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(U 338-E)

2018 General Rate Case A.16-09-_____

Workpapers

IT- Capital Software (OU Software Projects) SCE-04 Volume 02, Book C

September 2016

2018 General Rate Case Index of Workpapers

SCE-04, Vol.02 Book A

DOCUMENT PAGE(S)Operating Unit Summary - Operating Software, Cybersecurity, and Technology Consolidation & Optimization 1-4

2015 Cap Software Authorized vs Recorded Table 5-6 Operating System Software 7-43

Operating Software Project Detail Worksheet 8-10 Investment Memo – Operating System 11-15 2018 GRC IT Capital Estimates – Operating System 16 Database Platform Upgrade Project Detail Worksheet 17 Investment Memo - Database Platform Upgrade 18-20 2018 GRC IT Capital Estimates - Database Platform Upgrade 21 System D Replacement Project Detail Worksheet 22 Investment Memo - System D Replacement 23-27 Business Intelligence Project Detail Worksheet 28 Investment Memo - Business Intelligence 29-31 2018 GRC IT Capital Estimates - Business Intelligence 32 Enterprise Integration Tools Project Detail Worksheet 33 Investment Memo - Enterprise Integration Tools 34-36 2018 GRC IT Capital Estimates - Enterprise Integration Tools 37 SAP Core Refresh Project Detail Worksheet 38 Investment Memo - SAP Core Refresh 39-42 2018 GRC IT Capital Estimates - SAP Core Refresh 43

Massive breach at health care company Anthem Inc. 44-46 Hidden costs of Sony’s data breach will add up for years, experts say 47-50 The eBay data compromise: What you need to know 51-53 Neglected Server Provided Entry for JPMorgan Hackers - The New York Times 54-57

Inside the Cunning, Unprecedented Hack of Ukraine’s Power Grid 58-63 Recommended Practice: Improving Industrial Control Systems Cybersecurity with Defense-In-Depth Strategies 64-108

Perimeter Defense 109-120 Perimeter Defense Project Detail Worksheet 110 Investment Memo - Perimeter Defense 111-113 2018 GRC IT Capital Estimates - Perimeter Defense 114

The U.S. Power Grid Is Under Near Continuous Attack 115-116 Defending an Undefinable Cyber Security Perimeter 117-120 Interior Defense 121-126

Interior Defense Project Detail Worksheet 122 Investment Memo - Interior Defense 123-125

DOCUMENT PAGE(S)2018 GRC IT Capital Estimates - Interior Defense 126

Spoiler Alert: 10 Business Technology Trends You'll Read About in 2014 127-131 Data Protection 132-137

Data Protection Project Detail Worksheet 133 Investment Memo - Data Protection 134-136 2018 GRC IT Capital Estimates - Data Protection 137

SCADA Cybersecurity 138-140 SCADA Cybersecurity Project Detail Worksheet 139 2018 GRC IT Capital Estimates - SCADA Cybersecurity 140

Targeted Attacks Against the Energy Sector 141-170 Russian hackers suspected in attack that blacked out parts of Ukraine 171-173 Common Cybersecurity Services (CCS) for Generator Interconnections 174-179

CCS for Generator Interconnections Project Detail Worksheet 175 Investment Memo – CCS for Generator Interconnections 176-178 2018 GRC IT Capital Estimates - CCS for Generator Interconnections 179

Grid Modernization Cybersecurity 180-186 Grid Modernization Cybersecurity Project Detail Worksheet 181 Investment Memo – Grid Modernization Cybersecurity 182-185 2018 GRC IT Capital Estimates - Grid Modernization Cybersecurity 186

NERC CIP Compliance 187-208 NERC CIP Compliance Project Detail Worksheet 188-191 2018 GRC IT Capital Estimates - NERC CIP Compliance Project 192 Investment Memo – NERC CIP 006 PSP for Low Impact Facilities 193-1962018 GRC IT Capital Estimates - NERC CIP 006 PSP for Low Impact Facilities 197

Investment Memo – NERC CIP 0014 Program 198-2022018 GRC IT Capital Estimates - NERC CIP 0014 Program 203Investment Memo – Test Smart Form Tool 204-207 2018 GRC IT Capital Estimates - Test Smart Form Tool 208

Data Warehouse Consolidation 209-217 Data Warehouse Consolidation Project Detail Worksheet 210-211 Investment Memo – Data Warehouse Consolidation 212-216 2018 GRC IT Capital Estimates - Data Warehouse Consolidation 217

Lotus Notes Migration 218-223 Lotus Notes Migration Project Detail Worksheet 219 Investment Memo – Lotus Notes Migration 220-222 2018 GRC IT Capital Estimates - Lotus Notes Migration 223

Backup and Disaster Recovery Optimization 224-229 Backup and Disaster Recovery Optimization Project Detail Worksheet 225 Investment Memo – Backup and Disaster Recovery Optimization 226-228 2018 GRC IT Capital Estimates - Backup and Disaster Recovery Optimization 229

DOCUMENT PAGE(S)Information Technology OU Projects less than $3M 230-262Enterprise Scheduler Consolidation 231-235

