warehouses. This will use customer data to determine 18

appropriate programs and products to offer SCE customers. 19

SCE.com, IVR, and the CCC are channels that will be used to 20

push tailored offers for products and services to customers. 21

Expansion of Self-Service Capabilities – Implement a Business 22

Rules Management System (BRMS) to enable multiple 23

channels to access business rules from a central system. 24

Performance will be optimized because business rules from 25

multiple systems will be consolidated and centralized. 26

Program Enrollments – Migrate additional programs to CRM 27

and integrate CRM with SCE.com, allowing customers to 28

enroll in select products and services. Provide SCE.com back-29

140 See SCE-04, Vol. 2, Ch. VIII.

141

office automation for enrollments in selected programs that 1

align with Customer Service approaches. Improve integration 2

between CRM and Customer Service System (CSS) by 3

migrating existing data from CSS (except meter data) to CRM 4

and capture new customer device, product, and service data in 5

CRM. This data will enhance SCE’s ability to define the rules 6

for an appropriate offer so that the offer is the best for that 7

specific customer at that time. 8

Enable Community Outreach/Program Promotion – Use 9

content and application syndication to offer SCE applications 10

to business partners and integrate the applications (complete 11

with all features) into their websites. As a result multiple 12

business partners’ will be provided with common SCE web 13

applications. This outreach tool can be used to funnel SCE 14

product information to third-party sites and ultimately to SCE 15

customers. 16

(b) Program Cost 17

The forecast capitalized software cost of this program is $38.7 18

million. 19


The work will be spread over two years from 2016-2017. 21

c) Digital Experience Overall Project Schedule 22

The projects that comprise the Digital Experience Program are staggered over the 23

period of 2014-2017. Figure VI-7 below shows the start and end dates of the Projects and the overlap 24

and sequencing of this work. The Digital Experience program will begin in 2014 with the Advanced 25

Speech Recognition (ASR) and Text To Speech (TTS) upgrade work and the required implementation of 26

the Do Not Contact feature in the Alerts & Notification System. This will be followed by the build-out 27

of the balance of the Alerts & Notification system in 2015 and work on the Outage Communication 28

Project and the Customer Data Warehouse in 2015 and 2016. SCE.com/CRM Integration will occur in 29

2016-2017 and will be the final piece to complete the Digital Experience Program. 30

142

Figure VI-7 Digital Experience Program Implementation Schedule

Project 2014 2015 2016 2017

IVR (ASR & TTS) X

Alerts & Notifications X X

Outage Communication X X

Customer Data Warehouse X X

SCE.com/CRM Integration X X

d) Cost-Benefit Analysis 1

SCE has implemented a company-wide prioritization method for assessing 2

capitalized software projects based upon strategic goals such as, safety, efficiency, and cost-effective 3

operations. Based on this prioritization method, this project is designated as a non-grid economic 4

project.141 As described in the opening section of this testimony, the Digital Experience Program 5

provides benefits in three areas: Advancing Public Policy, Increasing Customer Value, and Improving 6

Operational Efficiencies. The operational benefits result in a benefit to cost ratio of 1.96.142 The timing 7

of the costs of the project and the timing of the Digital Experience Program are shown in the chart 8

below. The shaded area indicates post-implementation when the program is delivering benefits. The 9

majority of hard benefits are delivered beginning in 2017, as illustrated in Figure VI-8 below. 10

141 See SCE-05, Vol. 1, Ch. I; and workpapers in the same volume entitled “Project Approval Process.”

142 See workpapers entitled “Cost-Benefit Analysis for Digital Experience.”

143

Figure VI-8 Cost and Timing of Benefits – Digital Experience Capital Software Projects

(Nominal $ in Millions)

For the Digital Experience Program capital software cost-benefit analysis, 1

the costs of construction and incremental O&M post-implementation were compared against up to five 2

years of benefits post-implementation. For this analysis, all future costs and benefits were escalated to 3

year-of-expenditure, then discounted to 2012 NPV using a 10 percent discount rate. Finally, the sum of 4

present-value benefits was divided by the sum of present-value costs to derive the Benefit-Cost ratio for 5

the project. Because of the construction period required for the individual software capital projects 6

(including the integration that must be built) and the ensuing five-year benefit window, substantial 7

benefits will accrue after 2017, which are not reflected in this GRC. Benefits between 2018-2020 will 8

be reflected in SCE’s next 2018 GRC Test Year. 9

e) Operational Benefits 10

There are two types of operational benefits: reduced costs and avoided costs. 11

Hard benefits produce cost savings to the operation when compared to the base 12

case, which represents organic self-service/DSM enrollment growth without the Digital Experience 13

capital investment. The ASR & TTS project is the first to deliver benefits which starts in 2015 and 14

continues through 2020. The forecast cost savings for 2015 is reflected in the O&M testimony in 15

Exhibit SCE 04, Vol. 2 and is equivalent to a reduction of approximately 68 positions.143 The balance of 16

the cost savings starts in 2016 and ramps up in 2017-2020. Once the program is complete and all 17

143 See SCE-04, Vol. 2, Ch. V.

144

projects are fully implemented, the full forecast benefits will be achieved. Table VI-46 below, shows 1

the Transaction Type, the expected start of benefits for each, and the assumptions made to determine the 2

expected cost saving benefit extended to the year 2020. These benefits are derived based on the 3

resultant integration of information, delivering and sharing the same customer information across all 4

channels of communications and interactions to support customers expanded use of digital technologies 5

for transacting business with SCE. 6

Table VI-46 Digital Experience Program Cost Savings Benefit Assumptions

(less ASR & TTS Project)

Transaction Type Benefit Description

Year

Benefits

Begin Metric Description 2012

2020 Base

Case

Projection

2020 Cap

Software

Projection

Online Billing Transactions Postage/paper savings 2017 Self Service % 18% 41% 60%

Turn On/Off/Transfer Transactions CCC deflection to SS 2017 Self Service % 21% 37% 60%

Home Energy Efficiency Rebates* PSO deflection to SS 2018 Enrollees ‐ 70,335 116,000

Billing Inquiry Transactions CCC call reductions 2018 Call Deflection % ‐ ‐ 21.5%

First Call Resolution (Total CCO Calls) CCC call reductions 2018 First Call Resolution 80% 80% 86.6%

Payment Arrangement/Extension CCC deflection to SS 2017 Self Service % 25% 49% 60%

Outage Transactions CCC deflection to SS 2016 Self Service % 57% 73% 81%

TOTAL

*HEER benefits are non‐O&M, non‐GRC

Key Metric

Avoided Costs are costs that will likely occur if we do not implement the full 7

Digital Experience Program. In particular, there is substantial risk associated with failure to comply 8

with Federal and State privacy laws dealing with electronic communications.144 Based on lawsuits both 9

pending and settled, fines of several million dollars have been levied on major companies.145 We 10

estimated that in 2015 about 70.5 million emails, alerts and notifications will be sent to customers. The 11

financial risk to SCE of not implementing the Digital Experience Program has been estimated at $11.7 12

million in 2015 and increasing to nearly $24.0 million in 2020 as customers increase their use of digital 13

144 FCC 47 CFR Telephone Consumer Act of 1991; California Business & Professional Code Div.7, Part 3, Ch 1; Public

Law 108-187 108th Congress – To regulate interstate commerce by improving limitations and penalties on the transmission of unsolicited commercial electronic mail via the internet.

145 Class Actions for CAN SPAM, text and robo calling:Wells Fargo Text Message Class Action Lawsuit - $17.1M Settlement; LuckyBrand Spam Texts Class Action Lawsuit – $9.9M, Settlement – November 28, 2012; Google Slide Disco Test Class Action Lawsuit – $6M, Settlement – December 19, 2012; Target Spam Class Action Filed – no settlement; Papa John’s Class Action Filed - $250M, (pending) – November 14, 2012; AllianceOne Robocalls and Auto Dialer Settlement - $9.9M – May 2012 (The company is now facing a text messaging lawsuit).

145

channels to conduct business with SCE. This estimate is based on assuming $500 per incident and a 1

three percent risk of occurrence both of which were based on Wells Fargo and other companies’ 2

experience. 3

Full Investment will yield benefits by 2020, which are displayed on the Figure VI-4

9 below. These benefits, when compared to the cost to implement the Digital Experience Program, yield 5

a benefit cost ratio of 1.96. This benefit is further enhanced by the advancement of public policy in 6

meeting the State’s Energy Action Plans goals by increasing the expected enrollments in various DSM 7

programs. Customer Value is improved substantially by opening multiple channels for communication 8

both by the customer and by SCE. 9

Figure VI-9 Full Investment Yields Hard Benefits by 2020

f) Recorded and Forecast Expenditures 10

Labor, hardware, licensing and contingency costs comprise the forecast 11

capitalized software costs of $91.5 million for the Digital Experience Program.146 Estimates for IT 12

support are based upon prior experience in initial implementation of system upgrades. Various types of 13

146 See workpaper entitled “Forecast Expenditures Digital Experience.”

146

developmental or commercial off-the-shelf (COTS) projects, labor rates, contingency levels, and cost 1

components are utilized to develop the overall cost estimate of the project.147 2

g) Conclusion 3

The Digital Experience Program is a continuation of the strategy that was first 4

described in the 2012 GRC Policy testimony and supports the current Customer Engagement Model 5

discussed in Exhibit SCE-04, Vol. 1. Initial implementation of SCE.com has laid the technological 6

foundation for a digital experience that will meet customers’ growing needs. Channel parity will 7

improve customers’ interaction with SCE and enable SCE to provide personalized basic customer 8

service. This development and implementation will produce economic and non-economic benefits to 9

our customers. 10

6. Prepayment Program 11

a) Background 12


The Prepayment Program will allow residential customers the option of 14

paying for their electric use prior to consuming it. This pay-as-you-go concept allows customers to 15

make multiple payments throughout each month to maintain a prepay balance used to pay for electricity 16

as it is consumed. Customers benefit by not being required to pay a deposit when establishing service, 17

and they are not tied to a monthly bill due date. 18

With the implementation of Edison SmartConnect®, SCE is able to offer 19

customers a program that allows them to better manage their energy use and personal finances. With the 20

Remote Service Switch (RSS), SCE can turn customers on or off easily without the need to send an FSR 21

into the field. SCE’s Prepayment Program will be available to Edison SmartConnect®-metered 22

residential customers with RSS capability. See Exhibit SCE-04, Vol. 2, Ch. IV.A, pp. 115-120, for 23

further details on the Prepayment Program. 24

(2) Scope 25

To facilitate customer participation in the Prepayment Program, system 26

enhancements are necessary to enable verification of eligibility, online customer enrollment, web 27

presentment of account status and usage, customer payment management, and alerts and notifications. 28

Additional integration is required to automate the operational processes affected by the Prepayment 29



147

Program such as connect and/or disconnect of service. The systems within scope for this project are as 1

follows: 2

Customer Call Work Optimization (CWO) and CSS Workstation – Create a prepayment 3

enrollment/de-enrollment screen and create a detail screen showing all prepayment events and 4

balances for use by the Customer Service Representative (CSR) handling customer inquiries, to 5

verify eligibility and process enrollments. 6

Customer Service System (CSS) – Create prepayment service modules to accept enrollment from 7

the workstations and Interactive Voice Response (IVR) system and pull information from Budget 8

Assistant data (i.e., Bill to Date, Daily Average). 9

Dispatcher – Modify Service Order dispatchers for the following: 10

o Cancel pending prepayment enrollment, and 11

o Change the prepayment enrollment event status upon completion. 12

Database Changes – Create a back-end table to store prepayment data (e.g., minimum transaction 13

amount, low balance amount, and de-enrollment). 14

Front End/Back End Static Data Changes – Define new event types, eligible prepayment rates, 15

and ineligible profile. 16

Payment Channels – Current payment channels will be available to accept payment (e.g., APA, 17

EDI, SCE.com, credit/debit, or mail). 18

Account Receivable & Collection – The system will allow for multiple payments, accept triggers 19

for alerts to notify customers that payments have been received, and trigger disconnect alerts 20

when balances fall below requirements. 21

Alerts and Notifications – Add new templates for each alert and notification in Varolii for 22

enrollments, payments, low balance, disconnection alert, etc. 23

SCE.com – Existing interface between Varolii and CSS will be used for notifications and alerts; 24

all CSS service interactions will be managed through the software product Datapower; and all 25

CSS transactions that require interaction with SCE.com, CWO, and IVR will be a web service. 26

Within MyAccount, existing web presentment of bill to date, usage, and account status will be 27

changed for those customers on the Prepayment Program, and enrollment via SCE.com will be 28

offered. 29

148


The Prepayment Program implementation is scheduled to start in 2014 and 2

end by 2015. 3


This is a new payment program being requested in this rate case. There are no 5

current systems or processes. See Exhibit SCE-04, Vol. 2, Ch. IV, pp. 115-120, for further details on the 6

Prepayment Program. 7


An alternative to automating the prepayment program is to have the CSR 9

in the Customer Contact Center (CCC) manually enroll all customers electing this option. Even the 10

manual process would require some system automation, as this is not an existing payment program. The 11

cost-benefit analysis below in Section (2) illustrates why automating this process will have a positive 12

Net Present Value (NPV). 13

Another feasible option for automating this payment program would be to 14

use a vendor COTS. 15


For the capital software cost-benefit analysis, the costs of construction and 17

any incremental O&M post-implementation were compared against up to five years of benefits post-18

implementation. For this analysis, all future costs and benefits were escalated to year-of-expenditure, 19

then discounted to 2012 NPV using a 10 percent discount rate. Finally, the sum of present-value 20

benefits was divided by the sum of present-value costs to derive the Benefit-Cost ratio for the project. 21

Because of the construction period required for software capital projects and the ensuing five-year 22

benefit window, many projects have substantial benefits after 2017, which are not reflected in this GRC; 23

benefits between 2018-2020 will be reflected in SCE's next 2018 Test Year GRC through avoided costs. 24

A cost-benefit analysis was performed to determine if the automation project would be more cost-25

effective than performing the work manually. The benefits incurred from automating this project 26

include reducing the bad debt (uncollectible) expense, reducing postage costs, and reducing energy 27

procurement costs. The analysis indicates a positive Benefit-Cost Ratio of 1.11 where the benefits are 28

associated with the Prepayment program and not the automation of the system.148 29

148 See workpaper entitled “Cost-Benefit Analysis for Prepayment Program.”

149


The forecast capitalized software costs of $1.6 million for the Prepayment 2

Program project is comprised of labor, hardware, licensing and contingency costs.149 Estimates for IT 3

support are based upon prior experience with similar projects. Based upon various types of 4

developmental or COTS projects, labor rates, contingency levels, and cost components are utilized to 5

develop the overall cost estimate of the project.150 This project is expected to be of medium complexity 6

and an internally developed solution based on IT’s estimating method. 7

Table VI-47 below illustrates the forecast expenditures of the Prepayment 8

Program project by year. 9

Table VI-47 Capital Forecast Expenditures for the Prepayment Program Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ 1.6$ -$ -$ -$ 1.6$

d) Conclusion 10

The Prepayment Program will allow eligible customers to pay in advance for 11

anticipated energy consumption. This will allow customers to make multiple payments throughout each 12

month to maintain a prepayment balance that is used to pay for energy as it is consumed. By SCE 13

automating this new offering, customers will be able to determine their eligibility, enroll in the 14

Prepayment Program, receive alerts and notifications, and manage their payment plan. 15

7. GRC Rate Design Phase II 16

a) Background 17


At the conclusion of each General Rate Case, new rates are developed in 19

Phase II of the GRC to be implemented in SCE’s billing system. These new rates result from the 20

changes in rate design developed in Phase II of the GRC. The purpose of this project is to modify 21

various systems, including the billing systems in order to implement these new rates, and the project is 22

required to be completed for a 2015 Test Year implementation. 23

149 See workpaper entitled “Forecast Expenditures for Prepayment Program.”

150 See SCE-05, Vol. 1, Ch. II; and workpapers in the same volume entitled “2015 GRC IT Capital Estimates TEMPLATE v1.doc” and “GRC Estimation Worksheet TEMPLATE v1.1.xls.”