Enterprise Scheduler Consolidation Project Detail Worksheet 231 Investment Memo – Enterprise Scheduler Consolidation 232-234 2018 GRC IT Capital Estimates - Enterprise Scheduler Consolidation 235

Database Backup Optimization 236-241 Database Backup Optimization Project Detail Worksheet 236 Investment Memo – Database Backup Optimization 237-240 2018 GRC IT Capital Estimates - Database Backup Optimization 241

Citrix VDI Capacity Increase 242-246 Citrix VDI Capacity Increase Project Detail Worksheet 242 Investment Memo – Citrix VDI Capacity Increase 243-245 2018 GRC IT Capital Estimates - Citrix VDI Capacity Increase 246

User Experience Technologies 247-251 User Experience Technologies Project Detail Worksheet 247 Investment Memo – User Experience Technologies 248-250 2018 GRC IT Capital Estimates - User Experience Technologies 251

Application Distribution 252-257 Application Distribution Project Detail Worksheet 252 Investment Memo – Application Distribution 253-256 2018 GRC IT Capital Estimates - Application Distribution 257

Modernize Tools for Software Development 258-262 Modernize Tools for Software Development Project Detail Worksheet 258 Investment Memo – Modernize Tools for Software Development 259-261 2018 GRC IT Capital Estimates - Modernize Tools for Software Development 262


SCE-04, Vol.02 Book B

DOCUMENT PAGE(S)Customer Service Capitalized Software Projects 1-73 SCE.com Strategic Upgrade/Stabilization 6-8

SCE.com Project Detail Worksheet 7 2018 GRC IT Capital Estimates - SCE.com 8

Digital Customer Self Service 9-30 Digital Customer Self Service Project Detail Worksheet 10 Investment Memo - Digital Customer Self Service 11-17 Digital Customer Self Service Benefit-Cost Analysis 18-20 2018 GRC IT Capital Estimates - Digital Customer Self Service 21 Mary Meeker, “Internet Trends 2015 – Code Conference,” Kleiner Perkins Caufield & Byers, May 27, 2015, page 123 22-23

Francesco Banfi, Boris Gbahoue, Jeremy Schneider, “Higher Satisfaction at Lower Costs: Digitizing Customer Care, ” page 12 23-30

Alerts & Notifications 31-36 Alerts & Notifications Project Detail Worksheet 32-33 2018 GRC IT Capital Estimates - Alerts & Notifications 34 Notification Architecture 35-36

Meter Data Management System Upgrade 37-43 Meter Data Management System Upgrade Project Detail Worksheet 38 Investment Memo - Meter Data Management System Upgrade 39-42 2018 GRC IT Capital Estimates - Meter Data Management System Upgrade 43

Customer Service Projects less than $3M 44-732015 GRC Rate Changes 45

2015 GRC Rate Changes Project Detail Worksheet 45 Investment Memo 2015 GRC Rate Changes 46-48 2018 GRC IT Capital Estimates – 2015 GRC Rate Changes 49

2018 GRC Rate Changes 50 2018 GRC Rate Changes Project Detail Worksheet 50 Investment Memo 2018 GRC Rate Changes 51-53 2018 GRC IT Capital Estimates - 2018 GRC Rate Changes 54

Contact Center Optimization 55 Contact Center Optimization Project Detail Worksheet 55 Investment Memo Contact Center Optimization 56-58 2018 GRC IT Capital Estimates - Contact Center Optimization 59-61

Itron 3.9 NMS Upgrade Project 62 Itron 3.9 NMS Upgrade Project – Project Detail Worksheet 63

DOCUMENT PAGE(S)Investment Memo Itron 3.9 NMS Upgrade Project 64-65 2018 GRC IT Capital Estimates - Itron 3.9 NMS Upgrade Project 66

SmartConnect Monitor & Analysis 67-73 SmartConnect Monitor & Analysis Project Detail Worksheet 67 Investment Memo SmartConnect Monitor & Analysis 68-72 2018 GRC IT Capital Estimates - SmartConnect Monitor & Analysis 73

T&D Capitalized Software Projects 77-353 T&D Work Management Gap Analysis 77-101 WM - Portfolio Management 102-110

WM - Portfolio Management Project Detail Worksheet 103 Investment Memo - WM - Portfolio Management 104-109 2018 GRC IT Capital Estimates - WM - Portfolio Management 110

Scope Cost Management Tool 111-118 SCMT Project Detail Worksheet 112 Investment Memo – SCMT 113-117 2018 GRC IT Capital Estimates – SCMT 118

Work Management Dashboard 119-127 Work Management Dashboard Project Detail Worksheet 120 Investment Memo - Work Management Dashboard 121-126 2018 GRC IT Capital Estimates - Work Management Dashboard 127

Transmission Telecommunication Work Order Lifecycle 128-136 Trans Telecomm Work Order Lifecycle Project Detail Worksheet 129 Investment Memo - Trans Telecomm Work Order Lifecycle 130-135 2018 GRC IT Capital Estimates - Trans Telecomm Work Order Lifecycle 136

Click Schedule Refresh Release 1&2 137-140 Click Schedule Refresh Release 1&2 Project Detail Worksheet 138-139 2018 GRC IT Capital Estimates - Click Schedule Refresh Release 1&2 140