150

(2) Scope 1

Because the exact scope of this project will not be determined until the 2

conclusion of the 2015 GRC Phase II, the preliminary basis for the project scope is based upon the 3

Residential Rate Structure OIR R.12-06-013 (Filed June 21, 2012), the Rate Design Workshop for R.12-4

06-013 (Held December 5, 2012), and the 2012 GRC Phase 2 (A.11-06-007) Final Decision D.13-03-5

031. These provide for several rate design options, including: 6

Tiered Rates, which set rate levels relative to some baseline volumetric 7

usage; 8

Non-Volumetric Charges, such as fixed customer charges, basic 9

service fees and minimum bill charges, and demand charges; 10

Time-of-Use (TOU) Rates setting different rate levels depending upon 11

the time period during which energy is used; 12

California Alternate Rates for Energy (CARE) Program, an alternative 13

mechanism for providing assistance for low-income customers; 14

Small Commercial and Agricultural customers’ further transition to 15

default Critical Peak Pricing (CPP) rates, beginning January 1, 2016, 16

two years after the January 1, 2014 transition to mandatory TOU 17

service; and 18

Rate elimination. 19

Each of these areas has complex options that will need to be designed and 20

implemented. Based on prior rate design efforts and the extent of changes anticipated, this effort will 21

require intensive systems and user testing, as well as challenging regression testing, to ensure the scope, 22

is implemented and ready for live operation. 23


The General Rate Case Plan calls for new rates to be decided in Phase II 25

of each rate case and those new rates to be implemented in the Test Year of each case. Rates must be 26

implemented as proposed by SCE or as ordered by the Commission. The final 2015 GRC Phase II 27

application will be filed in February 2014 with the IT project initiation beginning in April of that same 28

year. The final decision is expected in August 2015 with the new rates becoming effective October 1, 29

2015. 30

151



The Level 2 Customer Organization processes principally affect two areas: 3

Manage Customer Relationships and Bill for Products and Services. The capabilities that affect how we 4

manage customer relationship changes include customer self-service, customer care, and customer 5

information exchange and education. Bill for Products and Services affects how SCE manages and 6

processes rate changes, performs bill computations and generations, and manages the process of billing 7

work. 8

Current systems that will be affected include Customer Service System 9

(CSS), SCE.com, Customer Data Acquisition System (CDAS), Meter Data Management System 10

(MDMS), and the Call Work Optimization (CWO) used by the CCC. 11


Due to the system infrastructure and the necessity of customer 13

confidentiality, an external solution is not possible. SCE must develop the changes to the system to 14

accommodate the rates approved in Phase II of the 2015 GRC. 15


This project includes implementing mandated rate schedules resulting 17

from the decision of this 2015 GRC. Therefore, the decision to undertake the project cannot be 18

appropriately analyzed using a cost-benefit analysis. The project will not create any incremental O&M. 19

The rates within the system will be updated according to the Commission’s Decision. The least-cost 20

option will be pursued. 21


The forecast capitalized software costs of $6.5 million for the GRC Rate Design 23

Phase II project is comprised of labor, systems hardware, licensing and contingency costs.151 Estimates 24

for IT support are based upon prior experience with similar types of projects. Based upon various types 25

of developmental or COTS projects, labor rates, contingency levels, and cost components are utilized to 26

develop the overall cost estimate of the project.152 The work necessary for the modifications to the 27

systems will be considered a small developmental project based on IT’s estimating method. 28

151 See workpaper entitled “Forecast Expenditures GRC Rate Design Phase II.”


152

Table VI-48 below illustrates the forecast expenditures of the GRC Rate Design 1

Phase II project by year. 2

Table VI-48 Capital Forecast Expenditures for the General Rate Design Phase II Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ 6.5$ -$ -$ 6.5$

d) Conclusion 3

Phase II of the General Rate Case process generates new rates, the 4

implementation of which are required by the Commission. SCE is required to implement these new 5

rates on customer’s bills for the Test Year 2015. These new rates are required as a result of the changes 6

in rate design developed in Phase II of the GRC. The purpose of this project is to modify the billing 7

system implementing these new rates. This project is required to implement the new rates for the 2015 8

Test Year. 9

8. Enhanced Metering and Usage 10

a) Background 11


Edison SmartConnect® relies on Commercial-Off-The-Shelf (COTS) 13

products from the vendor for meter data collection using the Network Management System (NMS), and 14

the Meter Data Management System (MDMS) for managing metering data. The vendor’s products are 15

critical infrastructure components for the SCE-integrated systems, and SCE has a contractual obligation 16

to maintain the software within the latest two release versions to preserve vendor support of the system 17

and devices. These commercial products are enhanced and upgraded by the vendor on a regular basis 18

(12-18 month cycle). These updates are driven from the vendor. Because the system and the process 19

are new technology and COTS, enhancements will occur more frequently than standard. Once the 20

system is in steady state, the duration between upgrades will become longer. This is a common way for 21

software vendors to upgrade their systems as new offerings are developed, improvements in the speed 22

and efficiency of managing data are developed, and problems identified since the previous upgrade are 23

fixed. The new enhancement packages are available to SCE via its licensing agreements with the 24

vendor. These software upgrades will include NMS and MDMS improvements. 25

153

The NMS is the gateway to all Edison SmartConnect® meters and field 1

infrastructure. All commands sent to, and all data received from, the Edison SmartConnect® meters and 2

communications systems must pass through the NMS. The NMS includes three subcomponents: the 3

head-end component to communicate with the meter; the network management console to optimize and 4

manage the individual meters and the network infrastructure together, and the encrypting service to 5

secure the data and communications of the entire network. 6

The MDMS is the repository for the meter and event data collected from 7

the Edison SmartConnect® meters. In addition, the MDMS provides the validation, editing and 8

estimating necessary to support customer usage calculations necessary to generate an accurate bill. The 9

MDMS also receives and routes all messages from the meter population to the appropriate SCE systems. 10

This includes meter events received from the NMS, for meter failures, power outages, tamper events, 11

demand response messages, service switch operation, as well as messages received from HAN devices. 12

(2) Scope 13

As stated above, there are two primary systems scheduled for upgrade as 14

part of this project. The upgrade to the MDMS will involve planning, configuration, testing and 15

deployment. The release is expected to include new enhancements and newly resolved issues as well as 16

enhancements from previous service pack releases. The vendor’s professional services, such as 17

engineering support, will be required to configure the system. The following scope is based on the Itron 18

Enterprise Edition (IEE) version 8.1 Release Roadmap, and includes; 19

Data Import and Integration Enhancements, 20

Data Quality Assurance, 21

IEE 8.1 Aggregation Enhancements, 22

Data Distribution Enhancements, and 23

Platform Enhancements. 24

The NMS, the second system being upgraded, is critical for SCE to remain 25

current on the ITRON NMS (Itron Network Management System) product releases to take advantage of 26

new functionality and to continue to improve overall performance of the Meter and Communications 27

System. 28

This request is for an NMS upgrade and the costs associated with 29

planning, testing and deploying the most current commercially available release in a manner that 30

prevents negative impacts to the back-end systems or the 5 million meters that the SOC will update over 31

154

the air. Upgrading the NMS to the most current commercially available release will empower SCE to do 1

the following: 2

Remain current with the latest vendor firmware and utilize new 3

functionality, 4

Enable meter functionality required to support HAN with Load 5

Control, and 6

Reduce known NMS User Interface performance issues, which can 7

increase with system load. 8


There is a significant operating impact to the business in upgrading this 10

software. Releases of MDMS and NMS will be carefully planned and coordinated in order to obtain 11

economies of scale through the testing process. 12

Of the two upgrades to be completed as part of the Enhanced Metering 13

and Usage Capabilities, the first phase is scheduled to be implemented in 2014, and the second is 14

scheduled to be implemented in 2016. Each of these package upgrades will include pre-engineering to 15

identify the detailed scope, schedule, and budget. The projects will be reviewed on a regular basis at 16

project status meetings for adherence with scope, schedule, budget, and technical objectives. CSOU 17

standard project management tools and techniques will be used to manage these projects. 18



The Edison SmartConnect® program made significant investments to 21

ensure that critical needs were addressed in the versions of the products implemented, but important 22

areas of functionality will continue to evolve as the Advanced Metering Infrastructure (AMI) market 23

matures. These investments include security updates, network improvements, internet protocols, service 24

order management, and additional types of demand response billing calculations and reporting. SCE 25

also anticipates the need to include improvements that support future Smart Grid functionality. SCE is 26

committed to being as current as possible with releases of new product functionality and to be no more 27

than two releases away from the current product functionality to ensure technical support is available 28

and trained. This is consistent with SCE’s approach to maintaining large COTS packages. 29

155


If SCE falls more than two product releases behind, SCE will lose product 2

maintenance support. This leads to the risk of technology obsolescence of the Edison SmartConnect® 3

infrastructure and can affect the end-to-end reliability. 4


The objective of this project is to upgrade MDMS and NMS systems such 6

that the Edison SmartConnect® infrastructure is up-to-date and able to serve SCE customers. Therefore, 7

the decision to undertake the project cannot be appropriately analyzed using a cost-benefit analysis. The 8

project will upgrade and include schedule testing for all affected systems (NMS, MDMS, and Teradata) 9

to achieve economies of scale. The upgrade also includes new features SCE has requested. 10


The forecast capitalized software costs of $16.6 million for the Enhanced 12

Metering and Usage project is comprised of labor, systems hardware, licensing and contingency costs.153 13

Estimates for IT support are based upon prior experience with similar kinds of projects. Based upon 14


are utilized to develop the overall cost estimate of the project.154 The upgrade will be a COTS product 16

for both the MDMS and NMS systems. The work needed to modify the systems will be considered a 17

large developmental project based on IT’s estimating method. 18

Table VI-49 below illustrates the forecast expenditures of the Enhanced Metering 19

and Usage project by year. 20

Table VI-49 Capital Forecast Expenditures for the Enhanced Metering and Usage Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ 6.7$ -$ 9.9$ -$ 16.6$

d) Conclusion 21

Edison SmartConnect® relies on COTS products from SCE’s vendor for meter 22

usage data collection from the NMS and the MDMS. To keep the software up-to-date for support and 23

153 See workpaper entitled “Forecast Expenditures Enhanced Metering and Usage.”


156

availability of the latest features, these products require upgrades by the vendor on a regular basis (12-18 1

month cycle). The new enhancement packages are available to SCE via their licensing agreements with 2

the vendor. These enhancements must be made to ensure the reliability of the Meter and 3

Communications System. 4

9. Edison SmartConnect® Monitoring and Analysis System (SCMAS) Phase 2 5

a) Background 6


The Edison SmartConnect® Monitoring and Analysis (SCMAS) was 8

implemented during the Edison SmartConnect® deployment. The SCMAS is used to facilitate the 9

monitoring and analysis of the Meter and Communications System. This project will enhance the 10

SCMAS by implementing requirements that were originally taken out of scope during the Phase 1 11

implementation of SCMAS because of project time constraints, as well as provide upgrades to improve 12

the current system. The SCMAS is the main interface for the Meter and Communications System. It 13

acts as an umbrella for a single point of entry and control for NMS, SEM, CRA, security and 14

visualization. This is illustrated in Figure VI-10 below. 15

157

Figure VI-10 Edison SmartConnect® Monitoring and Analysis (SCMAS) System Diagram

(2) Scope 1

By implementing the additional functionality of the SCMAS Phase II 2

project, the SOC will improve operational efficiency as well as enable functionality required to support 3

the following programs: the HAN program, the Daily Non Responding Devices (NRD) and Radio 4

Frequency (RF) Mitigation, and the Opt-Out program. 5

(a) HAN Program 6

The SOC needs access to HAN data and diagnostic functionality 7

delivered with Network Management System (NMS) to support automated and more timely manual 8

identification and mitigation of HAN-related issues associated with the 200,000 Customers with HAN 9

devices155 (i.e., ability to enable SOC to identify potential issues before they are realized). The SOC 10

will have access to data associated with all accounts with HAN devices by device type and status 11

(registered vs. not registered). Customer and HAN data will be available for the SOC to interrogate and 12

155 See Resolution E-4527, September 27, 2012.

158

identify problems or incidents. The system will provide workflow notifications and minimize the 1

systems needed to track incident and the work management process through to resolution. 2

(b) Daily NRD and RF Mitigation 3

The SOC performs daily identification and mitigation of non-4

responding devices and RF-challenged accounts (customer accounts without a signal). This upgrade 5

will provide for data and functionality required to strengthen analytics necessary to expand monitoring 6

scope and further automate the identification of problems. Today, the SOC manually conducts RF 7

desktop analysis to rule out account-based issues (e.g., no power, no access, Meter Order Processing 8

(MOP), outstanding Basic Work Request (BWR), and outstanding Trouble Orders that cannot be 9

resolved by a field visit). Automating the RF desktop analysis will reduce the significant manual effort 10

and reduce the number of truck rolls (i.e., FSRs and meter technicians being sent out to a location to 11

manually inspect a device), returned devices requiring MSO testing, and “No Trouble Found” results. 12

(c) Remote Re-Programming 13

The SOC will have the functionality to process requests from RSO 14

to perform Over the Air Remote Reprogramming of meters and to interrogate results from within a 15

single tool, SCMAS. Remote reprogramming functionality allows the SOC to change the meter 16

configuration to support various billing programs and the Load Research Program over the air. 17

(d) Opt Out 18

The SOC continuously monitors the impacts of the Opt-Out 19

Program on the overall network performance. The enhancements to the system will provide visibility to 20

all accounts moving out of and back into the Edison SmartConnect® program, transactions, and their 21

statuses to ensure timely remediation of issues. (For more details on the Opt-Out Program, see SCE-04, 22

Vol. 2, Ch. IV.A) As smart meters are removed or added to the network, the SOC will need to analyze 23

the effect of the movement on the network signal. Depending on the location of the analog meter, RF 24

Mitigation actions and solutions may be required (i.e., installation of range extenders, satellite solutions, 25

or pole mounted cell relays). 26


The SCMAS Phase 2 project is scheduled to start and end by 2015. 28

159



The SCMAS system is the main interface used to facilitate the monitoring 3

and analysis of the Edison SmartConnect® Meter and Communications System. It acts as an umbrella 4

for a single point of entry and control for NMS, SEM, CRA, security, and visualization. Currently the 5

process of monitoring the network and transitioning between systems is manual. Significant data reports 6

are maintained to identify threats to the Meter and Communications System. An additional eight 7

positions are required within the SOC to perform analytics and reporting required identifying and 8

mitigating issues. These reports are then analyzed and reviewed for trends. The approach is a very 9

reactive one for monitoring such a complex system. The data must be received, reported on and then 10

analyzed all before the SOC is aware there is a problem with the network. Once a potential problem is 11

identified, manual desktop analysis is conducted; multiple individuals are required to run a series of 12

reports and search CSS to determine if the problem resides in the Meter and Communications System or 13

CSS with synchronization issues. The manual mitigation process can take up to eight hours to 14

determine the source of the problem. The duration varies significantly depending upon the size of the 15

population being analyzed. SOC analyzes between 500 to 1,000 devices per day based on currently 16

defined incidents. This does not include the time to actually fix the problem. 17


An alternative to the systems enhancements described in this section 19

would be to continue with the manual processes performed by the SOC. If SCE is unable to implement 20

these system enhancements, the SOC will need to increase their incremental forecast by approximately 21

eight FTEs. Refer to the next section (3) Cost-Benefit Analysis for support as to why the status quo is 22

not the most beneficial option. 23


This project provides benefits to the department through avoided costs. 25

For the capital software cost-benefit analysis, the costs of construction, and any incremental O&M post-26

implementation, were compared against up to five years of benefits post-implementation. For this 27

analysis, all future costs and benefits were escalated to year-of-expenditure, then discounted to 2012 28

NPV using a 10 percent discount rate. Finally, the sum of present-value benefits was divided by the sum 29

of present-value costs to derive the Benefit-Cost ratio for the project.156 Because of the construction 30

156 See workpapers entitled “Cost-Benefit Analysis for SmartConnect Monitoring and Analysis Systems.”

160

period required for software capital projects, and the ensuing five-year benefit window, many projects 1

have substantial benefits after 2017, which are not reflected in this GRC; benefits between 2018-2020 2

will be reflected in SCE's next (TY 2018) GRC. 3

The Benefit-Cost ratio for the SCMAS project is 0.84. With an additional 4

year of benefits, the Benefit-Cost ratio is greater than one. The avoided costs for the SCMAS project 5

include: 6

Not hiring an additional eight FTEs to run Desktop analytics; 7

Reducing the number of truck rolls, returned devices requiring MSO 8

testing, and No Trouble Found in MSO test through the automation of 9

Non-responding Device Desktop analysis; 10

Timely identification and mitigation of HAN-related issues associated 11

with 200,000 customers with HAN devices to ensure that the customer 12

is able to take advantage of the HAN related programs; 13

Some additional customer benefits not included in the cost-benefit 14

analysis, including faster resolution of customer-reported problems, as 15

well as resolution of problems before customers realize there is an 16

issue; 17

Improved storm response time in correlation with the priority and 18

volume of storm issues; 19

Timely remediation of issues related to Opt-Out and Opt-In 20

transactions; and 21

Reducing the overall number of customer-facing problems and 22

speeding resolution of those issues that customers do report, which 23

will further the state policy goal of faster, more widespread customer 24

adoption of HAN technology and resulting DSM benefits. 25

After the project implementation in 2015 and starting in 2016, we 26

anticipate the benefit will be shown in the net savings in the O&M request (through a reduced forecast) 27

for the corresponding department. 28

161


The forecast cost of $5.1 million for the SCMAS Phase 2 project is comprised of 2

labor, hardware, licensing and contingency costs.157 Estimates for IT support are based upon prior 3

experience with similar projects. Based upon various types of developmental or COTS projects, labor 4

rates, contingency levels, and cost components are utilized to develop the overall cost estimate of the 5

project.158 This project is expected to be a medium complex, internally developed solution. Therefore, 6

the added functionalities will be considered a medium developmental project under IT’s estimating 7

method. 8

Table VI-50 below illustrates the forecast expenditures of the SCMAS Phase II 9

project by year. 10

Table VI-50 Capital Forecast Expenditures for the SCMAS Phase II Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ 5.1$ -$ -$ 5.1$

d) Conclusion 11

The Meter and Communications System will be exposed to higher risks of 12

catastrophic Edison SmartConnect® failure if not implemented. Failures of the system would cause 13

higher delayed billing rates and an increase in field visits to probe the meter and manually capture usage 14

information. Without the additional SCMAS functionality, the SOC would be unable to identify new 15

issues and offer timely analysis, thus increasingly the risk of failure of the interim Edison 16

SmartConnect® analysis platform used for daily non-responding meter analytics and mitigation. 17

10. Hiperwall Refresh 18

a) Background 19


A hiperwall is a video wall display technology consisting of a series of 21

LED devices affixed to a wall and linked together through an ordinary Local Area Network (LAN) or a 22

157 See workpaper entitled “Forecast Expenditures for SmartConnect Monitoring and Analysis System (SCMAS) Project.”


162

wireless network. A hiperwall displays any combination of content types, such as large graphic images 1

or streaming content from a camera or other source. 2

The hiperwall is currently located in the SOC and was installed in October 3

2010. The wall is a visualization tool used to track the performance of SCE’s Advanced Metering 4

Infrastructure (AMI). The hiperwall is used 24 hours a day, 7 days a week for real-time monitoring of 5

SCE’s smart meter security and communication performance. The hiperwall provides for concurrent, 6

real-time access to all the data required to ensure timely identification and resolution of problems 7

affecting the ESC operations. 8

It is vitally important to maintain this display for continuous viewing of 9

the AMI communication system, as this display translates usage information into billing for our five 10

million customers. The hiperwall also has the capability of displaying connectivity related to Home 11

Area Network (HAN) devices and tracking the remote service switch for turn-ons, turn-offs, and credit-12

related activity. The SOC has a partnership role in outage management with the Transmission & 13

Distribution Organization Unit (T&D). Through the hiperwall, the SOC can view voltage and load 14

information on five million devices and is able to determine if a customer is receiving electricity. This 15

information is relayed back to T&D and used to deploy repair resources more effectively. 16

(2) Scope 17

The project will refresh the current hiperwall located in the SOC, as well 18

as any hardware fixes. The project also includes the creation of a maintenance plan with scheduled 19

refreshes and software upgrades to maintain long-term operations. Because the hiperwall is utilized 24 20

hours a day, 7 days a week, any system or hardware update needs to be well planned to minimize the 21

outage time of the hiperwall. The maintenance plan will also include training of SCE’s IT department to 22

maintain the hiperwall. 23

The project will include replacing twenty 46” LED displays with a 5.5mm 24

combined bezel (the distance between the display screens). Each display has an internal windows 25

computer assisting in the visualization. The narrow bezel, or edge, allows the displays to be aligned 26

closely together for the appearance of a smooth continuous surface. Also within the scope of the 27

Hiperwall Refresh, are the 20 individual computers that support the back-end of the hiperwall. Because 28

of the work performed, these computers need to be powerful with large memory and small form factor to 29

fit together within a rack. The hiperwall controller node computer links the 16 different computer 30

applications together for visualization on the wall. Three additional computers are used for AV control, 31

163

playing video or DVDs, or transferring the hiperwall display into conference rooms. No new interfaces 1

will be necessary between the applications and the hiperwall controller. 2

SCE’s IT department will be responsible for the development of a robust 3

maintenance plan that will allow for scheduled refreshes and software upgrades with minimal down- 4

time. SCE’s IT department will also develop processes and undergo training to maintain the hiperwall. 5


The capitalized software component of the Hiperwall Refresh project is 7

scheduled to start in 2015 and end by 2017. 8



The current hiperwall is approximately 8 feet high and 17 feet wide (4 11

displays high and 5 displays wide). An application can be viewed on one display, blown up to be 12

viewed on all 20 displays, or any combination in between. Four SOC operators view the hiperwall 13

concurrently to track and monitor the Meter and Communications System. The LED displays are 14

controlled by a hiperwall controller. The hiperwall controller links several SOC applications together 15

that can then be displayed either individually or concurrently on the LED displays as shown below in 16

Figure VI-11. 17

164

Figure VI-11 Hiperwall Configuration Diagram

The SOC applications that are viewed on the hiperwall include: 1

Security Event Management (SEM) System – This application is used to 2

conduct security monitoring by capturing meter logs and event data and interrogating the data to identify 3

cyber security alerts. The cell relays send encrypted secure text files to the SEM system. SEM reads 4

these files to determine if there was any type of security alert on the system. 5

Edison SmartConnect® Monitoring & Analysis System (SCMAS) – The 6

SCMAS is used to facilitate the monitoring and analysis of the Edison SmartConnect® meter and the 7

communication network. The SCMAS is the main interface for the Meter and Communications system. 8

It acts as an umbrella for a single point of entry and control for NMS, SEM, CRA, security and 9

visualization. 10

165

Cell Relay Configuration Management System (CGM) – CGM ensures 1

configuration management of the new devices. This system is used to push out any needed upgrades to 2

the cell relay devices while they are installed in the field. The upgrade is pushed out over the CGM 3

system through the air and received by the cell relays. 4

Network Management System (NMS) – The NMS is the gateway to all 5

Edison SmartConnect® meters and field infrastructure. All commands sent to and all data received 6

from the Edison SmartConnect® meters and network field infrastructure must pass through the NMS. 7

Cell Relay Availability (CRA) – CRA is used to monitor the over-the-air 8

communication and availability of the 14,000 cell relay cellular data devices. 9

BMC Patrol –This system is used to monitor the Edison SmartConnect® 10

system IT servers for their real time status, health and performance. 11

Outage Management System – This system is used to monitor system 12

power outages for impact to meter and communications operations and provides support to T&D related 13

to power outages and restoration. 14


Due to the necessary flexibility needed to display multiple applications in 16

a variety of configurations, viewable by multiple operators simultaneously, the hiperwall is the only 17

technology solution at this time. 18

The hiperwall is purchased and supported through authorized and 19

approved Audio Video (AV) Integrators only. SCE’s current vendor is an authorized and approved AV 20

Integrator. If SCE were to consider alternate vendors, the cost of replacing the hiperwall would increase 21

as supporting infrastructure (such as the wall and brackets) would need to be removed and replaced by 22

the new vendor. The lowest cost option was to remain with the current vendor. 23

Within the video monitor industry, five years is the standard lifecycle for 24

monitors that operate 24 hours a day, 7 days a week. The same is true for the computers that deliver and 25

control the content of the hiperwall. Because the hiperwall was installed in 2010, it needs to be 26

refreshed in 2015. It is not feasible to allow the hiperwall to extend beyond the five-year lifecycle and 27

to incur additional expenses for repair and maintenance. Over the last six months, the vendor has been 28

called for service three different times. The wall is constantly in use and cannot be down without 29

affecting the metering system operations, system monitoring, and incident identification and resolution 30

processes. 31

166

c) Cost-Benefit Analysis 1

This project is required for SCE to maintain 24- hours- a- day, 7-days- a-week 2

visibility of the Meter Communication System. Therefore, the decision to undertake the project cannot 3

be appropriately analyzed using a cost-benefit analysis. As discussed in the prior section, the lowest 4

cost option will be selected. The project will not create incremental O&M. SCE’s IT department will 5

require training to support the hiperwall and its maintenance plan, but this will be included in regular 6

training time. 7

d) Recorded and Forecast Expenditures 8

The forecast capitalized software costs of $1.9 million for the Hiperwall Refresh 9

project is comprised of labor, systems hardware, licensing and contingency costs.159 The project is 10

divided into two components: the IT software modifications and the hardware, such as the LED 11

monitors. Based upon various types of developmental or COTS projects, labor rates, contingency levels, 12

and cost components are utilized to develop the overall cost estimate of the project.160 The work 13

necessary for the modifications to the systems required for the Hiperwall Refresh project is considered a 14

small developmental project based on IT’s estimating method. The hardware component of the project 15

is based upon vendor quotes and costs for similar equipment procured by SCE. 16

Table VI-51 below illustrates the forecast expenditures of the Hiperwall Refresh 17

project by year. 18

Table VI-51 Capital Forecast Expenditures for the Hiperwall Refresh Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ 1.9$ -$ -$ 1.9$

e) Conclusion 19

SCE relies on the functionality of the hiperwall 24 hours a day, 7 days a week. 20

The visualization wall needs to be refreshed every five years. The Hiperwall Refresh project is 21

necessary to avoid hardware and software obsolescence and to maintain reliability. The wall is used for 22

159 See workpaper entitled “Forecast Expenditures Hiperwall Refresh.”


167

real-time monitoring of SCE’s smart meter security and communication performance of the AMI 1

system. 2

11. Plug-In Electric Vehicle (PEV) Support Systems 3

a) Background 4


As the adoption of light duty Plug-In Electric Vehicles (PEVs) scales,161 6

Customer Service seeks to streamline the process by which customers enroll in dynamic rates for fueling 7

their vehicles. The current semi-manual enrollment process leverages, as much as possible, automation 8

of existing systems to enable customers to charge at their chosen EV rate but still requires significant 9

manual intervention and is not scalable. A more efficient and transparent process is needed to better 10

support SCE’s growing number of PEV customers. This testimony describes the work to streamline and 11

automate the current processes and the systems that will provide one-stop, online service solution for 12

SCE’s PEV customers.162 13

Providing the growing population of PEV customers with reliable service 14

requires coordination among a number of SCE departments, including contact center representatives, 15

electrical service planning, distribution system construction crews, meter services, and billing. Some of 16

SCE’s current work management systems are organization-specific with limited cross-organization 17

integration and few, if any, PEV-specific data fields. This approach was adequate for the original intent 18

of those systems and was manageable, with manual workarounds, for the current volume of PEVs. 19

However, future PEV volume projections dictate that more efficient processing will be required for SCE 20

to meet customer expectations for timeliness, efficiency, and accuracy of order tracking and status 21

reporting. 22

In D.12-11-051, SCE’s 2012 GRC Decision, the Commission stated that, 23

because PEV is integrated with other major technology projects, SCE should “slow down the 24

implementation [of the PEV System Support] to assure that the inevitable glitches and problems be 25

161 See SCE-09, Chapter V, Figure V-7, where SCE forecasts that annual PEV sales will continue to significantly grow,

reaching approximately 151,000 PEVs in its service territory by 2017.

162 For example, today, approximately one percent of SCE’s EV customers select the separately metered, TOU-EV-1 rate. These customers will typically call SCE multiple times to finalize their rate decisions and provide SCE with the required information to service their accounts. A one-stop online service would greatly improve the efficiency of that interaction, as well as improve the overall customer experience.

168

worked out in the key systems then complete the software development and other steps.”163 Edison 1

SmartConnect® and Customer Relationship Management (CRM) have now been implemented and 2

integrated into SCE systems and processes. Since SCE’s 2012 GRC Decision, SCE has streamlined the 3

PEV process and seeks to develop a PEV Self-Service Solution that will provide customers a one-stop, 4

online service solution. This PEV System Support project is now ready to be implemented. 5

(2) Scope 6

Customer Service seeks to develop a multi-year program that will address 7

and implement PEV self-service solutions in a phased approach during 2015-2017. This overall 8

solution will provide SCE’s customers with one-stop, online, end-to-end service solutions through 9

access in SCE.com or by contacting the Customer Contact Center. These services would allow the 10

customers to do the following: 11

Access SCE’s web site for PEV information and education; 12

Perform a rate analysis using the last twelve months of a customer’s 13

actual usage information and incorporating the EV load; 14

Determine which rate best fits the customer’s need; and 15

Request rate changes. 16

Back-end system integration would allow SCE.com to create and transmit 17

service requests initiated through SCE.com to TD service planners to verify customer infrastructure 18

needs and Basic Work Requests (BWR) to the Revenue Services Organization (RSO) to complete rate 19

changes for the customer as requested. Capabilities needed include: 20

System logic to determine (based upon EV information supplied by the 21

customer) if customer’s site requires infrastructure verifications and, if 22

so, routing a Design Manager service request to TD; 23

A Customer Contact Center (CCC) representative to run rate (TOU-D-24

TEV, TOU-EV-1) analyses for customers and the ability to request 25

rate plan changes (based on a series of questions required to calculate 26

kWhs per month); leveraging the Online Rate Calculation Analysis 27

Tool (ORCAT) infrastructure by adding PEV specific information to 28

that analysis; and 29

163 D.12-11-051, p. 375.

169

Similar interfaces for program/services selection and EV rate (TOU-D-1

TEV, TOU-EV-1, or domestic rate) analysis offered through 2

SCE.com. Customers requesting TOU-EV-1 could request an 3

additional meter and service using upgrades to the Design Manager 4

system in order to take advantage of the TOU-EV-1 rate provided by 5

SCE. This may be an additional smart meter on a separate service or a 6

third-party sub-meter. (PEV submetering is not within the scope for 7

this project.) 8

Additional information that would be collected for further analysis would 9

include tracking of customers that have acquired or are planning to acquire a PEV vehicle, changes in 10

their service to support these vehicles, and usage patterns. 11

The PEV Support System’s high level process requirements include: 12

Set up PEV service, including all activities from the initial customer 13

request, to establishment of service, to billing the customer; 14

Online SCE.com-My Account or contact center registration/enrollment 15

and program/service selection; 16

Initiate service request to TD service planners through the Design 17

Manager systems for verification of customer infrastructure needs, 18

creation of BWR rate change for CS’s Revenue and Billing department 19

to change and enroll customer on new PEV rates (TOU-D-TEV); 20

Provide customer rate choice inquiries and forecast billing options 21

based on current interval usage data (ORCAT for TOU-D-TEV and 22

TOU-EV-1) (provide real forecast pricing based on current and 23

modeled usage information); 24

Support PEV Customers; 25

Provide end-to-end services to PEV customers through self-service 26

and CSR directed options, such as account information on usage, 27

rate/program options, infrastructure set-up requests; and 28

Integrate tracking, reporting and analytics across all organizational 29

systems and processes. 30

These changes will impact the following systems: 31

170

SCE.com – self-service for service and program enrollment; 1

Dynamic Pricing – business requirements and additional functionality 2

for the Online Rate Analysis (ORCAT) project for PEV rates; 3

CRM – Customer account information updates and changes; 4

CSS – Enhancements to customer data fields, PEV work process 5

information, program options and enrollment, and integration to 6

Design Manager (TD), Clicksoft, and FATS (CS MSO). 7

Currently, tracking and reporting are done manually. With a growing 8

PEV customer base and regulatory mandates (PEV submetering),164 automated systems will be required 9

for accurate tracking and reporting and for efficient, effective service for our customers. These system 10

upgrades are essential to facilitate and streamline SCE processes associated with proper installation of 11

customer charging equipment and metering hardware. In addition, these system changes support SCE’s 12

ability to effectively implement PEV-specific rate structures and programs as mandated by the 13

Commission in R.09-08-009. 14


The PEV project will be reviewed on a regular basis at project status 16

meetings for adherence with budget, schedule, and technical objectives. Standard project management 17

tools and techniques will be used to manage the project. Certain planning aspects of this project may 18

begin earlier due to specifications necessary for concurrent development in other related systems. Such 19

concurrent development allows for establishment of requirements across multiple projects, which can 20

minimize rework when projects have differing implementation schedules. 21

Implementation for the PEV project will be scheduled to start in the third 22

quarter 2015 and is expected to complete by the end of the third quarter 2016. The first phase will 23

consist of implementing Customer Contact Center enrollment and workflow status tracking. This status 24

will be visible to Customer Service Representatives and internal departments. The systems affected will 25

be the Customer Service System, Design Manager, and Field Automated Test System. The second 26

phase of implementation will affect the customer facing systems. This implementation will allow 27

customers to evaluate and enroll in SCE’s PEV rates online through SCE.com. The systems affected by 28

the second phase will be SCE.com, CRM, and the Customer Data Warehouse. 29

164 See R.09-08-099.

171



The scope of this project is to enhance the overall PEV process and system 3

solution to enable SCE to provide their customers with a seamless PEV experience. As PEV sales 4

continue to grow in the market, automated system integration between internal existing systems is 5

needed to deliver simple solutions for customers to be able to select rates, programs and services. 6

Current programs are offered to customers through contact with a customer service representative (CSR) 7

in the Customer Contact Center (CCC), but there are limits to what a CSR is able to provide to the 8

customer; a CSR cannot forecast what the customer’s bill would be on other programs based on the 9

customer’s current usage. 10

The current process has seven steps and requires numerous hand-offs 11

among four SCE organizational units and departments using seven disparate systems. Figure VI-12 12

below illustrates the current PEV enrollment process. 13

Figure VI-12 Current PEV Seven Stage Process

Because the PEV-related system changes will result in an enrollment 14

process that is simple for customers to use, it may facilitate the growth of PEV use in SCE’s territory, 15

which will help reduce greenhouse gas emissions and create opportunities for optimizing use of utility 16

assets. 17

172

PEV Self Service Solution will also reduce costs while improving 1

customer service as EV volume grows by doing the following: 2

Reducing the number of customers contacting the CCC, 3

Reducing errors through automation, 4

Decreasing customer time and effort to make a rate choice, and 5

Reducing manual support role to monitor and support process. 6


Maintaining the status quo would be one alternative to developing new 8

functionality to support the increased rate of PEVs that are expected to be in service. The existing 9

systems and manual interactions would not allow SCE to provide an adequate level of customer service 10

to the growing number of PEV owners and might even serve as a disincentive to the adoption of PEVs. 11

SCE also considered developing a stand-alone system to support PEVs but 12

determined that it would be more expensive to implement and maintain without providing any 13

significant additional benefits over the proposed approach. 14


For the capital software cost-benefit analysis, the costs of construction and 16

any incremental O&M post-implementation were compared against up to five years of benefits post-17

implementation. For this analysis, all future costs and benefits were escalated to year-of-expenditure, 18

then discounted to 2012 NPV using a 10 percent discount rate. Finally, the sum of present-value 19

benefits was divided by the sum of present-value costs to derive the Benefit-Cost ratio for the project. 20

Because of the construction period required for software capital projects and the ensuing five-year 21

benefit window, many projects have substantial benefits after 2017, which are not reflected in this GRC; 22

benefits between 2018-2020 will be reflected in SCE's next GRC Test Year 2018. 23

The PEV Support System has a Cost-Benefit Ratio of 1.32.165 This is 24

achieved by reducing PEV operational costs by $1.7 million over a five-year period. This includes 25

reducing PEV tracking and reporting costs by 40 percent and reducing the number of EV customer calls 26

to the CCC by 50 percent in 2017 and 60 percent in 2020. There may be additional benefits that were 27

not included, such as reduced errors due to automation and increased customer satisfaction because of a 28

more efficient process. 29

165 See workpaper entitled “Cost-Benefit Analysis for Plug-In Electric Vehicle (PEV) Support Systems.”

173


The forecast capitalized software costs of $2.5 million for the PEV Support 2

System project is comprised of labor, hardware, licensing and contingency costs.166 Estimates for IT 3

support are based upon prior experience with similar projects. Based upon various types of 4

developmental or COTS projects, labor rates, contingency levels, and cost components are utilized to 5

develop the overall cost estimate of the project.167 The system changes and enhancements discussed 6

above are incremental to existing functions delivered as part of the Edison SmartConnect® program and 7

in other GRC requests. The current estimate is based on experience associated with system development 8

projects in similar size and scope. 9

Table VI-52 below illustrates the forecast expenditures of the PEV Support 10


Table VI-52 Capital Forecast Expenditures for the PEV Support System Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ -$ 2.5$ -$ 2.5$

d) Conclusion 12

The PEV Support System was proposed in SCE’s 2012 GRC. The Commission 13

stated, because of the slower than expected adoption of PEVs, SCE should wait for other system 14

implementations before implementing the PEV Support System. Those systems have been 15

implemented, and the adoption of PEVs in SCEs territory is growing. The system upgrades discussed in 16

this testimony will support SCE’s goal to provide efficient and effective support for its PEV customers 17

and has a positive cost-benefit ratio of 1.32. The modifications will also provide SCE with information 18

to help it effectively implement, manage and refine its PEV support program. Multiple systems will be 19

enhanced to integrate and automate systems and processes to create an efficient workflow. 20

166 See workpaper entitled “Forecast Expenditures for Plug-In Electric Vehicle (PEV) Support Systems.”


174

12. Customer Service System (CSS) Enhancements 1

a) Background 2


CSS was developed in the early 1990s, and certain capabilities built into 4

the system are becoming obsolete and in need of replacement. In general, CSS contains the following 5

five major capabilities: (1) Cashiering and Payment Options, (2) Credit and Collections, (3) Event 6

Scheduling, (4) Billing, and (5) Metering. These sub-systems are treated as a single project because of 7

the multiple and complex interrelationships, common problems, and interfacing with SAP when 8

addressing the inherent technology obsolescence in each module. 9

SCE’s current evaluation requires an expenditure of $12 million during the 10

2015 GRC window specifically to (1) replace the obsolete Cross-System Product (CSP) tool, which is 11

no longer supported by IBM, and (2) to complete the conversion to CSS workstation, which will 12

eliminate the Green Screen technology for displaying customer information. 13

(2) Scope 14

The scope of work involved with this project is as follows: 15

(a) Green Screens 16

The green screens currently being used for a variety of interfaces 17

with CSS, including accounts receivables, collections, early warning system, field systems, the metering 18

equipment system, and the revenue protection system, among others need to be replaced. The green 19

screens are old and rule-based and are both technologically and functionally obsolete based on 20

technology of the 1990s used to display mainframe generated information on Cathode Ray Tube (CRT) 21

displays. 22

(b) Cross-System Product (CSP) 23

Systematically replace the obsolete IBM development tool, Cross-24

System Product (CSP). CSP is comprised of a set of source code generators. The last supported version 25

of CSP was version 4.1 which went out of support at the end of 2001. SCE needs a new tool to perform 26

what CSP has been doing, and remediate the existing code that was generated by CSP. This requires a 27

migration of the CSP-generated code to another format of currently-supported code. 28