Vegetation Management 141-148 Vegetation Management Project Detail Worksheet 142 Investment Memo - Vegetation Management 143-146 Vegetation Management Financial Forecast Workpaper 147 2018 GRC IT Capital Estimates - Vegetation Management 148

Pole Loading Application Replacement Tool 149-153 PoLAR Tool Project Detail Worksheet 150 Investment Memo - PoLAR Tool 151-152 2018 GRC IT Capital Estimates - PoLAR Tool 153

Design Manager Refresh 154-158 DM Refresh Project Detail Worksheet 155 Investment Memo - DM Refresh 156-157 2018 GRC IT Capital Estimates - DM Refresh 158

Graphic Design Tool and Tract Deployment Refresh 159-168 GDT and Tract Deployment Refresh Project Detail Worksheet 160

DOCUMENT PAGE(S)Investment Memo - GDT and Tract Deployment Refresh 161-167 2018 GRC IT Capital Estimates - GDT and Tract Deployment Refresh 168

Consolidated Mobile Solution 169-174 CMS Project Detail Worksheet 170 Investment Memo – CMS 171-173 2018 GRC IT Capital Estimates – CMS 174

Field Tools Upgrade 175-180 Field Tools Upgrade Project Detail Worksheet 176 Investment Memo - Field Tools Upgrade 177-179 2018 GRC IT Capital Estimates - Field Tools Upgrade 180

Enhanced Business Resiliency for Energy Management System 181-186 EBR for Energy Management System Project Detail Worksheet 182 Investment Memo - EBR for Energy Management System 183-185 2018 GRC IT Capital Estimates - EBR for Energy Management System 186

Comprehensive Situational Awareness for Transmission 187-353 CSAT Project Detail Worksheet 188 Investment Memo – CSAT 189-192 2018 GRC IT Capital Estimates – CSAT 193 Increased Trans Line Utilization: Arizona Southern California Outages on September 8 2011 194-349

Transmission Sensitivity Analysis for Stability Rating Increases. 350-353


SCE-04, Vol.02 Book C

DOCUMENT PAGE(S)Transmission and Distribution Software Projects (Cont.) 1-2Centralized Remedial Action Scheme (CRAS) 3-91

CRAS Project Detail Worksheet 4 Investment Memo – CRAS 5-7 2018 GRC IT Capital Estimates – CRAS 8 CRAS Cost Study Overview and Reference 9-56 CRAS Cost Study Worksheet 57-71 Northern Area Arming Points Comparison 72-74 Evolution of RAS Complexity - Base Data 75-78 Arming Points (Current and Future) 79-80 RASs Nearing or Exceeding Capacity Limits 81-85 Northern Area RAS Arming Points - Base Data 86-87 Stand-Alone RAS Capacity Increase Factors 88-89 Cumulative Completion Percentage of Transmission Interconnection Queue Projects 90-91

RGOOSE Project 92-103 RGOOSE Project Detail Worksheet 93 Investment Memo – RGOOSE 94-101 2018 GRC IT Capital Estimates – RGOOSE 102 GOOSE Data Volume Study 103-106

Energy Management System (EMS) Refresh 107-115 EMS Project Detail Worksheet 108 Investment Memo – EMS 109-114 2018 GRC IT Capital Estimates – EMS 115

Outage Management System (OMS) Refresh 116-123 OMS Project Detail Worksheet 117 Investment Memo – OMS 118-122 2018 GRC IT Capital Estimates – OMS 123

Distribution Management System 124-130 DMS Project Detail Worksheet 125 Investment Memo – DMS 126-129 2018 GRC IT Capital Estimates – DMS 130

Grid Interconnection Processing Tool (GIPT) 131-133 GIPT Project Detail Worksheet 132 2018 GRC IT Capital Estimates – GIPT 133

DOCUMENT PAGE(S)Grid Analytics Applications (GAA) 134-136

GAA Project Detail Worksheet 135 2018 GRC IT Capital Estimates – GAA 136

Long-Term Planning Tools 137-139 Long-Term Planning Tools Project Detail Worksheet 138 2018 GRC IT Capital Estimates – Long-Term Planning Tools 139

Grid Connectivity Model 140-142 Grid Connectivity Model Project Detail Worksheet 141 2018 GRC IT Capital Estimates – Grid Connectivity Model 142

Transmission and Distribution Projects less than $3 Million 143-192 Substation Health Assessment Tool 144-149

Substation Health Assessment Tool Project Detail Worksheet 144 Investment Memo – Substation Health Assessment Tool 145-148 2018 GRC IT Capital Estimates – Substation Health Assessment Tool 149

Substation 3D Design 150-155 Substation 3D Design Project Detail Worksheet 150 Investment Memo – Substation 3D Design 151-154 2018 GRC IT Capital Estimates – Substation 3D Design 155

Electronic WO Package Automation 156-161 Electronic WO Package Automation Project Detail Worksheet 156 Investment Memo – Electronic WO Package Automation 157-160 2018 GRC IT Capital Estimates – Electronic WO Package Automation 161

Fast Response Energy Storage 162-166 Fast Response Energy Storage Project Detail Worksheet 162 Investment Memo – Fast Response Energy Storage 163-165 2018 GRC IT Capital Estimates – Fast Response Energy Storage 166

Transient Devices 167-172 Transient Devices Project Detail Worksheet 167 Investment Memo – Transient Devices 168-171 2018 GRC IT Capital Estimates – Transient Devices 172

High Z Impedance Fault Detection 173-177 High Z Impedance Fault Detection Project Detail Worksheet 173 Investment Memo – High Z Impedance Fault Detection 174-176 2018 GRC IT Capital Estimates – High Z Impedance Fault Detection 177

Secure DNP Ver5 Support for EMS 178-181 Secure DNP Ver5 Support for EMS Project Detail Worksheet 178 Investment Memo – Secure DNP Ver5 Support for EMS 179-180 2018 GRC IT Capital Estimates – Secure DNP Ver5 Support for EMS 181

Grid Management Dashboard 182-186 Grid Management Dashboard Project Detail Worksheet 182 Investment Memo – Grid Management Dashboard 183-185 2018 GRC IT Capital Estimates – Grid Management Dashboard 186

PSMP 2.0 187-192

DOCUMENT PAGE(S)PSMP 2.0 Project Detail Worksheet 187 Investment Memo – PSMP 2.0 188-191 2018 GRC IT Capital Estimates – PSMP 2.0 192

Power Supply Software Projects 193-262 Generation Automation Upgrade & Control Systems Refresh 196-199

Generation Automation Upgrade & Control Systems Refresh Project Detail Worksheet 197-198

2018 GRC IT Capital Estimates – Generation Automation Upgrade & Control Systems Refresh 199

Dam Monitoring and Surveillance 200-203 Dam Monitoring and Surveillance Project Detail Worksheet 201-202 2018 GRC IT Capital Estimates – Dam Monitoring and Surveillance 203

CAISO Market Enhancements Program (IMEP) 204-211 IMEP Project Detail Worksheet 205-206 Investment Memo – IMEP 207-210 2018 GRC IT Capital Estimates – IMEP 211

Energy Planning Platform Upgrade (EPP) 212-218 EPP Project Detail Worksheet 213 Investment Memo – EPP 214-217 2018 GRC IT Capital Estimates – EPP 218

PCI Replacement 219-224 PCI Replacement Project Detail Worksheet 220 Investment Memo – PCI Replacement 221-223 2018 GRC IT Capital Estimates – PCI Replacement 224 Power Procurement Market Systems Front-Office (FO) Capabilities Strategic Assessment 225-236

Energy Trading and Risk Management (ETRM) 237-242 ETRM Project Detail Worksheet 238 Investment Memo – ETRM 239-241 2018 GRC IT Capital Estimates – ETRM 242

Aggregated Demand Response (ADR) 243-248 ADR Project Detail Worksheet 244 Investment Memo – ADR 245-247 2018 GRC IT Capital Estimates – ADR 248

Commodity Management Platform (CMP) 249-255 CMP Project Detail Worksheet 250 Investment Memo – CMP 251-254 2018 GRC IT Capital Estimates – CMP 255

Generation Management System (GMS) Upgrade 256-262 GMS Project Detail Worksheet 257 Investment Memo – GMS 258-261 2018 GRC IT Capital Estimates – GMS 262

DOCUMENT PAGE(S)Power Supply Projects less than $3M 263-281 Usage Measurement System (UMS) 264-268

Usage Measurement System (UMS) Project Detail Worksheet 264 Investment Memo – Usage Measurement System (UMS) 265-267 2018 GRC IT Capital Estimates – Usage Measurement System (UMS) 268

PPD Control System HW Refresh 269-272 PPD Control System HW Refresh Project Detail Worksheet 269 Investment Memo – PPD Control System HW Refresh 270-271 2018 GRC IT Capital Estimates – PPD Control System HW Refresh 272

Gas Solar Control System Refresh 273-276 Gas Solar Control System Refresh Project Detail Worksheet 273 Investment Memo – Gas Solar Control System Refresh 274-275 2018 GRC IT Capital Estimates – Gas Solar Control System Refresh 276

WM Reliability-Centered Maintenance 277-281 WM Reliability Centered Maint. Project Detail Worksheet 277 Investment Memo – WM Reliability Centered Maint. 278-280 2018 GRC IT Capital Estimates – WM Reliability Centered Maint. 281

Enterprise / Corporate Software Projects 282-318 Enterprise Content Management (ECM) 286-292

ECM Project Detail Worksheet 287 Investment Memo – ECM 288-291 2018 GRC IT Capital Estimates – ECM 292

Electronic Document Management / Records Management (eDMRM) 293-299 eDMRM Project Detail Worksheet 294 Investment Memo – eDMRM 295-298 2018 GRC IT Capital Estimates – eDMRM 299

Plant Ledger Upgrade and Tax Module Installation 300-318 PLU and TMI Project Detail Worksheet 301 Investment Memo – PLU and TMI 302-304 2018 GRC IT Capital Estimates – PLU and TMI 305 PowerPlan Tax Repairs White Paper 306-318