CSS has a significant amount of unsupported CSP code, which can 29

be divided into three categories of required replacement. 30

175

(i) Applications fully implemented with CSP 1

Shared Subsystems – Provide common software 2

processes to be used by application sub-systems within 3

CSS. 4

Sales Summary – Main source of data for Account 5

Management application (described below), ad-hoc 6

reporting, and summarized consumption data. 7

(ii) Applications partially implemented with CSP 8

Post-Billing – Provides credit functions, such as 9

payment extensions. 10

(iii) Applications with redundant use of CSP 11

CSS Workstation – A tool that simplifies customer 12

account information. 13

Customer Billing Application – Collects information 14

from various systems, such as Service Billing and 15

Customer Information, and integrates the data to create 16

the customer account statement. 17

Each of these applications will need to be replaced because 18

of obsolete code. 19


The Customer Service System (CSS) Enhancement project is scheduled to 21

start in 2016 and end by 2017. 22



As described in the prior scope section, the CSS system is obsolete or 25

inflexible and not able to address the daily activities of the Revenue Services Organization (RSO). 26

Many operational functions require manual intervention, which take additional time and could lead to 27

errors. 28

176


Alternatives to CSS have been considered and studied. They will continue 2

to be evaluated in the future with the intent to have a longer term plan in place to deal with those parts of 3

CSS that increasingly become obsolete. 4


This system is obsolete and no longer supported. The obsolete platforms 6

for which the technology is built are facing challenges to evolve with more current technologies, 7

therefore causing risk to the business when unable to upgrade to current system releases, which are 8

company-wide. Therefore, the decision to undertake the project cannot be appropriately analyzed using 9

a cost-benefit analysis. 10


The forecast costs of $12.0 million for the CSS Enhancements project are 12

comprised of labor, hardware, licensing and contingency costs.168 Estimates for IT support are based on 13

prior experience with similar projects. Based upon various types of developmental or COTS projects, 14

labor rates, contingency levels, and cost components are utilized to develop the overall cost estimate of 15

the project.169 This project is expected to be a highly complex, internally developed solution. 16

Therefore, the added functionalities will be considered a large developmental project based on IT’s 17

estimating method. 18

Table VI-53 below illustrates the forecast expenditures of the Customer Service 19


Table VI-53 Capital Forecast Expenditures for the CSS Enhancements Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ -$ 5.0$ 7.0$ 12.0$

168 See workpaper entitled “Forecast Expenditures for Customer Service System (CSS) Enhancements.”


177

d) Conclusion 1

The CSS Enhancement project will replace critically important portions of CSS 2

that were built on platforms that are obsolete and are no longer supported by the vendor. Technology 3

has advanced. The green screens used to display main-frame data first deployed in the 1990s are 4

outdated and obsolete, making it difficult to enhance the system. This investment in replacing this 5

portion of the CSS application will keep CSS running and will allow for further exploration of a longer-6

term solution. 7

13. Cell Relays Replacement Project 8

a) Background 9


Cell relays work in conjunction with smart meters to collect interval data 11

from customers and relay that data back to the Network Management System (NMS). One cell relay 12

device can transmit data for up to 500 smart meters. 13

The cell relays that SCE purchased for the Edison SmartConnect® 14

implementation approved in D.08-09-039 have a useful life period of seven years due to technical 15

obsolescence of the product. Once the devices extend beyond their useful life, the vendor will no longer 16

support the device. We are contractually obligated to remain within two system updates behind the 17

current release. Many of the devices that were installed early in the program will be coming to the end 18

of their lifecycle during this GRC period. SCE will be working with vendors to identify the next 19

generation of communication devices required to support the changing technological landscape of smart 20

meters and will replace the cell relay devices as they approach the end of their lifecycle and support 21

period. 22

The Meter and Communications System is a series of systems and 23

applications that comprise the communication channel through which SCE bills its customers, and 24

provides critical customer services such as remote turn-on and turn-offs, near real-time energy 25

information, and power outage and restoration information. This system is required in order to bill SCE 26

customers accurately and on a timely basis. In 2020, software and firmware enhancements made to the 27

Meter and Communications System will no longer be supported. This system requires a formal 28

contractual support agreement with SCE’s suppliers. 29

The Cell Relay Replacement project will be a two-phase project. The first 30

phase includes modifications to and testing of the Metering and Communication System to ultimately 31

178

support the new hardware. The second phase of the project will be the purchase and installation of the 1

new devices. 2

(2) Scope 3

In addition to the Meter and Communications System, there are several 4

individual applications that interact with the cell relay devices. 5

Cell Relay Configuration Management System (CGM) – CGM ensures 6

configuration management of new devices. This system is used to push out any needed upgrades to cell 7

relay devices while they are installed in the field through the air and received by cell relays. 8

Network Management System (NMS) – The NMS is the gateway to all 9

Edison SmartConnect® meters and field infrastructure. All commands sent to and all data received 10

from smart meters and network field infrastructure must pass through the NMS. The NMS will need to 11

be modified and tested to ensure it can communicate with new devices. 12

Customer Service System (CSS) – This application contains the following 13

six major capabilities: (1) Cashiering and Payment Options, (2) Credit and Collections, (3) Event 14

Scheduling, (4) Meter Data Acquisitions, (5) Billing, and (6) Metering. 15

Meter Equipment System (MES) – The MES is the system of record for 16

asset management to track assets and track Advance Shipping Notice (ASN). The MES is the inventory 17

management system. The various locations of the meter are tracked through MES from the time the 18

meter is purchased to when it is received in the warehouse to when it is installed in the field. 19

Security Event Management (SEM) system – This application is used to 20

conduct security monitoring by capturing meter logs and event data and interrogating the data to identify 21

cyber security alerts. Cell relays send encrypted secure text files to the SEM system every minute. 22

SEM reads these files to determine if there are any types of security alerts on the system. 23

Cell Relay Availability (CRA) – The CRA monitors the health and 24

operations of the cell relay signal effectiveness. The CRA polls the cell relay device every five minutes 25

to ensure the cell relay is active. 26

Edison SmartConnect® Monitoring & Analysis System (SCMAS) – The 27

SCMAS is used to facilitate the monitoring and analysis of the ESC meter and communication system. 28

The SCMAS is the main interface for the Meter and Communications System. It acts as an umbrella 29

and a single point of entry and management for NMS, security, and visualization. 30

179

System updates to these applications are required before deployment of 1

new cell relay devices to ensure compatibility. A systemic problem with one or more of these 2

applications may affect the ability to communicate with the entire meter population and impact business 3

operations and customer service. 4

Phase two of the Cell Relay Replacement project extends from 2017 to 5

2019. The project will include the replacement of 14,000 cell relays. The necessary equipment will be 6

procured over three years to perform approximately 20 percent of the work in 2017, 40 percent in 2018, 7

and 40 percent in 2019. Because this project spans two GRC cycles, only the costs associated with the 8

2017 year will be included in this 2015 GRC. 9

The new cell relay devices will replace the cell relays currently installed at 10

the base of the meter socket on customer premises, poles, pedestals, or pad-mounted. Because 20 11

percent of the total 14,000 cell relays will be replaced in 2017, SCE needs to purchase 2,800 new cell 12

relays along with the appropriate poles, pedestals, or pad-mount hardware. An existing meter with a cell 13

relay socket will also need to be replaced with a new end point meter. There are necessary field design 14

costs related to determining which SCE utility poles or pad-mounts should be used and identifying 15

transformers already located near existing cell relay installations. 16

Without this capital project, cell relays will reach the end of their useful 17

lifecycle and contract supported period. The devices will begin to fail at a faster rate, and SCE may be 18

unable to bill its customers. The firmware and software will no longer be supported by the vendor and 19

may not even be procured, which would lead to a shutdown of the entire Meter and Communications 20

System. 21


This project is required for SCE to continue uninterrupted collection of 23

operating revenue; the decision to undertake the project cannot be appropriately analyzed using a cost-24

benefit analysis. There are other operational functions that would also be lost, such as the use of the 25

remote service switch (RSS), web presentment of customer usage data, programs and rates that rely 26

upon hourly usage data, and power outage information. Cell relays transmit customer usage data back to 27

the NMS system. The MDMS sits between the NMS and CSS and is the system of record for meter 28

data. MDMS uses meter data to create billing determinants that are passed to CSS to calculate the actual 29

customer bill. Each time a cell relay fails, the communication for approximately 500 meters associated 30

with the device is interrupted. The duration of the interruption will depend on whether the meter can 31

180

attach to another cell relay in the area and how long it takes the meter to find another cell relay to 1

reestablish communication. If a meter cannot connect with a cell relay, manual meter reading is required 2

to read the meter, as was done before ESC deployment. The project will not create incremental O&M as 3

the Business Intelligence Organization (technology used for data analysis), Edison SmartConnect® 4

Operations Center (SOC), and Meter Service Organization (MSO) are currently staffed to handle 5

ongoing product testing and support as part of their business-as-usual engineering function. 6


The capitalized software component of the Cell Relays Replacement 8

project is scheduled to commence in June 2016 with the selection of the product and vendor and will be 9

completed by July 2017 with the testing of the system update to accommodate the new products. The 10

non-systems capital component of the project, the actual removal and replacement of the cell relays, is 11

scheduled from 2017–2019 and targeted to replace 14,000 cell relay devices. 12



The current Meter and Communications System as shown below in Figure 15

VI-13 consists of six different systems and applications all coordinated to bring 15-minute interval data 16

from the individual meter into the Customer Service System, which contains software to calculate and 17

bill SCE’s customers for their energy usage. 18

The smart meters collect the usage data and transmit it to the cell relay. 19

From the cell relay, the information is sent to three different systems. NMS receives the usage data in 20

15-minute intervals. After it receives information, it sends data to the MES system to verify the meter 21

inventory. The CRA and SEM systems receive information every minute from the cell relays. These 22

systems check for the validity of a signal and ensure there are no security alerts on the system, 23

respectively. The CGM system is used as needed to send software updates to the cell relays. These 24

systems send the information they receive to a large data warehouse, which can be utilized through a 25

reporting application. 26

181

Figure VI-13 Meter and Communications System


There is no alternative to the replacement project. The cell relays are the 2

backbone of the Meter and Communications System. If the vendor is not supporting the cell relays, 3

SCE will be limited in its ability to implement future releases and updates of the NMS system. If SCE 4

does not stay within specified releases of the system and firmware software, SCE will be in violation of 5

its maintenance contract agreement with its vendor. If SCE were simply to maintain the current system, 6

SCE would eventually lose its capability to bill its customers because of equipment failure and 7

obsolescence. The current failure rate of the cell relays is seven percent. The end of the effective life of 8

a cell relay is approaching in 2017. SCE expects this failure rate would increase as the existing cell 9

relays reach and exceed their effective lives. When these existing relays fail, there is no guarantee that 10

the same cell relays will be available. The existing model will not be supported by the vendor, and the 11

182

vendor will not guarantee it will be making these models as technology advances. Allowing these 1

devices to go out of warranty and fail will directly affect SCE’s ability to collect its operating revenue 2

and provide customers usage information. 3


The forecast capitalized software costs of $17.3 million for the Cell Relays 5

Replacement project is comprised of labor, hardware, licensing and contingency costs.170 The project is 6

divided into two components: the IT software modifications and the cell relay procurement process. 7

The $5.8 million estimate for IT software modifications is based upon prior experience with similar 8

kinds of projects. Various types of developmental or COTS projects, labor rates, contingency levels, 9

and cost components are utilized to develop the overall cost estimate of the project.171 The system 10

modifications required for these enhanced products are considered of “medium complexity” under IT’s 11

estimating method. The $11.5 million estimate for the cell relay procurement process was derived from 12

the cost of procuring and installing a cell relay device multiplied by the number of devices to be 13

replaced.172 14

Table VI-54 below illustrates the forecast expenditures of the Cell Relay 15

Replacement project by year. 16

Table VI-54 Capital Forecast Expenditures for the Cell Relay Replacement Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ -$ -$ 17.3$ 17.3$

d) Conclusion 17

The Meter and Communications System allows for the continuous collection of 18

meter usage data by which SCE bills and provides usage information to its customers. The cell relay 19

equipment has a useful life of seven years. Current equipment initially installed in 2010 with the Edison 20

SmartConnect® deployment falls out of warranty in 2017. Likewise, support for the current software 21

and firmware enhancements ends in 2020. By beginning implementation of the necessary system 22

170 See workpapers entitled “Forecast Expenditures Cell Relays Replacement Project” and “Cell Relay Procurement Costs.”


172 See workpaper entitled “Cell Relay Procurement Costs.”

183

upgrades to support the new cell relay devices in 2016, SCE will be able to complete the installation of 1

14,000 cell relays and system updates by 2020. This project is critical to support continuous billing of 2

customers and the generation of operational revenue. 3

14. Home Area Network (HAN) Future Upgrades and Standards 4

a) Background 5


The Edison SmartConnect® deployment represents a critical milestone for 7

implementation of the HAN and demand-side management capabilities. During the 2013-2014 period, 8

SCE expects growth in this emerging market with widespread availability of standardized HAN devices 9

through retail distribution channels to consumers and the implementation of SCE programs that utilize 10

HAN devices (e.g., Summer Discount Plan with Smart Thermostats). The CPUC has ordered that SCE 11

be able to support up to 200,000 HAN devices within its service territory by the end of 2014—including 12

in-home displays, programmable communicating thermostats, and other smart appliances.173 13

(2) Scope 14

As the HAN technology advances, customer adoption is expected to 15

increase. To meet customer needs and regulatory mandates, SCE plans to build upon the foundation to 16

expand HAN capabilities and programs. The continued evolvement and development of HAN 17

functionality will be required to fully exploit smart meter technologies. There is a significant 18

opportunity to integrate HAN technology into SCE’s existing programs and services to deliver 19

additional value to customers. HAN technology can be leveraged as SCE educates and informs 20

customers to actively respond to dynamic pricing signals, demand response events, and energy 21

efficiency programs. These advanced capabilities include the following functionalities: 22

(a) Enable Enhanced or New Customer Program Offerings 23

A key benefit of the HAN is that it allows SCE to enhance existing 24

and offer new and innovative customer programs and services. These programs can result in energy 25

conservation and demand response benefits. In this GRC period, SCE expects to see continued 26

innovation and growth in HAN enabled technologies. SCE intends to evolve its program portfolio to 27

include additional customer offerings that capitalize on this product innovation. System capabilities will 28

be needed in order to successfully implement and deliver these programs and services. These 29

capabilities will address new or modified rates, customer enrollment via multiple channels, and new 30

173 Resolution E-4527, September 27, 2012.

184

technology registration and troubleshooting. SCE will leverage the existing processes to the extent 1

possible when building the processes for the new programs. However, new capabilities and 2

enhancements will be needed to effectively support these new programs. 3

(b) Enable Billing, Payment and Energy Efficiency Messaging 4

This functionality will expand SCE's ability to send a broader set 5

of text messages to registered HAN devices. Some of the additional text messages include billing and 6

payment messages, such as “Your bill is ready,” “Your payment is due in X days,” and “Thank you for 7

your payment.” Enabling this ability leverages an additional channel to provide customers with timely 8

information about their SCE bill and their payments. 9

Likewise, Energy Efficiency messaging will provide SCE with the 10

ability to send reminder text messages to change energy consumption behavior. The messages may 11

include “Raise your thermostat to reduce your bill,” “Turn off lights in vacant rooms,” “Charge your 12

PEV after 8:00 p.m.,” “Use light-sensing fixtures outside,” etc. Providing customers with real-time 13

actionable messages may contribute to energy conservation behaviors. 14

The system changes and enhancements discussed in this messaging 15

section are incremental to functions delivered as part of the Alerts and Notification project also 16

requested in this GRC. The Alerts and Notification project will establish the system so that alerts and 17

notifications can be sent. The HAN Future Upgrades and Standards will enable the development of the 18

functionality for HAN to become a channel for targeted messages from the Alerts and Notifications 19

System and deliver messages to HAN devices. 20

(c) Third-Party Registration of HAN Device 21

SCE anticipates that many of the HAN devices purchased by 22

customers will be installed by third-party service providers (e.g., cable, telecom, security, etc.). SCE 23

also expects that these customers will want the device registered as part of a comprehensive service 24

package. SCE has enabled eligible end-use customers to submit HAN device registrations request via 25

the SCE portal (My Account), which requires the customer to enter an ID and password to authenticate 26

the requestor. To enable a third party to submit a request on behalf of the customer, SCE would require 27

the customer to provide authorization for the third party to act on the customer’s behalf, as well as make 28

system changes to provide a mechanism for the third party to submit the request. This will provide the 29

customer and third party a more seamless, positive experience and reduce the possibility of a customer 30

abandoning the program enrollment process with the third party. 31

185

(d) Solar Inverter Control Via HAN 1

This functionality would provide customers with energy 2

production (kW and kWh) data of their PV system. Customers could use PV system production data to 3

better manage their overall energy consumption, resulting in reduced customer costs. Furthermore, 4

advanced controls via HAN would give SCE the ability to directly manage smart inverter output for 5

increased system safety and reliability. 6

(e) Gross Generation within Distributed Generation Display 7

This display will provide a single source of information from SCE 8

to the customers regarding total generation and net energy returned to SCE. This will improve customer 9

service and support better and more reliable data for SCE forecasting. 10

(f) PEV Charging Control Via HAN 11

SCE's service territory is host to one of the nation’s leading PEV 12

adoption areas. Currently, most PEV customers charge their vehicle at home. Depending on the type of 13

vehicle and the charging level, PEV charging load could be one of the largest loads in the house, far 14

exceeding any other load, including air conditioning. PEVs should be treated as any other smart device 15

in the home. 16

Customers who purchase charging equipment will have the ability 17

to enroll in advanced programs that would allow them to take advantage of technology to better manage 18

their PEV charging. This would include provisioning of customer infrastructure. To assist customers 19

with their PEV charging management, tariff information, in conjunction with user preferences, will 20

provide customers the ability to reduce cost and maximize charging. For charging control, SCE could 21

develop a PEV-specific load management program similar to the legacy Summer Discount Program. In 22

return, customers would receive an incentive for allowing SCE to interrupt or curtail their charging 23

session (with the ability to opt out). For residential and light commercial customers, both tariff and 24

control messages could be delivered using either the Edison SmartConnect® meter or via the customer’s 25

internet connection. 26

(g) Third-Party PEV Charging Controls within HAN 27

Product manufacturers are quickly moving toward cloud-based 28

control systems. In order to reduce the chance of stranded assets, it is recommended that SCE establish 29

an OpenADR2.0 system to leverage third party controls. In such a scenario, SCE does not have control 30

over the end-use device. Rather, SCE prompts the third party to reduce load in a targeted region or 31

186

provides pricing tariff info to the third party to enable the third party to manage its customers’ loads. As 1

an aggregator, the third party is responsible for the enrollment of customers and establishing 2

communications with the end-use device. 3


The Smart Meter HAN implementation plan (phases III and IV) will be 5

completed in 2014 and is being funded through the Edison SmartConnect® Balancing Account 6