Corporate Projects less than $3M 319-342 Legal Platform Modernization 321-325

Legal Platform Modernization Project Detail Worksheet 321 Investment Memo – Legal Platform Modernization 322-324 2018 GRC IT Capital Estimates – Legal Platform Modernization 325

Reg Affairs - TM2 Replacement 326-331 Reg Affairs - TM2 Replacement Project Detail Worksheet 326 Investment Memo – Reg Affairs - TM2 Replacement 327-330 2018 GRC IT Capital Estimates – Reg Affairs - TM2 Replacement 331

Integrated Budget Planning 332-336 Integrated Budget Planning Project Detail Worksheet 332

DOCUMENT PAGE(S)Investment Memo – Integrated Budget Planning 333-335 2018 GRC IT Capital Estimates – Integrated Budget Planning 336

Union Negotiations 337-342 Union Negotiations Project Detail Worksheet 337 Investment Memo – Union Negotiations 338-341 2018 GRC IT Capital Estimates – Union Negotiations 342

Operation Services Projects 343-392 C-CURE 9000 344-349

C-CURE 9000 Project Detail Worksheet 345 Investment Memo - C-CURE 9000 346-348 2018 GRC IT Capital Estimates – C-CURE 9000 349

Operational Services Projects less than $3M 350-392 Mobile Field Response 351-357

Mobile Field Response Project Detail Worksheet 351 Investment Memo – Mobile Field Response 352-356 2018 GRC IT Capital Estimates – Mobile Field Response 357

Crisis Information Management System 358-362 Crisis Information Management System Project Detail Worksheet 358 Investment Memo – Crisis Information Management System 359-361 2018 GRC IT Capital Estimates – Crisis Information Management System 362

Seismic Risk Assessment 363-367 Seismic Risk Assessment Project Detail Worksheet 363 Investment Memo – Seismic Risk Assessment 364-366 2018 GRC IT Capital Estimates – Seismic Risk Assessment 367

EHSync Environmental Clearance Phase 2 368-375EHSync Environmental Clearance Phase 2 Project Detail Worksheet 368-369 Investment Memo – EHSync Environmental Clearance 370-374 2018 GRC IT Capital Estimates – EHSync Environmental Clearance 375

Facilities Management System 376-380 Facilities Management System Project Detail Worksheet 376 Investment Memo – Facilities Management System 377-379 Facilities Management System 380

Safety Observations 381-385 Safety Observations Project Detail Worksheet 381 Investment Memo – Safety Observations 382-384 2018 GRC IT Capital Estimates – Safety Observations 385

Ariba Deployment and Supplier Portal Decomm 386-392 Ariba Deployment and Supplier Portal Decomm Detail Worksheet 386 Investment Memo – Ariba Detail Worksheet 387-391 2018 GRC IT Capital Estimates – Ariba 392

Workpaper – Southern California Edison / 2018 GRC

Exhibit No. SCE-04 / Vol. 02 / Book C Witness: Various

Transmission and Distribution Software Projects (Cont.)

1



CAPITAL WORKPAPERS - ITSouthern California Edison Company

OU SUMMARY, BY WITNESS, BY EXHIBIT(Nominal $000)

Forecast Capital Expenditures

TotalTestimony DescriptionItem

2016 2017 2018 2019 2020

38,201 56,470 37,782 23,380 13,392 169,2251 Tim Boucher

SCE-04, Vol. 02 38,201 56,470 37,782 23,380 13,392 169,2251.1

3,744 12,732 356 367 392 17,590CIT-00-SD-PM-0002471.1.1

0 2,000 4,000 8,000 8,000 22,000CIT-00-DM-DM-0000851.1.2

459 6,323 6,029 2,260 0 15,070CIT-00-OP-NS-0005191.1.3

459 6,901 6,318 0 0 13,678CIT-00-OP-NS-0005201.1.4

3,440 5,025 5,049 1,432 0 14,946CIT-00-OP-NS-0005211.1.5

950 0 0 0 0 950CIT-00-SD-PM-0001021.1.6

2,440 0 0 0 0 2,440CIT-00-SD-PM-0001371.1.7

0 0 2,600 0 0 2,600CIT-00-SD-PM-0001871.1.8

0 0 1,260 720 0 1,980CIT-00-SD-PM-0002061.1.9

0 0 0 0 1,000 1,000CIT-00-SD-PM-0002331.1.10

0 0 0 1,000 1,000 2,000CIT-00-DM-DM-0000831.1.11

4,500 5,900 0 0 0 10,400CIT-00-SD-PM-0002431.1.12

6,210 7,220 2,670 0 0 16,100CIT-00-SD-PM-0002311.1.13

0 1,500 3,500 1,600 0 6,600CIT-00-DM-DM-0000231.1.14

0 0 1,000 6,000 3,000 10,000CIT-00-DM-DM-0000471.1.15

6,800 3,500 0 0 0 10,300CIT-00-DM-DM-0000501.1.16

0 3,000 4,000 0 0 7,000CIT-00-DM-DM-0000511.1.17

0 0 0 1,000 0 1,000CIT-00-DM-DM-0000841.1.18

0 2,000 0 0 0 2,000CIT-00-DM-DM-0000861.1.19

0 0 1,000 1,000 0 2,000CIT-00-DM-DM-0000901.1.20

5,450 370 0 0 0 5,820CIT-00-SD-PM-0000411.1.21

1,500 0 0 0 0 1,500CIT-00-SD-PM-0001401.1.22

1,620 0 0 0 0 1,620CIT-00-SD-PM-0001521.1.23

630 0 0 0 0 630CIT-00-SD-PM-0002341.1.24

2

See WP_SCE-04, Vol. 2 Bk B for the following:CIT-00-DM-DM-000023CIT-00-DM-DM-000047CIT-00-SD-PM-000137CIT-00-DM-DM-000085CIT-00-DM-DM-000051



Centralized Remedial Action Scheme

3



0

200

400

600

800

1,000

1. WITNESS: Tim Boucher

Program: PROJECT MANAGEMENT

Pin #: 6428

WBS Element: CIT-00-SD-PM-000102

2. PROJECT DETAIL:

Select one3. PROJECT TYPE:

Compliance: Safety, Environmental, Licenses Customer Growth

Replacements in Kind Load Growth

Upgrades Reliability

Blanket: F&E, Tools, Spare Parts, Lab, Computer Equip X Capitalized Software

5. CLOSE DATE: 4/17/2016

7. COST ESTIMATES (NOMINAL $000):

Year950

0

0

0

SCE $

0

7 (a). SYSTEM SHORT TEXT:

7 (b). DETAILED DESCRIPTION:

8. SCOPE:

9. JUSTIFICATION:

Various (See Below)

4. ASSET TYPE: Cap Soft 5yr

6. RIIM ELIGIBLE:

950

Program Group: SOLUTION DELIVERY

2016 2017 2018 2019 2020

2018 GRC - Capital Expenditures Forecast

Testimony Summary: Organizational Unit Summary:

Major Program: Category:

SOUTHERN CALIFORNIA EDISON COMPANYCAPITAL WORKPAPERS - CAPITALIZED SOFTWAREPROJECT DETAIL WORKSHEET: NEW SOFTWARE

Detail: RO Model ID:

SCE-04, Vol. 02IT

Capitalized SoftwareCapitalized SoftwareNew Software795

2016

2017

2018

2019

2020

Total

Centralized Remedial Action Scheme Project (CRAS)

See Testimony.

See Testimony.

CRAS Project

4



Centralized Remedial Action Schemes EXECUTIVE SUMMARY (1 of 3)

PROJECT OVERVIEW

Buy or build: [X]Leverage current capabilities: [ ]

Description:

This new system software and hardware will allow better compliance with state generation interconnection requirements and Renewable Portfolio Standards and reduce operating risks on the transmission grid by reducing the amount of generation tripped and/or firm load shed. In addition, once the CRAS platform is in place, adding new schemes is less expensive (less relays and less field labor needed) than stand-alone RASs. The CRAS platform will be implemented with two initial stand-alone RASs incorporated. Then normal RAS deployment will occur using the following criteria for RASs into CRAS:

All new RASs Complex existing RASs in renewables-rich areas

This funding request is for CRAS Phase 1 only. Future deployment is covered by existing approved infrastructure funding for RAS deployment.

PROJECT RATIONALE

Discretionary / Non-negotiable: Discretionary

Justification:

Compliance with state generation interconnection requirements and Renewable Portfolio Standards, as well as reduction of operating risks.

Rate impact:

Decrease (BC ratio = 2.00)

Business needs:

This project addresses the following needs:

1. Stand-alone RASs are bottle-necked in design and installation, hampering SCE’s ability to interconnect generation in compliance with state policies on large generation interconnections and to meet the 2020 33% and 2030 50% Renewable Portfolio Standard targets;

2. Stand-alone RASs are more expensive to implement and test or change and test (require more labor because of different test methodologies and capabilities);

3. As they become more complex, stand-alone RASs trip too much generation and/or shed too much firm load, substantially increasing operating risks for complex schemes; and

4. Certain upcoming RASs are too complex (have too many arming points needed when future growth is considered) for a stand-alone RAS approach and require CRAS.

Urgency:

1. Renewable Portfolio Standard requirements and other incentives have an increase in generation projects in the CISO queue and an increase in percentage of projects completing;

2. Due to complexity of most new interconnection clusters, individual RASs are less practical and tend to trip more generation and/or load than needed, increasing operating risks; and

3. CRAS is needed to facilitate generation interconnections.

5



2


PROJECT FINANCIALS

6



3


ALTERNATIVES Alternatives Considered

Alternative 1: Do not do “project” (in this sense, by “project” we mean further deployment of CRAS, not the base CRAS project already implemented) and instead, for the three RASs out of the four under consideration where a stand-alone RAS capacity upgrade is possible, increase the capacity of stand-alone RAS relays instead of converting the RASs into CRAS. This alternative is not recommended because it is cost prohibitive and merely sets another hard arming points limit in place that will be exceeded in the future, causing the same capacity shortfall. In addition, a critical deficiency of this alternative is that Northern Area RAS (the remaining RAS out of the four under consideration) cannot be accommodated as a stand-alone RAS, asit would not meet grid protection requirements even if there is an increase in stand-alone RAS relay capacity (see Alternative 2). Alternative 1 does not provide a long-term solution to arming point capacity and is not cost-efficient.