(ESCBA). The HAN enhancements defined in this GRC are expected to be completed after funding 7

through the ESCBA has closed. 8



The current text messaging capabilities with the HAN are very limited. 11

Pricing signals, cost-to-date forecasts, and Save Power Days are some of the only text messages that can 12

be sent over the HAN. Many of the other capabilities described in the scope section do not yet exist. 13

The HAN device is new technology, which is just beginning to be utilized. 14


The alternative is to do nothing, but doing nothing would contradict many 16

of the Commission’s past wishes. In Ordering Paragraph 11 of D.11-07-056, the Commission ordered 17

SCE to develop a Smart Meter HAN implementation plan. The plan has been completed and is being 18

implemented with HAN implementation Phases III and IV being completed in 2014. In this Decision, 19

the Commission also requested utilities make HAN functionality and benefits generally accessible to 20

customers on a consistent and statewide basis. SCE has laid its HAN foundation, and this project will 21

provide additional functionality and benefits. SCE has shared its HAN Roadmap (which includes these 22

additional functionalities) with Commissioners and received no negative comments. 23


This project is an anticipated compliance project as SCE feels this is the 25

direction in which its customers and the Commission want the HAN to be developed. As such, a cost-26

benefit analysis was not used in determining the need for this project. This project is necessary for SCE 27

to implement based on the evidence stated above in Section (2) Alternatives Considered. 28

187


The forecast costs of the HAN Future Upgrades and Standards project is $6.00 2

million.174 Estimates for IT support are based upon prior experience with similar projects. Based upon 3


are utilized to develop the overall cost estimate of the project.175 This project is expected to be an 5

internally developed solution. Therefore, the added functionalities will be considered a small 6

developmental project based on IT’s estimating method. 7

Table VI-55 below illustrates the forecast expenditures of the HAN Future 8

Upgrades and Standards project by year. 9

Table VI-55 Capital Forecast Expenditures for the HAN Future Upgrades and Standards Project


Year 2013 2014 2015 2016 2017 TotalCosts -$ -$ -$ -$ 6.0$ 6.0$

d) Conclusion 10

The objective of the HAN Future Upgrades and Standards project is to ensure 11

SCE is aligned with the latest HAN Standards to remain consistent with the market evolution of HAN 12

technology, to enable third parties to provide customers energy management and demand reduction 13

services, and to fulfill SCE’s regulatory requirements. 14

F. Power Supply 15

1. Data Management Platform Upgrade Phase 3 16

a) Background 17

The Common Data Store (CDS) is a data hub that serves as the central repository 18

and exchange for California Independent System Operator (CAISO) market-related operational data. 19

The CDS transfers forecasts of load, gas and power prices, various generation resource output (including 20

output from hydro-electric and QFs), meter data, and weather data to Power Supply’s176 operating 21

systems. The CDS also receives the results of market operations, including published prices, schedules, 22

174 See workpaper entitled “Forecast Expenditures for HAN-Future Upgrades/Standards.”


176 See SCE-02, Vol. 4, where O&M cost related to Power Supply’s capital software requests are described in more detail.

188

transfers, deal data, and outages. The CDS transfers this information to the Power Supply Data and 1

Reporting system for operational and regulatory reporting purposes. 2

The implementation of Market Redesign and Technology Upgrade (MRTU) 3

resulted in significant increases in the complexity and volume of data that Power Supply needs to 4

process and store. The current interfaces between CDS and the source and target systems were 5

developed before MRTU was implemented. SCE’s post-MRTU operating experience reveals the need 6

for data operations improvement. In addition, while meeting the basic needs for MRTU startup, the 7

CDS does not contain all of the data necessary to efficiently meet the ongoing and developing trading, 8

operations, risk management and transaction settlement data requirements. 9


Power Supply needs to enhance its outdated data management infrastructure to 11

reflect changing market needs. The Data Management Platform Upgrade Phase 3 project will do the 12

following: 13

Upgrade CDS in order to handle increased CAISO data flows. While the CDS 14

was designed to capture pricing information on the 8th day following the trade 15

day, CAISO has been re-publishing its data at varying and increasing 16

frequencies. This has resulted in higher-than- planned data storage and 17

transfer requirements, which are taxing Power Supply’s ability to efficiently 18

handle the data flow. Likewise, the large increase in the amount of data 19

managed by Power Supply resulting from MRTU, ongoing CAISO market 20

enhancements, and Edison SmartConnect® program, will require Power 21

Supply’s data management capabilities to be continually improved to ensure 22

that the vast quantity of data is useful to Power Supply users.177 23

Enable CDS to collect more types of data: The platform should be expanded 24

to include transmission outage data, pricing data, forecast data, awards, and 25

other data currently stored within a variety of operating systems. 26

Make the interfaces that transfer data from CAISO more efficient by going 27

directly to CAISO to get the source data rather than relying on an 28

177 See workpaper entitled “Forecast Expenditures CDS/PDR Enhancement Project.”

189

intermediary system to download data from CAISO before transferring the 1

data to CDS. 2

Power Supply determined that, by the end of 2012, SCE had enough experience in 3

operations in the post-MRTU market to allow the project to proceed and be able to provide valuable 4

capabilities for managing SCE’s energy resource requirements. 5


Table VI-56 Capital Forecast Expenditures for Data Management Platform Update Phase 3

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

1,270$ -$ -$ -$ -$ 1,270$

We forecast costs of the Data Management Platform Update Phase 3 project to be 7

$1.270 million for 2013. This cost estimate is based on the forecasted costs to complete the scope of 8

project. For detailed cost information of this initiative, see attached workpaper.178 9

This project was included as part of the 2012 GRC and was scheduled to be 10

completed by 2012. This project is now scheduled to be implemented in 2013. 11

d) Conclusion 12

The Data Management Platform Update Phase 3 project will simplify interfaces 13

between the CAISO and SCE systems in order to improve data operations. 14

2. CAISO Market Enhancements in 2013 15

a) Background 16

The MRTU program was implemented on March 31, 2009. Following MRTU 17

implementation, CAISO implemented several enhancements to the MRTU program during 2009-2012. 18

CAISO has further enhancements planned for 2013 and beyond. SCE replaced many of our systems in 19

preparation for MRTU implementation and we are enhancing these systems to keep up with new and 20

changing CAISO requirements. The objective of the CAISO Market Enhancements project is to 21

enhance existing systems and processes to implement CAISO 2013 market initiatives in order to meet 22

SCE’s CAISO Scheduling Coordinator obligations. 23

178 See workpaper entitled “Data Management Phase 3 Platform Project Costs.”

190

CAISO maintains the current list of initiatives including detailed descriptions179 1

and a release schedule of the list of initiatives included in each release.180 CAISO generally releases 2

major CAISO market changes three times each year: Winter (on January 1), Spring (typically in April) 3

and Fall (typically in October). The scope and timeline of each release are driven by CAISO and are 4

subject to change, sometimes with little advanced notice. CAISO currently is scheduled to implement 5

19 market initiatives during 2013, 12 of which are scheduled for the Spring release and 7 of which are 6

scheduled for the Fall release. No initiatives are currently scheduled for the Winter 2013 release. The 7

market initiatives that will impact SCE the most in 2013 are Pay-for-performance Regulation (also 8

called FERC Order 755) in the Spring release and Mandatory Multi-Stage Generator (MSG) in the Fall 9

release, as discussed in more details below. 10

(1) Pay-for-performance Regulation 11

The pay-for-performance regulation implements FERC Order 755. Before 12

the pay-for-performance regulation went into effect, all generators that provide regulation service to 13

CAISO were compensated based solely on how much frequency regulation capacity they provide. 14

CAISO utilizes regulation service to balance the supply and demand on the electricity grid every four 15

seconds. CAISO performs this balancing by instructing generators that provide regulation service to 16

increase or decrease their output depending on system needs. Generators that can change their output 17

quickly (called ‘fast-moving’ generators) tend to receive instructions to change their output more 18

frequently than generators that are slower in their response. This moving around of the generator output 19

is referred to as ‘mileage’ (since moving the output can be thought of as travelling a distance) and 20

although faster generators provide more mileage (by moving their output around more) they do not 21

receive any additional compensation from CAISO. The pay-for-performance regulation compensates 22

generators that provide regulation service according to the level of mileage they provide. This 23

regulation provides an added incentive to fast-moving generators to participate in the regulation service 24

market. Fast-moving generators are becoming more important to the grid since they help integrate 25

intermittent renewable generation. 26

The pay-for-performance regulation will impact the price forecasting, 27

short-term planning, day-ahead and real-time operations and settlement areas of SCE, as well as the 28

179 See workpaper entitled “CAISO Detailed Descriptions” available at

http://www.caiso.com/informed/Pages/ReleasePlanning/Default.aspx (Last visited June 17, 2013).

180 See workpaper entitled “Master Stakeholder Engagement Plan.”

191

software systems used in these areas. SCE’s Demand and Price Forecasting group will need to consider 1

mileage prices when they develop price forecasts. Likewise, the Short-term Planning group will need to 2

consider mileage as part of SCE’s generation resource plan and bidding strategy and the Energy 3

Operations groups need to include mileage bids as part of the generator bids to be submitted to CAISO. 4

Finally, the Settlements group needs to validate the mileage payments from CAISO. Since pay-for-5

performance payments are based on four-second data, SCE also expects that this regulation will lead to 6

efforts to carefully synchronize the four-second data in the SCE and CAISO generation control systems, 7

requiring modifications and upgrades to those systems to reduce any delays in the control signals 8

between CAISO and the control systems at the power plants. 9

(2) Mandatory Multi-Stage Generator (MSG) 10

In December 2010, CAISO offered a voluntary Multi-Stage Generator 11

(MSG) service to allow market participants to accurately model generators that have multiple operating 12

configurations (also called ‘ranges’ or ‘stages’) with different physical characteristics. For example, a 13

combined cycle gas-fired generator may have a low range where only the gas turbines are running and a 14

high range where the gas turbines and a steam turbine are running. The low range will have different 15

operating characteristics than the high range, and there are limitations on how to move the generator 16

from the low range to the high range and vice versa. Multi-stage generators require special modeling by 17

CAISO to be accurately compensated in the market and the CAISO offers this MSG modeling on a 18

voluntary basis. In 2013, the Mandatory MSG initiative will make MSG modeling mandatory for all 19

multi-stage generators in the CAISO market. Accurately modeling a multi-stage generator requires 20

careful analysis of the operating characteristics of the generator as well as extensive testing with CAISO 21

to validate that the CAISO systems operate the generator in accordance with the model and within the 22

physical limitations of the generator. 23

The Mandatory MSG initiative will require SCE to analyze the generators 24

that would be required to be modeled as MSG resources, configure these generators to the SCE and 25

CAISO systems, and work with CAISO to extensively test that these generators are dispatched properly 26

as MSG resources. 27


Since the implementation of MRTU, the CAISO energy market continues to 29

evolve. Based on the CAISO business requirements and implementation schedule for the market 30

initiatives, SCE will need to modify the Power Supply systems to handle the required changes. 31

192

Each of the CAISO market initiatives brings changes to one or more of the 1

following areas: 2

Modeling of generation resources. As CAISO adds or changes resource 3

attributes (e.g., generator output flexibility), SCE needs to mirror this 4

modeling in its in-house systems to accurately model its generation and load 5

resources. 6

Forecasting and planning load and generation assets. CAISO market changes 7

have an impact on how to optimally plan, bid and schedule SCE’s fleet of 8

resources. SCE’s forecasting and planning systems need to be modified to 9

take the CAISO market changes into account to support the daily operations 10

of SCE’s generation and load assets. 11

Managing generation outages. CAISO market changes impact the information 12

and timeline required for reporting generator outages. SCE needs to 13

implement these changes into our systems to be able to report outages 14

accurately to CAISO. 15

Bids submitted to CAISO. New market initiatives often require new bid types 16

or bid data attributes to be submitted to CAISO. SCE needs to implement 17

these changes into our systems to be able to submit accurate bids to CAISO. 18

Prices and awards received from CAISO. New market initiatives often 19

introduce new price components or award and/or bid data attributes. SCE 20

needs to implement these changes into our systems to be able to retrieve the 21

market results from CAISO. 22

Settlement statements and invoices received from CAISO. Most market 23

changes will require either new settlement charge codes or changes to existing 24

charge codes. SCE needs to implement these changes into our systems to be 25

able to validate that the payments and charges to and from CAISO are 26

accurate. 27

These changes generally require modifications to the SCE systems, databases and 28

system interfaces. In addition, CAISO conducts a market simulation to test all market initiatives before 29

they are deployed into the daily production market. SCE participates actively in all market simulations 30

to validate both that the CAISO market is functioning as expected and to validate our internal systems 31

193

and processes. The CAISO Market Enhancements project will implement the CAISO market changes in 1

2013. 2


Table VI-57 Capital Forecast Expenditures for CAISO Market Enhancements Project (2013)

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

5,300$ -$ -$ -$ -$ 5,300$

We forecast the CAISO Market Enhancements project to be $5.300 million. This 4

cost estimate is based on the current scope of the CAISO market initiatives for 2013. For detailed costs 5

information of this initiative, see supporting workpaper.181 6

This project is scheduled to be implemented in 2013 as planned. Per D.12-11-051 7

the project is funded through the MRTU memorandum account. 8

d) Conclusion 9

The funding for this request will allow SCE to remain in compliance with CAISO 10

MRTU market changes in 2013. 11

3. CAISO Market Enhancements in 2014–2017 12

a) Background 13

CAISO goes through an annual process to identify and prioritize future market 14

initiatives. Once identified, each of the initiatives is ranked based on the two criteria: (1) benefits 15

including grid reliability, overall market efficiency and desire by market participants, and (2) feasibility, 16

including market participants’ implementation impact (costs and resources) and CAISO implementation 17

impact (costs and resources). 18

The 2012 CAISO Stakeholder Initiatives Catalog182 outlines the priority issues 19

identified by the CAISO and stakeholders that may require enhancements to the energy market. This list 20

is used by Power Supply to identify market initiatives that have a high likelihood of being addressed in 21

the 2014–2017 timeframe. Although the exact timelines and requirements are still being defined by the 22

181 See workpaper entitled “Forecast Expenditures CAISO Market Enhancements (2013).”

182 See workpaper entitled “2012 CAISO Stakeholder Initiatives Catalog,” California ISO, December 4, 2002.

194

CAISO, SCE must be able to respond and implement required system enhancements once these market 1

initiatives are mandated by the CAISO. 2


CAISO currently has six market enhancement initiatives scheduled for 2014. 4

These include one high-complexity initiative, one medium-complexity initiative, and four low-5

complexity initiatives. The high- and medium-complexity initiatives are as follows: 6

FERC Order 764. This initiative will replace the current CAISO Hour-Ahead 7

Scheduling Process (HASP) with a full 15-minute market. HASP is an hourly 8

process that is used to facilitate imports into California as well as intermittent 9

renewable generation. The timelines of the current HASP process make it 10

difficult for intermittent resources to participate in the hourly market since 11

they would have to predict their output several hours ahead of time. FERC 12

Order 764 introduces a 15-minute market and shortens the timelines to make it 13

easier for both in-state and out-of-state renewable generators to participate in 14

the CAISO market. The FERC Order 764 initiative will impact the price 15

forecasting, short-term planning, day-ahead and real-time operations and 16

settlement areas of SCE, as well as the software systems used in these areas. 17

The Demand and Price Forecasting group will need to include the 15-minute 18

market when they develop price forecasts, the Short-term Planning group will 19

need to include the 15-minute market as part of the generation resource plan 20

and bidding strategy, Energy Operations group needs to submit bids to and 21

download prices and awards from the 15-minute market, and finally the 22

Settlement group needs to validate the payments and charges from CAISO. 23

Flexible Ramping Product. This initiative introduces a new CAISO market 24

product for generator ramping services, which is the capability of a generator 25

to change output over time. Some generators can change their output quickly 26

(called ‘fast-ramping’ generators) and others can only change their output 27

slowly (called ‘slow-ramping’ generators). As the amount of intermittent 28

renewable generation increases CAISO needs more fast-ramping generators to 29

be able to compensate for the rapid changes in generator output by 30

intermittent generators such as solar and wind. The Flexible Ramping Product 31

195

initiative will impact the price forecasting, short-term planning, day-ahead and 1

real-time operations and settlement areas of SCE as well as the software 2

systems used in these areas. The Demand and Price Forecasting group will 3

need to take into account the ramping flexibility when they develop price 4

forecasts. The Short-term Planning group will need to take into account 5

ramping flexibility as part of the generation resource plan and bidding strategy 6

and the Energy Operations groups need to include the ramping flexibility in 7

the bids that are submitted to CAISO. Finally, the Settlements group needs to 8

validate the Flexible Ramping Product payments and charges from CAISO. 9

The 2012 CAISO Stakeholder Initiatives Catalog also identifies market initiatives 10

that CAISO plans to implement in the 2015-2017 timeframe. The scope and timing of these initiatives 11

are driven by CAISO and the associated stakeholder processes and is subject to change. SCE has 12

identified one high-complexity initiative, seven initiatives that have medium complexity, and 47 low-13

complexity initiatives. 14

The high- and medium-complexity initiatives are discussed in more detail as 15

follows: 16

Load Aggregation Point (LAP) Granularity. Currently, there is one LAP for 17

each of the three investor-owned utilities (PG&E, SDG&E and SCE) where 18

the customer load is forecasted, bid, priced, metered and settled by the CAISO 19

market. This initiative would break each of the three existing LAPs into 20

multiple new LAPs, each covering a smaller geographic area. For example, 21

SCE’s single LAP would be divided into a number of smaller LAPs, each of 22

which would have to be independently forecasted, bid, metered and settled 23

separately. The LAP Granularity initiative will have significant impacts on 24

SCE. Currently the systems and processes that support demand and price 25

forecasting, developing and submitting the demand bid to CAISO, as well as 26

the settlement of the SCE demand bid are based on a single LAP that covers 27

the entire SCE service territory. The same is true for the systems and 28

processes that collect, validate and submit load meter data to CAISO. All of 29

these systems and processes would need to be modified significantly to be 30

able to handle multiple LAPs. 31

196

Multi-Day Unit Commitment in the Integrated Forward Market (IFM). 1

Currently the CAISO IFM (also called the day-ahead market) covers only one 2

operating day, i.e. the market is run today for power that will be delivered 3

tomorrow. This initiative would extend the unit commitment portion of the 4

market to cover multiple days. The unit commitment portion of the market 5

process calculates which generators need to be on-line to serve the load for the 6

next day. By extending the time period considered as part of the unit 7

commitment to cover multiple days, CAISO will be able to better select the 8

optimal set of generators to serve load. The reason is that generators with 9

high startup costs but low production costs may seem expensive when only 10

one operating day is considered (because of high start-up costs) but may be a 11

lower-cost option when multiple operating days are considered. This 12

initiative would require SCE to modify its systems and processes in the Short-13

term Planning group to consider unit commitments across multiple days when 14

developing the generation resource plan. The multi-day unit commitment 15

would also impact the SCE forward position (supply vs. forecasted demand) 16

for the days covered by the Multi-Day Unit Commitment initiative. This 17

would impact the trading strategies and activities employed by SCE to 18

manage its forward position. 19

Directional Bidding in Real Time Market. This initiative will allow submittal 20

of bids within the real-time market that include one-way directional bidding 21

(i.e., incremental or decremental energy only) to CAISO. Under the current 22

market design, a market participant can submit an energy bid curve indicating 23

either incremental or decremental energy, but this does not guarantee that the 24

resulting award from the real-time market will be consistent with the direction 25

the market participant desires. This can be particularly challenging for 26

hydroelectric resources, which can have unique operational constraints that 27

require them to provide incremental energy only. This initiative would impact 28

the processes and systems used by the Short-term Planning group to develop 29

the resource plan and bid strategy for the SCE generators, the Energy 30

197

Operations groups to submit bids to CAISO, and finally the Settlements group 1

to validate payments and charges from CAISO. 2

Frequency/Inertia Procurement. ‘Inertia’ is a term that describes the 3

stabilizing effect that is provided by large generators (with large spinning 4

masses) on the electrical grid. The increase in renewable resources may 5

reduce system inertia, which may have a destabilizing impact on the 6

electricity grid. In order to address this emerging operational need, the ISO 7

may consider additional products or services necessary to maintain system 8

inertia. Any new products or services introduced by this initiative will impact 9