Alternative 2: Do not do “project” (in this sense, by “project” we mean further deployment of CRAS, beyond the base CRAS project already implemented) and instead, build a transmission line to meet the Northern Area protection needs. This alternative is not recommended due to costly infrastructure and lead time requirements that would significantly impact the feasibility of QC-8 and QC-9 renewables generation projects.

KEY BENEFITS

Benefits:

1. CRAS has a Benefit/Cost ratio of 2.00 (please see work papers: “CRAS Cost Study Overview and Reference” and “CRAS Cost Study Worksheet” for supporting information).

2. CRAS has a $49.13 million cost, which is less than the cost of 20 miles of new transmission, making it the least cost alternative to both transmission build out and stand-alone RAS implementation (using the criteria mentioned earlier for new and existing RASs); and

3. CRAS enables the business to address interconnection requests from generators in a timely manner, supports SCE’s achievement of the 33% RPS by 2020 and 50% RPS by 2030.

PV of Savings:

BC = 2.00

Justification of Benefits:

See cost study work papers cited above.

KEY ISSUES / RISKS

1. N/A: Project is completed. Current GRC effort is around remaining cost recovery for project phase (about $16 M not including AFUDC)

2. A network upgrade project, RGOOSE Project, is required as a key enabler for CRAS deployment based on upcoming complex RAS data volume requirements. The RGOOSE protocol based on standard IEC 61850 90-5 has been implemented by GE Multilin (relay provider) and thoroughly tested by GE. The CRAS Central Controller sub-vendor, SISCO, will need to upgrade central controller software to enable use of RGOOSE protocol. This is relatively low risk.

Mitigation:

1. N/A 2. Perform initial tests of higher risk items (such as ability of RGOOSE data packets to pass quickly through required firewall devices on the data paths) in the RGOOSE Project, followed by deployment of Colorado River RAS into CRAS with RGOOSE with additional cycles of testing.

7



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-$

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00$

Ass

umpt

ions

:

Cen

tral

ized

Rem

edia

l Act

ion

Sche

me

(CR

AS)

Pro

ject

CO

TS A

pplic

atio

n Pr

ojec

tLa

rge

CO

TS P

roje

ct>$

5M

8



CRAS Cost Study Overview and Reference

9



CRAS

(Cen

tralize

dRe

med

ialA

ctionSche

me)

WorkPape

rs

CRAS

CostStud

yOverviewan

dRe

ference

For2

018GR

CFilin

g

1.Starth

ereforo

verviewof

busin

essd

rivers,alternatives

considered

,costd

rivers,and

detailedbreakdow

nsof

howtheeq

uatio

nsandvaria

bles

work

2.Associated

workpape

r“CR

ASCo

stStud

yWorkshe

et”istheExcelw

orkshe

etthat

calculates

expe

cted

costavoidances

usingeq

uatio

nsde

scrib

edinthisworkpape

r.

1CR

ASCo

stStud

yOverviewandRe

ference

10



Glo

ssar

y of

Ter

ms

•ArmingPo

int–

Acontingencythat

theRA

Sconstantlyevaluates.RA

S“arm

s”(becom

esreadyto

tripgene

ratio

nor

shed

load)atthis

thresholdvalue.Fore

xample,thiscouldbe

atransm

issionlineflo

wam

ount.A

rmingpo

intsareassociated

with

specificgene

rators,

thou

ghthey

may

sharecontingencies.

•Ba

seCase

RAS–Thestandalon

eRA

Ss(ElN

idoandElSegund

o),con

sidered

asaun

it,that

CRAS

replaced

/incorporated

inproject

phase.Ga

vevery

usefulandaccurate

comparison

betw

eenCR

ASandstandalon

eRA

Ssviarecorded

costs.

•CR

AS–Ce

ntralized

Remed

ialA

ctionSche

me–Ce

ntralized

RASthat

haslogiccontrollersinhigh

speedserversinGridCo

ntrolCen

ters.

•CapacityUpgrade

–Logiccapacityup

gradeto

astandalon

eRA

Srelaythat

allowsittohave

morearmingpo

intsandadditio

nal

commun

ications

channe

ls.Fore

xistingstandalon

eRA

Ss,thisinvolvesinstalling

anup

graded

CPUmod

uleandpo

wer

supp

ly,and

individu

alrelayre

testing,as

wellasretestin

gtheoverallRAS

forp

rope

rfun

ctionality.Thisleaves

ahigher

“hardstop

”inarming

pointsforthe

standalon

eRA

S,so

itisatempo

rary

solutio

nto

capacityissue

s.•

Contingency

An“N

1”sin

gleou

tage

or“N

2”do

ubleou

tage,suchas

atransm

issionlineor

lines

beingoverloaded

,thata

RAS

evaluatestoprotecttransmissionor

gene

ratio

nassets.Firstthe

RASarms,then

ifthevaluegettingmon

itored(suchas

alineflo

w)

getsworse,risk

ingdamage,theRA

Stripsg

enerationor

shed

sload(orb

oth).