SCE’s Demand and Price Forecasting, Short-term Planning, Energy 10

Operations and Settlement groups, as well as the software systems used by 11

these groups. The Demand and Price Forecasting group will need to include 12

the new products or services when they develop price forecasts, the Short-13

term Planning group will need to include the new products or services as part 14

of the generation resource plan and bidding strategy, the Energy Operations 15

groups need to include the new products or services in the bids that are 16

submitted to CAISO, and finally the Settlements group needs to validate the 17

new products or services payments and charges from CAISO. 18

Long-Term Congestion Revenue Rights (CRR) Auction. CRRs are financial 19

instruments used to hedge against the cost of congestion on the transmission 20

grid. Currently, only short-term CRRs can be procured through an auction. 21

This initiative would add an auction mechanism for long-term CRRs as well. 22

This initiative would impact the Transmission Planning and Energy Contract 23

Origination groups at SCE. The Transmission Planning group will need to 24

determine which CRRs to bid for at which prices and the Energy Contract 25

Origination groups, which need to participate in the CRR auction process to 26

submit the bids to CAISO. 27

Expansion of Metering and Telemetry Options. This initiative will investigate 28

additional options for metering and telemetry configurations, including data 29

concentration and alternative security architectures to reduce barriers 30

especially to support aggregated resource models. Pilot projects to verify 31

198

options will be identified and executed as needed to adequately ensure the 1

alternative meets CAISO requirements. This initiative will impact the data 2

connections and field equipment that SCE uses to collect data from the 3

various utility-owned and contracted for generation within its portfolio. 4

Data Transparency. This initiative is intended to enable market participants to 5

replicate the results of the CAISO models. This would include publishing of 6

detailed CAISO modeling and operational data that the market participants 7

would use as inputs to their own models to attempt to replicate the CAISO 8

model outputs as closely as possible. This initiative will allow SCE to capture 9

and store additional data from CAISO needed for its internal modeling of the 10

CAISO market. SCE needs to conduct this modeling in order to study market 11

scenarios and develop bid strategies. 12

Multiple Scheduling Coordinators (SCs) at a Single Meter. Currently CAISO 13

prohibits the use of multiple Scheduling Coordinators at a single meter. 14

Discussions concerning the implementation of enhanced demand response 15

have identified a potential role for demand response aggregators who would 16

bid price-responsive demand separately from the initial scheduling of load by 17

load serving entities. This arrangement would require CAISO to allow 18

multiple SCs for a single meter. This initiative will require changes to SCE’s 19

metering systems for collecting data from the generators as well as the 20

business processes for processing and submitting this meter data to CAISO. 21

Each of these initiatives is described in the workpaper accompanying this 22

testimony.183 The scope and timing of these initiatives are driven by CAISO and the associated 23

stakeholder processes and is subject to change. 24

Each of the CAISO market initiatives brings changes to one or more of the 25

following areas: 26

Modeling of generation resources. As CAISO adds or changes resource 27

attributes (e.g., generator output flexibility), SCE needs to mirror this 28

183 See workpaper entitled “2012 CAISO Stakeholder Initiatives Catalog,” California ISO, December 4, 2002.

199

modeling in its in-house systems to accurately model its generation and load 1

resources. 2

Forecasting and planning load and generation assets. CAISO market changes 3

have an impact on how to optimally plan, bid and schedule SCE’s fleet of 4

resources. SCE’s forecasting and planning systems need to be modified to 5

take the CAISO market changes into account to support the daily operations 6

of SCE’s generation and load assets. 7

Managing generation outages. CAISO market changes impact the information 8

and timeline required for reporting generator outages. SCE needs to 9

implement these changes into our systems to be able to report outages 10

accurately to CAISO. 11

Bids submitted to CAISO. New market initiatives often require new bid types 12

or bid data attributes to be submitted to CAISO. SCE needs to implement 13

these changes into our systems to be able to submit accurate bids to CAISO. 14

Prices and awards received from CAISO. New market initiatives often 15

introduce new price components or award and/or bid data attributes. SCE 16

needs to implement these changes into our systems to be able to retrieve the 17

market results from CAISO. 18

Settlement statements and invoices received from CAISO. Most market 19

changes will require either new settlement charge codes or changes to existing 20

charge codes. SCE needs to implement these changes into our systems to be 21

able to validate that the payments and charges to and from CAISO are 22

accurate. 23

These changes generally require modifications to the SCE systems, databases and 24

system interfaces. In addition, CAISO conducts a market simulation to test all market initiatives before 25

they are deployed into the daily production market. SCE participates actively in all market simulations 26

to validate both that the CAISO market is functioning as expected and to validate our internal systems 27

and processes. 28

200


Table VI-58 Capital Forecast Expenditures for CAISO Market Enhancements Project (2014-2017)

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ 6,790$ 7,000$ 7,000$ 6,000$ 26,790$

We forecast the CAISO Market Enhancements project to be $26.79 million for 2

the 2014-2017 period.184 This initiative is estimated to be a high complexity Commercial Off The Shelf 3

(COTS) software implementation requiring significant upgrades to existing applications, the system 4

interfaces that connect the various systems and databases and hardware infrastructure. The cost 5

assumptions are modeled on previous CAISO market enhancements, including the completed MRTU 6

initiative. The ongoing CAISO market enhancement initiatives have required and will continue to need 7

significant business and IT labor to complete. The licensing costs are based on the assumption of 8

upgrades to the existing applications as opposed to installation of a new application. Hardware 9

estimates assume continued growth in data volumes as well as a need to upgrade development, test and 10

production infrastructure. 11

Per D.12-11-051 this project is funded through the MRTU memorandum account 12

for 2014. 13

d) Conclusion 14

The funding for this request will allow SCE to be in compliance with CAISO 15

MRTU market changes between 2014 through 2017. 16

4. Energy Procurement Information Center Replacement 17

a) Background 18

This project seeks to upgrade or replace the current Energy Procurement 19

Information Center (EPIC) system, which was developed in 2006. EPIC stores information about Power 20

Supply’s contract portfolio, including both current and future contracts. Power Supply uses EPIC to 21

report on SCE’s net-open procurement position (i.e., the amount of power procured versus the amount of 22

power needed to meet SCE’s customer demand) from current time and up to six years into the future. 23

184 See workpaper entitled “Forecast Expenditures CAISO Market Enhancements (2014-2017)” for details on how the cost

estimate was developed.

201

This information drives all of SCE’s power procurement activities, including its Request For Offer 1

(RFO) solicitations, bilateral contracting, and market trading activities. Power Supply also utilizes EPIC 2

to perform “what-if” analyses to see what the impact of new contracts (or a new load forecast) will be on 3

our position. 4

The current EPIC system has a number of limitations that are constraining the 5

usage and usefulness of the system, especially as the number of contracts in SCE’s portfolio increases. 6

The number of active contracts has increased from less than 300 to more than 500 from 2006 to 2012 7

and is expected to increase further in 2013 and beyond.185 8


Several issues exist with the current implementation of EPIC that must be 10

resolved: 11

Ability to run multiple scenarios concurrently. With a growing portfolio 12

multiple users need to run multiple scenarios at the same time. The current 13

EPIC allows only one scenario at a time so the only way to perform a what-if 14

analysis is to lock other users out of EPIC for the duration of the analysis. 15

Varying time resolution. Today, forecasts in EPIC provide hourly data (i.e., 16

hourly resolution), even if the forecast extends for 6 years. Six year forecasts 17

do not need this level of granularity. It would be more efficient to store data 18

for the next few years in hourly resolution and store data at daily (or even 19

monthly) resolution for dates further into the future. This would reduce the 20

data volumes and processing times in the system. 21

Improved controls. In the current EPIC new information is immediately 22

visible to other users and there is no ‘release’ function to release the new 23

information to other users after the upload has been verified. In order to 24

ensure that other users are viewing the most up-to-date information, the user 25

must lock all other users out of the system while making updates. 26

Improved performance. Currently EPIC requires four to five hours to upload 27

and process a new set of data (e.g., an updated load or price forecast). This 28

effectively limits the number of uploads to one to two per day and severely 29

185 See workpapers entitled “Forecast Expenditures Usage Measurement System,” “Forecast Expenditures Generation

Management System,” and “Power Supply EPIC Replacement Investment Memo” for details.

202

impacts the capability to perform what-if and ad-hoc analyses. The target 1

time for a data upload is one hour or less. 2 3

Improved error handling. The current error logging and handling in EPIC is 4

insufficient since while ‘silent errors’ are generated where something has 5

failed in the EPIC processing steps, there is little or no error log indication to 6

help identify or diagnose the error. This could potentially result in incorrect 7

positions being uploaded, published, and used for business decisions. 8


Table VI-59 Capital Forecast Expenditures for Energy Procurement Information Center

Replacement (Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ -$ 2,800$ 3,000$ 5,800$

Funding needs for the EPIC Replacement project are expected to be $5.8 million. 10

This forecast is based on the internal IT application costing model and the details are available in the 11

attached workpaper.186 12

As part of the EPIC Replacement project, SCE plans to survey the market to see if 13

any vendor tools can provide some or most of the required functionality at a lower cost than an in-house 14

development effort. Depending on the results of this survey, the EPIC Replacement project may use a 15

vendor solution, a solution developed in-house, or a combination of the two. 16


completed by 2012. The project start was delayed as part of SCE’s prioritization process of its overall 18

technology spend. It is now scheduled to be implemented in 2016 and 2017. 19

d) Conclusion 20

The proposed EPIC Replacement project will enable SCE to address the 21

limitations of the current system and enable SCE to handle to growing the number of contracts in SCE’s 22

portfolio. 23

186 See workpaper entitled “Forecast Expenditures Energy Procurement Information Center Replacement.”

203

5. Renewable Contract Management System 1

a) Background 2

The Renewable Contract Management187 System project seeks to install a new 3

system to manage renewable power contracts and replace the Wholesale Energy System (WES). WES 4

will be unable to handle the volume and complexity of the new renewable contracts that are currently 5

online and those that are expected to come online in the next five years in growing numbers. 6


Power Supply’s Wholesale Energy System (WES) is old (it was implemented in 8

1998), has limited functionality, and is built on technologies that are no longer supported. The 9

limitations of the current system has forced Power Supply to add more user-developed applications 10

(UDAs) and manual processes in an attempt to handle the growing volume and complexity of new 11

renewable, combined heat and power, and Qualifying Facilities (QF) contracts. These workarounds are 12

insufficient and as the WES becomes increasingly out-of-date and the volume and complexity of these 13

contracts continues to grow, the risk of missing data increases. 14

Specifically, the current WES system is customized to settle legacy power 15

purchase contracts based solely on whether the power was generated during an on-peak or off-peak 16

period (i.e., using a time-of-use definition). New renewables contract terms require payment and 17

settlement functions based on interval data (hourly or sub-hourly) and are tied to CAISO operations and 18

settlements. Since the WES system cannot handle hourly data, all contracts that require hourly or sub-19

hourly data (which includes most of the new contracts) are handled manually using spreadsheets, Access 20

databases and user-developed SAS188 tools today. Data is extracted from WES and other sources, 21

processed manually using spreadsheets and other tools, and finally the results are manually entered back 22

into WES for further processing. This process is cumbersome and increases the risk of human error. 23

The Renewable Contract Management System will be able to handle hourly (and sub-hourly) data 24

through a formula editor that will enable advanced contracts to be configured in the system and 25

automate the processing of these contracts. This will reduce the need for spreadsheet workarounds. 26

Due to the current market structure, the new contracts are far more complex than 27

the legacy contracts that SCE currently administers. The contracting terms now include, but are not 28

limited to: 29

187 Previously called “Commodity Management Platform (Phase 1).”

188 SAS is a statistical analysis package from SAS Institute, Inc.

204

Processing for forecast, scheduled, and metered kWh. 1

Multi-settlement intervals per hour (5, 10 and 15-minute intervals). 2

CAISO settlement transaction adjustments. 3

Payment adjustments based on CAISO prices. 4

Annual energy delivery target monitoring. 5

The Renewable Contract Management System will accommodate contract 6

compliance, payment, and reporting processes for existing and envisioned future power purchase 7

contracts. The Renewable Contract Management System will also provide enhanced controls and 8

auditing capability above what can be done using spreadsheets. The system will be designed to store a 9

timestamp and user name for all changes to data in the system, as well as to store both the previous and 10

new value of the changed data. This enables users and auditors to trace the source and timing of all data 11

changes. This greatly aids in identifying and diagnosing the source of discrepancies in calculation 12

results and counterparty invoices and provides controls that cannot be replicated using spreadsheets. 13


Table VI-60 Capital Forecast Expenditures for Renewable Contract Management System

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

5,000$ 15,520$ -$ -$ -$ 20,520$

SCE forecasts the Renewable Contract Management System will cost $20.520 15

million.189 This forecast is based on the internal IT application costing model and the details are 16

available in the workpaper cited above. 17




d) Conclusion 21

The Renewable Contract Management System will replace the current obsolete 22

system and will enable Power Supply to handle the volume and complexity of the new renewable 23

189 See workpaper entitled “Forecast Expenditures Renewable Contract Management System.”

205

contracts that have recently begun operating or are expected to become operational in the next five 1

years. 2

6. Energy Trading and Risk Management (ETRM) System Replacement 3

a) Background 4

The Energy Trading and Risk Management (ETRM) System Replacement190 5

project will upgrade or replace the Sungard Entegrate191 ETRM system which was put in place in 2008 6

and is used by Power Supply to capture and process all conventional bilateral contracts as well as 7

physical and financial power and gas transactions. The new system will be able to handle new products 8

such as emission products. 9


The Sungard Entegrate ETRM system requires a multitude of spreadsheet 11

workarounds to support the current business needs. By upgrading or replacing Sungard Entegrate 12

ETRM system, SCE will be able to handle conventional, bilateral, and fuel transactions implement most 13

new deal types (e.g., emissions) without the use of spreadsheet workarounds. 14

SCE requires a fully integrated, end-to-end commodity trading system to support 15

its current and future trading of physical and financial energy commodities and bilateral contracts. The 16

system must include front, middle and back office capability. The vendor solution must automate the 17

entire trade to payment process and limit manual intervention and processing. This will reduce 18

operational risks, minimize settlement risk for trade execution, and help control operational costs. 19

The commodity trading system performs the following major business functions: 20

Supporting purchases and sales of physical commodity deals, capacity deals, 21

transmission deals, natural gas transmission, natural gas storage deals, and 22

financial deals. 23

Monitoring the profit/loss risk for each deal. 24

Performing settlements reconciliation with the counterparty. 25

Generating invoices for all confirmed deals. 26

Interfacing with Power Costs Inc. for the scheduling with CAISO and 27

actualizing volumes. 28

190 Previously called “Commodity Management Platform Phase 2.”

191 Entegrate is the name of an ETRM software system from Sungard.

206

Dynamic position reporting and processing. 1

Reporting aggregated positions and profit and loss by both profit center and 2

portfolio. 3

Supporting mark-to-market calculation on standard power and natural gas 4

deals. 5

Supporting SCE’s Risk Operations and Analytics group to ensure that SCE is 6

compliant with CPUC and internal policies and procedures. 7

Generating confirmations for all deals. 8

The ETRM system also manages conventional bilateral contracts. The current 9

system requires multiple spreadsheet workarounds to handle bilateral tolling contracts. SCE requires an 10

automated system that will support settlement of tolling contracts and preparation of final invoices. The 11

automated system will accommodate three primary functions required to settle a tolling contract: 12

Capturing all contract terms that affect economic calculations. 13

Accessing and capturing external financial and physical data required for 14

settlement. 15

Calculating the expected payment amounts and invoice line items, and 16

generating exception reports on major economic factors. 17


Table VI-61 Capital Forecast Expenditures for Energy Trading and Risk Management System

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ -$ 6,000$ 6,000$ 12,000$

SCE forecasts the ETRM System Replacement will cost $12.0 million.192 This 19

forecast is based on the internal IT application costing model and the details are available in the work 20

paper cited above. 21

192 See workpaper entitled “Forecast Expenditures ETRM System Replacement.”

207




d) Conclusion 4

The ETRM System Replacement project will upgrade or replace the Sungard 5

Entegrate ETRM system and will be able to handle conventional, bilateral contracts and energy 6

commodity products without extensive use of spreadsheet. 7

7. Common Data Store (CDS) and Power Supply Data and Reporting database (PDR) 8

Upgrade 9

a) Background 10

This project will further enhance the capabilities of the current Common Data 11

Store (CDS) and Power Supply Data and Reporting database (PDR) by consolidating dispersed data 12

stores and by adding real-time data acquisition, storage, and reporting. This enhancement will also 13

provide visualization tools and an environment that is isolated and separate from the production 14

environment and can be used for large and/or one-time data retrieval and/or analysis without impacting 15

the performance of the production environment. This is sometimes referred to as a “sandbox” 16

environment. 17

The enhanced CDS/PDR will consolidate certain data sets that are stored in 18

multiple locations into one central location. The enhanced CDS/PDR will provide real-time and time-19

series data for users who currently rely on manual extractions and file exchanges. The enhanced 20

CDS/PDR will provide new reporting tools to permit the graphical representation of information 21

including dashboards. 22


The key business needs addressed by this project are as follows: 24

1. Availability of real-time and time-series data. The current system supports a 25

fixed set of time resolutions, e.g., daily, hourly and five-minute data. This 26

needs to be extended to be able to store non-standard time resolutions 27

including real-time telemetry data, which has a time resolution down to four 28

seconds. Normally a database stores each interval as a separate record, e.g., 29

one record per hour for hourly data. For four-second data this approach 30

generates a large number of records; more efficient data storage approaches 31

208

exist for time series data with fine time resolution. A possible approach is 1

referred to as ‘store on update’ where a record is created for every change in 2

the data value rather than for every interval. For real-time data sources where 3

the input data changes infrequently this is a much more efficient way to store 4

the data in the database. 5

2. Consolidation and centralization of data sources. SCE’s current systems 6

frequently store the same data (e.g., CAISO prices) in multiple databases. A 7

more efficient approach is to consolidate the storage of each data type into a 8

single database and refer to this data from the other systems. This would 9

create a single repository for each type of data and simplify data quality 10

assurance since there is only one source of data to maintain. 11

3. New reporting capabilities through management dashboards. The 12

management dashboards will allow management information and reporting 13

within Power Supply to be readily accessible from a desktop dashboard 14

interface. “Management information” is the analysis of Power Supply data 15

that provides Power Supply management with the information it needs to 16

improve Power Supply operations and make key decisions. Examples of 17

management information may include, but are not limited to: 18

SCE power portfolio vs. load, power/gas contract utilization, for managing 19

SCE’s position. 20

Day-ahead market activity vs. real-time market activity, for managing SCE’s 21

position. 22

SCE’s power procurement and generation compliance costs for renewable or 23

GHG emissions reduction targets. 24

The management dashboard will have the following capabilities: 25

Structured management information based on a common data source. 26

Ensure the integrity of the operational and financial data as it is used for 27

management information and reporting. 28

Provide Power Supply management with desktop access to the management 29

information in near real time. 30

209

Provide desktop access and control for management reporting based on the 1

common data source. 2

Provide data for SCE’s financial and regulatory reports. 3

Provide the ability to monitor user-defined metrics. 4

Provide the means to audit management information and management 5

reporting – tracing management information back to the common data source. 6

This project addresses these business needs by providing new data sets for the 7

internal users at SCE to support the validation of various charges and contracts, the elimination of 8

duplicative data sets and data subscriptions and the provision of new reporting capabilities. 9


Table VI-62 Capital Forecast Expenditures for Common Data Store and Power Supply Data and

Reporting Database (Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ -$ 3,600$ 3,600$ 7,200$

This effort is estimated to be a large complexity, internally developed solution 11

requiring integration with CAISO, Power Costs Inc., and other Power Supply applications. The effort 12

will require additional database and operating system licenses, and additional hardware investments for 13

server and data storage capacity. For detailed cost information of this initiative, see supporting 14

workpaper.193 The total estimated costs of the project are estimated to be $7.2 million. 15

The project start was delayed as part of SCE’s prioritization process of its overall 16

technology spend. It is scheduled to be implemented in 2016 and 2017. 17

d) Conclusion 18

The CDS/PDR Enhancement project will consolidate dispersed data stores and 19

add real-time data acquisition, storage and reporting. The project will also provide visualization tools 20

and a sandbox environment for ad hoc analyses. 21

193 See workpaper entitled “Forecast Expenditures CDS/PDR Enhancement.”

210

8. Usage Measurement System 1

a) Background 2

SCE is mandated to report hourly consumption for all its retail customers to 3

CAISO. SCE’s Power Supply Meter Data Management group is responsible for this reporting 4

requirement. Power Supply currently has a process and the customized Usage Measurement System 5

(UMS) to aggregate Settlement Quality Meter Data (SQMD) and report it to the CAISO each business 6

day. 7

UMS will need to be replaced by a system capable of handling interval data from 8

the Edison SmartConnect® program and customer growth for new accounts. Currently UMS processes 9

close to 5 million monthly meter reads each month. With the new interval Edison SmartConnect® data, 10

UMS will need to process daily meter reads from the SmartMeter system in addition to approximately 11

100,000 monthly metered customer reads from customers without an Edison SmartConnect® meter. 12

The Edison SmartConnect® data cannot currently be processed by UMS. Power Supply relies on the 13

Customer Service System (CSS), Customer Data Acquisition System (CDAS) and Customer Revenue 14

Reporting Information System (CRRIS) for data to calculate SQMD. 15


The availability of retail interval meter data from the Edison SmartConnect® 17

program requires significant changes to Power Supply’s usage aggregation and reporting processes. The 18

current technology and design of UMS will not support the demand of the new Edison SmartConnect® 19

meter interval data. The SCE requirement to submit Settlement Quality Meter Data (SQMD) to the 20

CAISO for the cumulative and interval metered services for each hour of every trade day cannot be 21

supported with the existing UMS system. The CAISO uses the information provided by UMS, along 22

with SQMD from other entities within California, to calculate SCE’s energy charges, imbalance energy, 23

unaccounted for energy as well as other administrative charges. The current system, in addition to 24

having been developed in 1998 and being based on now-obsolete technology, will not support new 25

CAISO requirements related to Demand Response programs and the Edison SmartConnect® interval 26

data. The current system is written in a Sybase-PowerBuilder Pro version that is no longer supported 27

and needs to be rewritten with current development tools and database management system. 28

211


Table VI-63 Capital Forecast Expenditures for Usage Measurement System

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ 1,500$ -$ -$ 1,500$

We forecast the UMS replacement to be $1.5 million. This forecast is based on 2

the internal IT application costing model and the details are available in the workpaper cited above. The 3

current application was developed by SCE as a custom system and the estimates are based on using this 4

approach again, but utilizing the SCE standard integration technology where possible. 5



technology spend. It is now scheduled to be implemented in 2015. 8

d) Conclusion 9

The replacement of SCE’s UMS will provide the ability to handle retail customer 10

interval meter data from the Edison SmartConnect® program and the replacement of obsolete 11

technology with current technology that can be supported going forward. 12

9. Generation Management System 13

a) Background 14

The Generation Management System (GMS) was developed and implemented in 15

2003 to enable SCE’s Trading and Energy Operations personnel to more accurately determine SCE’s net 16

energy position throughout each operating day, thereby improving the opportunity to lower energy costs 17

to its customers. 18

GMS supports SCE’s goal to minimize costs to its customers by providing real-19

time information for Qualifying Facilities (QF), conventional and renewable power production and 20

enabling SCE to update hour-ahead schedules as needed for generation deviations from planned 21

schedules. GMS’ functionality allows Power Supply operations personnel to perform and monitor the 22

following: Automated Generation Control (AGC); telemetry data; schedules from the Power Costs Inc. 23

system; dynamic schedules information; CAISO scheduling information; energy trader information; real 24

212

time data from various locations; calculation of net short positions; and adjustment of hour-ahead 1

schedules based on generation status. 2

The implementation of GMS has allowed Power Supply operations personnel to 3

monitor the performance of generating units and to adjust CAISO hour-ahead schedules, thereby 4

reducing both negative and positive energy deviations (i.e., uninstructed energy) in the CAISO’s real-5

time energy market. This reduction has, in turn, resulted in reductions in CAISO charges for imbalance 6

(uninstructed) energy, as well as charges for ancillary services and grid management. 7


Each operating day, through its day-ahead and hour-ahead transactions, Power 9

Supply attempts to minimize SCE’s residual net short and residual net long positions in the CAISO’s 10

real-time market to avoid CAISO charges for energy imbalances (i.e., the difference between energy 11

scheduled and actual energy needed in real time to serve customer load). This requires Power Supply to 12

have reliable access to real-time system data used in assisting Power Supply personnel who schedule 13

energy with the CAISO. A technology-related failure due to obsolescence would jeopardize Power 14

Supply ability to schedule energy with the CAISO. The system operates in real-time, responding 15

immediately to market fluctuations. If it were to stop functioning, the ability to capture market changes 16

would be lost and SCE would have to perform these real-time functions manually. 17

The number of data connections to power plants is currently 51, which is above 18

what the original system was designed for (25). The existing system can handle the current number of 19

connections with some workarounds. New connections are continuously being added to support more 20

renewable power plants as they come online as part of contracts that were signed to support the state’s 21

33percent renewable portfolio goal, including at least 11 more connections to be added in 2013. 22

GMS is a customized solution built around various software packages as a system 23

from Invensys, PLC (a provider of specialized software solutions to the utility industry). GMS consists 24

of several modules including InTouch (human-machine interface) trending and analysis software, and, 25

the software communications protocol. 26

All these applications have to be upgraded together because GMS is an integrated 27

set of applications. This is a complex system that requires redundant infrastructure where separate sets 28

of computer servers are located in physically separate locations. 29

The GMS system is classified as a NERC Critical Cyber Asset and is subject to 30

NERC Critical Infrastructure Protection (CIP) regulations. 31

213


Table VI-64 Capital Forecast Expenditures for Generation Management System

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

1,500$ 194$ -$ -$ -$ 1,694$

SCE forecasts the Generation Management System will cost $1.694 million. The 2

project estimation is based on the historical cost of the capitalized software for implementing GMS in 3

2003 using a Commercial Off The Shelf (COTS) software package with modifications. The project 4

forecast cost details are available in the attached workpaper.194 5

The project start was delayed as part of SCE’s prioritization process of its overall 6

technology spend. It is scheduled to be implemented in early 2014. 7

d) Conclusion 8

The upgrade of SCE’s Generation Management System will provide the 9

following: 10

Upgrade the existing system to current vendor software versions. 11

Increase the capacity for telemetry connections to renewable generators. 12

Lower future costs for the configuration of each generator connection. 13

10. Aggregated Demand Response 14

a) Background 15

The CPUC has encouraged the growth of demand response programs in order to 16

enhance electric system reliability, reduce power purchases and protect the environment. In D.05-11-17

009, the CPUC developed a strategy and initiated programs to promote demand response. In proceeding 18

A.05-05-006, the CPUC adopted programs and goals for demand response for SCE and the other 19

California energy Investor Owned Utilities. 20

Demand response currently constitutes between one and two percent of SCE’s 21

portfolio. SCE anticipates that demand response will become a more significant factor in determining 22

overall power requirements as customers respond to new dynamic load management rates and programs 23

that the implementation of advanced meters in SCE’s service territory will make possible. Load 24

194 See workpaper entitled “Forecast Expenditures Generation Management System.”

214

aggregators are now allowed to create demand response blocks from individual consumers participating 1

in the aggregation programs. An effective demand response program will become the equivalent of a 2

significant dispatchable generation resource. 3

In R.07-01-041, the CPUC required demand response programs be integrated into 4

the CAISO markets. Under the market rules of CAISO, the location of the demand response impact will 5

affect SCE’s power costs due to Locational Marginal Pricing, as well as SCE costs for congestion 6

management and Resource Adequacy (RA). Power Supply must be able to accurately track and model 7

how demand response is impacting SCE’s net power need in order to effectively manage its energy 8

procurement for its customers. 9


The CPUC has required SCE to develop a plan for integrating demand response 11

into the CAISO markets. Additionally, CAISO requires SCE to provide demand forecast information 12

into its market to mimic generation resources. Power Supply will require analytical tools to operate in 13

the CAISO market with aggregate demand response as a dispatchable resource. 14

The Aggregated Demand Response application will provide the following 15

functions: 16

Define demand response resources that can be bid into the CAISO market. 17

From a CAISO perspective, demand response can be thought of as a 18

generator, except that instead of producing energy it reduces the demand for 19

energy. This reduction is sometimes calculated in ‘megawatts,’ meaning 20

negative megawatts. CAISO refers to these demand response resources as 21

Proxy Demand Resources (PDR). SCE will define PDRs to represent its 22

various demand response programs and customers in different geographic 23

areas. 24

Forecast the megawatt capacity of the demand response resources. Every day, 25

SCE needs to develop a resource plan for its demand response resources. This 26

resource plan will forecast how much demand response capacity is available 27

for the next day as well as the cost of that capacity. The capacity and price 28

will depend on the retail demand response programs that are included in the 29

specific demand response resource. 30

215

Develop bids for each demand response resource and submit these bids to the 1

CAISO markets. 2

Retrieve awards from CAISO for the demand response resources and translate 3

these awards into instructions to the retail demand response participants. This 4

function is complicated by the fact that a bid can be partially awarded by 5

CAISO. For example, if a demand response resource represents 1,000 retail 6

customers participating in the Summer Discount Plan program (also called the 7

AC Cycling program), the bid submitted to CAISO is for 2MW and CAISO 8

awards 1MW to the resource in the auction, the Aggregated Demand 9

Response system needs to determine which retail customers will be told to 10

reduce their load, by how much and for how long. 11

Monitor performance. Since demand response program participants get paid 12

for reducing their consumption, the Aggregated Demand Response system 13

needs to monitor the demand response resources to validate that participating 14

customers actually reduce their consumption when instructed to do so. 15

Perform settlements. Calculate data (including performance data) for 16

submission to CAISO and validate CAISO settlement payments and charges. 17


Table VI-65 Capital Forecast Expenditures for Aggregated Demand Response

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ 4,150$ 1,400$ 250$ 5,800$

Funding needs for the Aggregated Demand Response project are expected to be 19

$5.80 million.195 This forecast is based on the internal IT application costing model and the details are 20

available in the workpaper cited above. 21

The project start was delayed due to uncertainty around the details of the FERC 22

rules for demand performance in ISO markets. The project was also part of SCE’s prioritization process 23

of its overall technology spend. It is scheduled to be implemented in 2015 through 2017. 24

216

d) Conclusion 1

The implementation of SCE’s Aggregated Demand Response project will provide 2

the following: 3

Meet CPUC and CAISO requirements on demand response. 4

Treat aggregated demand response resources as a significant supply resource 5

for SCE’s portfolio. 6

Provide SCE with the capabilities to bid demand response resources into the 7

CAISO market. 8

11. Market System Replacement 9

a) Background 10

During the MRTU project in 2006-2009, the existing Power Supply planning and 11

operational systems were replaced with new vendor systems. These systems manage SCE’s 12

participation in the CAISO energy market, including planning the operations of our generating assets 13

and bilateral contracts, submitting bids and retrieving prices and market awards from CAISO, and 14

validating the settlement statements and invoices received from CAISO. Since installation of these 15

systems, multiple market enhancements have been implemented by CAISO, the software vendor 16

landscape has changed (several vendors have merged and significant product development has been 17

done by multiple vendors), and SCE has accumulated significant operating experience with the new 18

tools. There are unresolved issues with some of the systems that need to be addressed by replacing these 19

systems with other (newer) vendor products. Issues include lack of ability to keep up with CAISO 20

market changes, system performance, and limited functionality for analytics. 21


SCE market systems must have the following characteristics: 23

Ability to run market simulations. CAISO market changes are implemented 24

through a cycle consisting of stakeholder processes to design the market 25

changes, workshops to review the detailed technical design of the market 26

changes, market simulation of the changes, and finally go-live where the 27

changes are implemented in the production environment. The purpose of 28

market simulation is for both CAISO and market participants (including SCE) 29

195 See workpaper entitled “Forecast Expenditures Aggregated Demand Response.”

217

to test the new market changes using as close to the actual systems and 1

business processes as possible. SCE has on several occasions in the past had 2

to do market simulations using manual workarounds instead of the actual 3

software since our vendors have not been able to deliver software updates in 4

time for the CAISO market simulations. 5

Adequate performance in the SCE environment with data volumes as required 6

by CAISO. CAISO data volumes have increased dramatically after MRTU 7

went live. As with SCE’s Common Data Store system, SCE has seen issues 8

where some vendor systems struggle to retrieve and process the CAISO data 9

volumes in a timely manner. 10

Better functionality for analytics. Analytics is increasing in importance as the 11

CAISO market grows more complex and the portfolio of renewable power 12

continues to grow. Good analytics depend on access to updated and relevant 13

data that is easy to retrieve using a variety of data reporting and analysis tools. 14

SCE has experienced issues where data is stored in the current vendor 15

databases in a format that is either inaccessible or hard to retrieve and analyze 16

using reporting and analysis tools. 17


Table VI-66 Capital Forecast Expenditures for Market Systems Replacement

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ -$ 3,000$ 2,800$ 5,800$

SCE forecasts the Market Systems Replacement project will cost $5.8 million. 19

The project estimation is based on the historical cost for the capitalized software for implementing the 20

existing system in 2009 using a Commercial Off The Shelf (COTS) package with modifications. The 21

project forecast cost details are available in the attached work paper.196 The project will be implemented 22

in 2016 and 2017. 23

196 See workpaper entitled “Forecast Expenditures Market Systems Replacement.”

218

d) Conclusion 1

The Market Systems Replacement project provides better functionality, 2

performance and ability to keep up with CAISO market initiatives. 3

12. Fundamental Modeling Platform 4

a) Background 5

Power Supply at SCE relies on several fundamental power production simulation 6

models to estimate dispatch for utility owned and contracted generation, forecast prices, and analyze 7

market impacts of generation and transmission outages. 8

Fundamental modeling requires extensive and detailed data on generation 9

characteristics and costs, transmission topology and intertie imports. Consistent assumptions and input 10

data in the fundamental modeling efforts are crucial in order to get reliable results from the models. 11

These results are used to enhance SCE’s forecasting capabilities to improve power procurement 12

decisions since they allow SCE to study various expected or potential market scenarios and prepare 13

procurement or bidding strategies for these scenarios before they occur. 14

SCE has an in-house software tool called Fundamental Model Automation (FMA) 15

to partially automate the collection and maintenance of the data needed for simulations. The required 16

data includes detailed characteristics for all power plants within California or the WECC area as well as 17

detailed capacities (and outages) for all transmission lines within the CAISO control area or the West-18

wide WECC area. The FMA tool still requires significant manual efforts to validate and edit the data 19

and currently support only one fundamental model. The proposed “Fundamental Modeling Platform” 20

will enhance the existing FMA system capability to collect and maintain all input data for the 21

fundamental simulation models, ensure that consistent data is used cross the models, support the use of 22

multiple fundamental models, and store the key output from the models. By improving the process and 23

reducing the time and workload for simulations, the Fundamental Modeling Platform software can be 24

used to assist SCE’s participation in the CAISO day-ahead market. 25


Fundamental modeling is used to predict prices and production levels for 27

generators across a large geographical area, such as California or the West-wide WECC area. 28

Fundamental models require extensive and detailed data on generation characteristics and costs, 29

transmission topology and intertie imports. 30

219

The proposed Fundamental Modeling Platform will perform the following 1

functions: 2

Enhance the collection and maintenance of all input data for needed by 3

fundamental simulation models. This includes the transmission network 4

topology for the entire WECC area, detailed operational and cost data for 5

generation facilities across WECC, detailed operational data about intertie 6

facilities across WECC and load forecasts for the various load serving entities 7

across WECC. 8

Support multiple fundamental simulation models. The current system 9

supports only a single fundamental simulation model. Adding support for 10

multiple simulation models from different vendors would allow SCE to 11

benchmark different models against each other and use the outputs from 12

multiple models to produce a blended forecast that is based on the strengths of 13

each model. 14

Assure the consistent data is used across the models. Fundamental models 15

require extensive sets of input data. Different models use similar types of 16

input data (e.g., transmission outages), but may require the data in slightly 17

different formats. Using a manual process to prepare the different sets of 18

input data is burdensome and error-prone. By automating the preparation of 19

input data sets to the different models SCE can ensure that consistent input 20

data sets are constructed from a single set of base data. 21

Store the key output from the models. Fundamental models produce large and 22

detailed output data sets containing prices for each node in the system as well 23

as output levels for each generator and flows for each transmission line. 24

Manual collection and comparison of output results from different runs of the 25

same model and from different models is burdensome due to the amount of 26

data produced by the models. By storing the outputs from each model run in a 27

common database format SCE can easily retrieve and compare results from 28

different runs and models. 29

The proposed Fundamental Modeling Platform will have several benefits: 30

220

Support SCE’s Long-Term Procurement Plan (LTPP) and other power 1

procurement activities in the regulatory arena 2

Significantly improve the process and reduce the time for simulations 3

Make it possible to benchmark different models and combine the outputs from 4

different models to achieve the better results for procurement decisions 5


Table VI-67 Capital Forecast Expenditures for Fundamental Modeling Platform

(Nominal $000)

2013 2014 2015 2016 2017Total

Forecast

-$ -$ 750$ 750$ -$ 1,500$

SCE forecasts the Fundamental Modeling Platform will cost $1.50 million.197 7

This forecast is based on the internal IT application costing model and the details are available in the 8

workpaper cited above. The project will be implemented in 2015 and 2016. 9

d) Conclusion 10

The proposed Fundamental Modeling Platform will enable SCE to collect and 11

maintain all input data for multiple fundamental simulation models, assure the consistent data is used 12

across the models, and store the key output from the models.13

197 See workpaper entitled “Forecast Expenditures Fundamental Modeling Platform.”

Appendix A

Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF JOHN BUBB 3

Q. Please state your name and business address for the record. 4

A. My name is John Bubb, and my business address is 2244 Walnut Grove Avenue, Rosemead, 5

California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Principal Manager for the Edison SmartConnect® Operations Center in the Customer 8

Service Operating Unit (CSOU). I am responsible for planning, monitoring, operating and 9

maintaining the Edison SmartConnect® metering and communications system to ensure overall 10

integrity and operational efficiency. The Edison SmartConnect® Operations Center is the 11

central point of accountability for the Edison SmartConnect® meter and communications system 12

operation and performance and provides the overall communications and coordination function 13

for the business and operational environment. The center drives improvements by employing 14

analytics, end-to-end diagnostics and analysis, process improvement and related system 15

enhancements for nearly five million end-points. 16

Q. Briefly describe your educational and professional background. 17

A. I earned a Bachelor of Science in Electrical and Computer Engineering from the University of 18

Colorado, Boulder in 1985. My professional experience includes over 26 years of utility 19

engineering and operations experience in telecommunications, computer networking, embedded 20

systems, and product management. I’ve held a variety of positions throughout my career in 21

engineering and as a leader in systems architecture. Since 2008, I’ve served as Manager of 22

Product Management, and Manager of Edison SmartConnect® Operations Center. 23

Q. What is the purpose of your testimony in this proceeding? 24

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-05, 25

Volume 2, Part 1, entitled Information Technology – Capitalized Software as identified in the 26

Table of Contents thereto. 27

Q. Was this material prepared by you or under your supervision? 28

A. Yes, it was. 29

Q. Insofar as this material is factual in nature, do you believe it to be correct? 30

A. Yes, I do. 31

A-2

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 1

judgment? 2

A. Yes, it does. 3

Q. Does this conclude your qualifications and prepared testimony? 4

A. Yes, it does. 5

A-3



OF CARLOS CARAZO 3


A. My name is Carlos Carazo, and my business address is 4910 Rivergrade Road, Irwindale, 5

California 91706 6


A. I am the Director of Grid Services in the Information Technology Services Division within the 8

Information Technology organizational unit of Southern California Edison (SCE). Grid Services 9

designs, engineers, installs, operates, reports, and maintains the voice, data, and 10

telecommunications networks for SCE. This division manages, operates, and maintains SCE’s 11

communication network to ensure the communication infrastructure is available 24 hours a day, 12

365 days a year. Grid Services is also responsible for SCE’s SCADA systems. 13


A. I received my Bachelor of Science degree in Computer Information Systems from California 15

State Polytechnic University, Pomona. I joined SCE in 1989 as a part-time business trainee in 16

the Network Installations department within Information Technology (IT), and became a full-17

time Desktop Support Manager in 1996. Other positions I’ve held within IT include Project 18

Manager for several high-profile projects. In 2000, I became the Manager of 19

Telecommunication Special Projects, and in 2005, the Manager of Telecommunications 20

Advanced Technology Planning and Client Services. In 2006, I became General Manager of 21

Network Services within Information Technology – Operations. In 2010, I became Director of 22

Network and Telecommunications Services within IT Infrastructure Services; I presently hold 23

the same position, however, the name of the department has been changed to Grid Services. 24



Volume 1, entitled Information Technology – Overview, O&M and Capital, and portions of 27

Exhibit SCE-05, Volume 2, Part 1, entitled Information Technology – Capitalized Software as 28

identified in the Table of Contents thereto. 29


A. Yes, it was. 31

A-4


A. Yes, I do. 2


judgment? 4

A. Yes, it does. 5


A. Yes, it does. 7

A-5



OF JAY A. CASTLEBERRY 3


A. My name is Jay A. Castleberry, and my business address is 4910 Rivergrade Road, Irwindale, 5

California 91706. 6


A. I am the Director of Technology Delivery and Maintenance. In this capacity, I am responsible 8

for the diverse organization providing software solutions for Customer Service, Energy 9

generation and procurement, Transmission and Distribution, Human Capital Management, 10

Enterprise Asset Management, Finance, Compliance, Security, Legal, and Solution Delivery 11

management to our business partners within Southern California Edison. 12


A. I received my B.S., Business Administration and Hotel/Restaurant Management from California 14

State Polytechnic University-Pomona in 1990. I have worked for Southern California Edison for 15

1 year. Before joining Southern California Edison, my more recent positions included 16

Information Technology Executive at Ciber from 2008 to 2012, Director of Business 17

Intelligence, Data Warehousing and CRM at Lennar from 2007 to 2008, Director of 18

Infrastructure, Technical and Network Services at Fleetwood Enterprises from 2002 to 2007. 19

Effective August 1, 2012, I assumed the position of Director for Technology Delivery & 20

Maintenance. 21






A. Yes, it was. 27


A. Yes, I do. 29


judgment? 31

A-6

A. Yes, it does. 1


A. Yes, it does. 3

A-7



OF GLENN HADDOX 3


A. My name is Glenn Haddox, and my business address is 4910 Rivergrade Road, Irwindale, 5

California 91706. 6


A. I am the director of the Cybersecurity & IT Compliance organization in IT. I am responsible for 8

information security activities designed to protect information and technology assets. I also lead 9

SCE’s information security governance activities, including regulatory watch, risk assessment, 10

policy development and compliance, security strategy and programs, and incident response and 11

forensics. 12


A. I have served in a variety of management and leadership roles, primarily in the Defense industry. 14

Overall, I have 30 years of DoD background at Top Secret Level in Cyber, Intelligence, 15

Cryptology, and Communications. Prior to joining SCE in May 2012, I was director of 16

cybersecurity for Honeywell, where I was responsible for overall guidance and direction of 17

cybersecurity. Prior to that, I was employed at Ultra Prologic as the vice president for Command, 18

Control, Communications, Computers, and Intelligence (C4I). I have extensive experience in 19

cryptology, technical and product offerings, International Traffic in Arms Regulations (ITAR) 20

control, team composition, training and mentoring programs, CMMI 3, and ISO 9001. I earned 21

my Bachelor of Science degree in Organic Chemistry from Armstrong State University in 22

Savannah, Georgia and attended a number of technical schools as an officer in the U.S. Navy. 23







A. Yes, it was. 30


A-8

A. Yes, I do. 1


judgment? 3

A. Yes, it does. 4


A. Yes, it does.6

A-9



OF CHARLIE C. HU 3


A. My name is Charlie Hu, and my business address is 1551 W. San Bernardino Road, Covina, CA 5

91722. 6


A. I am the Director for the Revenue Services Organization within Customer Service. I am 8

responsible for the planning, strategy and operations for Southern California Edison’s revenue 9

services organization. Revenue Services Organization is responsible for billing, payment, credit 10

and collection, program service activities including postage oversight for all our customers. 11


A. I hold a Bachelor of Science (B.S.) degree in Computer Science from California State University 13

of Los Angeles. I completed the Management Program from Columbia University Graduate 14

School of Business and various graduate classes from Pepperdine University. I have worked for 15

Southern California Edison for over twenty two years. I was in the Information Technology 16

organization the first six years where I held positions with increasing responsibility involving 17

system development and implementation of our current billing system. The last sixteen years 18

include leadership roles involving implementation of various major initiatives in Customer 19

Service with focus in the areas of customer service, metering, meter reading, field services, 20

billing, and revenue collections. I’ve also held leadership positions within Revenue Services 21

Organization including Credit and Payment Services and Usage and Billing Group. 22






A. Yes, it was. 28


A. Yes, I do. 30

A-10


judgment? 2

A. Yes, it does. 3


A. Yes, it does. 5

A-11

SOUTHERN CALIFORNIA EDISON COMPANY

QUALIFICATIONS AND PREPARED TESTIMONY

OF GEORGETTE HUCKABY


A. My name is Georgette Huckaby, and my business address is 2244 Walnut Grove Avenue, 2

Rosemead, California 91770. 3


A. I am the Director of Finance, Support Organizations and I have responsibility for the centralized 5

financial interface with Information Technology, Human Resources, Operations Support, and 6

External Relations. 7


A. I graduated from California State University, Dominguez Hills in 1995 with a Bachelor of 9

Science degree in business with an accounting concentration. My experience prior to joining 10

SCE includes 11 years at Northrop Grumman Corporation. At Northrop Grumman, I held the 11

positions of financial analyst and accountant in Overhead Administration, General Accounting, 12

and Accounting Systems. I joined SCE in 1995 as a business analyst and was promoted to 13

Manager of CSBU Finance in 2000 where I was responsible for the development of CSBU’s 14

O&M, capital, and OOR forecasts and financial support in the 2003 and 2006 GRC. In 2009, I 15

was promoted to CSBU Director of Finance and Administration. In late 2012, I assumed my 16

current position. 17






A. Yes, it was. 23


A. Yes, I do. 25


judgment? 27

A. Yes, it does. 28

A-12


A. Yes, it does. 2

A-13



OF JASON M. ‘JAY’ KELLY 3


A. My name is Jason Michael Kelly, and my business address is 4910 Rivergrade Road, Irwindale, 5

California 91706. 6


A. I am Director of IT Enterprise Information Management & Architecture, which includes 8

Enterprise Information Management, Enterprise Data Management, and Enterprise Architecture. 9

I am responsible for leadership and strategic direction of the organization which maximizes the 10

value of SCE technology investments through the development and utilization of information 11

and data management services, strategic architectures, technology roadmaps and innovative 12

designs. 13


A. I have a degree in computer engineering from the University of Washington, over 20 years of IT 15

experience, and a broad range of industry experience including utilities, high-tech, automotive, 16

and media. My experience at SCE has included serving as general manager responsible for data 17

architecture and design services for IT projects. I also managed architecture and engineering 18

services for the company’s SAP application footprint. Before joining SCE in 2007, I worked as a 19

senior technical solution architect with SAP and a product manager for Microsoft. 20







A. Yes, it was. 27


A. Yes, I do. 29

A-14


judgment? 2

A. Yes, it does. 3


A. Yes, it does. 5

A-15



OF LORENE M. MILLER 3


A. My name is Lorene M. Miller, and my business address is 6060 N. Irwindale Ave., Suite E, 5

Irwindale, California 91702. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE). 7

A. I serve as Director of Business Transformation, responsible for leading major technology-8

enabled programs and overseeing the portfolio of system enhancement investments for the 9

Customer Service Operating Unit. 10


A. I hold a Bachelor of Science Degree in Computer Science from California State University at 12

Los Angeles and a Master of Science degree in Leadership and Management from the University 13

of La Verne. I have been employed at Southern California Edison (SCE) for over twenty three 14

years. My experience at SCE includes systems analysis and application development in the 15

Information Technology department and over eighteen years of leadership experience in project 16

and operations management in the Customer Service and Information Technology areas. I was 17

the senior manager of the Billing Organization responsible for metering, billing, payment, and 18

credit management of SCE’s end-use customers from 2000-2003. In December 2003, I was 19

promoted to Director of Business Process & Technology Integration for Customer Service and 20

from 2006 through 2008. I was Director of the Program Management Office of the Enterprise 21

Resource Planning project responsible for project scope and deliverables for the largest utility 22

implementation of SAP software. From February 2008 through April 2013 I was Director of the 23

Customer Communication Organization responsible for planning, strategy and operations of 24

SCE’s Customer Contact Center. I assumed my current position in April 2013. 25






A. Yes, it was. 31

A-16


A. Yes, I do. 2


judgment? 4

A. Yes, it does. 5


A. Yes, it does. 7

A-17



OF RICK PARK


A. My name is Richard L. Park. My business address is 8631 Rush St., Rosemead, CA 91770. 2


A. I am presently the Director of the Corporate Real Estate Department. In this capacity I have 4

responsibility for the strategy, planning, asset management and operation of SCE’s non-electric 5

facility portfolio which is composed of 6.0+ million square feet of offices, service centers, 6

warehouses and specialty facilities. 7


A. I hold a Bachelor of Science degree in Construction Management from Oklahoma State 9

University and the Certified Facilities Manager designation from the International Facilities 10

management Association. Prior to joining SCE I was employed by Bechtel Corporation as a 11

project controls engineer. I have been employed by SCE since 1984. I began my SCE career as 12

a project controls engineer in the nuclear organization and subsequently moved into management 13

positions in the facilities and supply chain areas. In the course of these assignments I had 14

extensive experience managing the strategy, planning and operation of SCE’s facilities and 15

supply chain operations. 16






A. Yes, it was. 22


A. Yes, I do. 24


judgment? 26

A. Yes, it does. 27


A-18

A. Yes, it does. 1

A-19



OF JOHN MATHEW PESPISA


A. My name is John Mathew Pespisa and my business address is 8631 Rush Street, Rosemead, 2

California 91770. 3

Q. Briefly describe your present responsibilities at Southern California Edison Company (SCE). 4

A. I am Director of the NERC Compliance Program in the Safety, Security and Compliance 5

Operating Unit. In this capacity, I oversee corporate NERC Compliance governance functions, 6

oversee SCE’s compliance with federal Reliability Standards, which have been promulgated to 7

ensure the safe, reliable operation of the power grid, and to protect the grid’s critical 8

infrastructure against cyber threats. 9


A. I am a graduate of Cal State Los Angeles and hold degrees in Electrical Engineering and 11

Business Management. I began my career with Southern California Edison in 1987, starting in 12

transmission operations and electrical substations. Since then I have worked in positions 13

including the operation of SCE’s bulk electric and distribution systems, and supervisory 14

positions at SCE’s Energy Control Center, including Manager of short term power marketing, 15

and Manager of Real-Time Power Operations. I assumed my current position in November of 16

2011 as the Director of SCE’s NERC Compliance Program. 17






A. Yes, it was. 23


A. Yes, I do. 25


judgment? 27

A. Yes, it does. 28

A-20


A. Yes, it does. 2

A-21



OF JAMES P. SCOTT SHOTWELL 3


A. My name is James P. Scott Shotwell, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6


A. I am the Director and Deputy Ethics & Compliance Officer. I am responsible for the 8

implementation and operation of the Company’s Compliance Management Program, along with 9

the Records Management, Policy Management, and Privacy Compliance Programs. 10


A. I hold a Bachelor of Science (B.S.) degree in Economics from Arizona State University and a 12

Juris Doctorate from the University of Arizona College of Law. I have worked for Southern 13

California Edison for over 22 years. Prior to accepting my current position in 2009, I worked in 14

Southern California Edison’s Washington, D.C. office, where I served as the primary liaison 15

between SCE and the Federal Energy Regulatory Commission. Previously, I was a Senior 16

Attorney with the Company, practicing chiefly before the California Public Utilities 17

Commission. 18


A. The purpose of my testimony in this proceeding is to sponsor portions of SCE-05, Volume 2, 20

Part 1, entitled Information Technology - Capitalized Software as identified in the Table of 21

Contents thereto. 22


A. Yes, it was. 24


A. Yes, I do. 26


judgment? 28

A. Yes, it does. 29


A. Yes, it does.31

A-22



OF JOANNE TRAN 3


A. My name is Joanne Tran, and my business address is 2244 Walnut Grove Avenue, Rosemead, 5

California 91770. 6


A. I currently hold the position of Director of SCE’s Settlements and Operations Services 8

Department. I have held this position since March 2013. Settlements and Operations Services 9

Department major responsibilities include: settling of complex bilateral conventional and 10

renewable power transactions, physical and financial gas transactions, transmission and GHG 11

products, and complex Independent System Operator market transactions, managing CAISO 12

disputes; providing data to support contract litigations; developing and documenting business 13

processes; managing large-scale technology implementation to support front-office operations; 14

managing information and data functions including acquisition and reporting of meter data to 15

CAISO; providing administrative support for power procurement. 16


A. I earned a Bachelor of Science degree in Business Administration, majoring in Accounting, from 18

California State University, Los Angeles in 1994. I received Certified Management Accountant 19

and Certified Financial Management designations in 1995. In 1998, I received a Certified Public 20

Accountant designation in the State of California. Following my graduation from business 21

school, I joined Southern California Gas Company from 1994 to 2005 where I held various 22

positions in Cost Accounting, Audit Services, Financial and Budgeting, and Gas Acquisition 23

departments. In 2005, I joined SCE’s Gas Trading group as a Senior Financial Gas Trader and 24

was promoted to Manager of Gas Trading in 2009. In 2011, I became the Manager of 25

Accounting and Reporting group in SCE’s Power Supply Finance department. I have over 19 26

years of experience in various aspects of the energy industry including utility accounting, utility 27

auditing, gas procurement, and risk management. I have previously testified before the 28

California Public Utilities Commission. 29


A-23





A. Yes, it was. 5


A. Yes, I do. 7


judgment? 9

A. Yes, it does. 10


A. Yes, it does. 12