•Ge

nerator–

Agene

rator(whe

nreferred

toincontexto

fapo

wer

source)o

rgen

erationcustom

er(w

henreferringto

abu

sinesse

ntity

with

aprojectintheCaliforniaISOIntercon

nectionQue

ueor

completed

projectinthefie

ld)

•Ha

rdStop

–Refersto

hard

limits

implicitinarelay’sh

ardw

areof

firmwarethat

limitthenu

mbe

roflogicstep

s(armingpo

ints)itcan

have.Thisthresho

ldvalue(currently48

armingpo

ints)isa

limitto

thecapacityto

addadditio

nalgen

eratorsfor

astandalon

eRA

S.•

PSCor

ITPSC–SCE’sP

ower

System

sCon

trolsg

roup

.Adm

inistersC

RASintheGridCo

ntrolCen

ters.

•Re

lays

(stand

alon

eRA

S)–GE

N60

with

individu

allycustom

izedsettings.

•Re

lays

(CRA

S)–GE

N60

with

standardize

dsettings

(onlytw

obasic

type

s:mon

itorin

gor

mitigatio

n).

•SC&M

SCE’sS

ubstationCo

nstructio

n&Mainten

ance

–thisgrou

phastesttechs

that

workon

fieldrelays.

•TS&S–TechnicalSup

port&Strategy

–partof

SCE’sS

C&M

(Sub

stationCo

nstructio

n&Mainten

ance)–

testingSM

Es.

2CR

ASCo

stStud

yOverviewandRe

ference

11



CRAS

CostStud

yOverviewan

dRe

ference

Tableof

Conten

ts,H

ighLevelSectio

n

•D

efin

ition

of R

AS

s an

d W

hat T

hey

Do

on th

e Tr

ansm

issi

on G

rid

(slid

es 4

–6)

•Bu

sine

ss P

robl

em a

nd A

ltern

ativ

es C

onsi

dere

d (s

lides

7 –

9)•

SCE

’s P

ositi

on o

n C

ost R

ecov

ery

for C

RA

S a

nd R

GO

OS

E P

roje

ct

(slid

e 10

) •

Sum

mar

y of

Res

ults

(Exp

ecte

d C

ost S

avin

gs in

Nom

inal

Dol

lars

) (s

lide

11)

•Im

plem

enta

tion

Cos

t Per

Rel

ay: R

ecor

ded

Cos

t Diff

eren

ces

(slid

e 12

)•

Nor

ther

n A

rea

Avoi

ded

Tran

smis

sion

Cos

t(s

lide

13)

•C

ost C

ompo

nent

Diff

eren

ces

Bet

wee

n C

RA

S a

nd S

tand

-Alo

ne R

AS

s(s

lide

14)

•C

ost P

er R

elay

: Spe

cific

Cos

t Fac

tors

Driv

ing

CR

AS

Fav

orab

le V

aria

nce

(slid

e 15

)•

Gre

ater

Effi

cien

cy o

f CR

AS

Fie

ld T

estin

g(s

lide

16)

•D

etai

l Lev

el/B

acku

p S

ectio

n(s

lides

17

–47

) 3CR

ASCo

stStud

yOverviewandRe

ference

12



RASProtectio

nSystem

–Co

mmon

Factors

4

1.RA

Ss(bothstandalon

eandCR

AS)are

desig

nedto

mitigate

transm

issionsystem

prob

lemsc

ausedby

thelossof

transm

issionsystem

capacity(e.g.,lossof

alineor

atransformer).

2.Iftheprob

lem

isgene

ratio

nexceed

ingtheremaining

transm

issioncapacity(resultin

ginoverloadso

rinstability),the

RASwilltripgene

ratio

n.3.

Iftheprob

lem

isload

exceed

ingtheremaining

transm

issioncapacity(resultin

gin

overloadso

rvoltage

collapse),the

RASwilltripload.

•Thereisno

diffe

rencebe

tweenastandalon

eRA

SandCR

ASintheserespects(1

–3).

13



RASProtectio

nSystem

–CR

ASAd

vantages

5

•CR

ASim

provem

entsover

standalon

eRA

Ssinclud

e:o

Logi

c pr

oces

sing

(“an

alyt

ics”

) bei

ng a

t the

con

trol c

ente

rs in

stea

d of

in th

e su

bsta

tion

Sig

nific

antly

gre

ater

eas

e of

cha

nge

of lo

gic

proc

essi

ngo

Gre

atly

impr

oved

arc

hite

ctur

eB

ette

r des

ign

for p

rote

ctin

g tra

nsm

issi

on a

sset

so

Bet

ter s

yste

m a

war

enes

s an

d st

abili

tyG

loba

l rea

ch a

cros

s in

corp

orat

ed R

AS

sA

ble

to in

corp

orat

e ex

tern

al s

yste

m d

ata

Hel

ps p

reve

nt c

asca

ding

failu

res

betw

een

inte

rrela

ted

RA

Ss

oE

nhan

ced

auto

mat

ion

and

sim

ulat

ion

capa

bilit

ies

Mor

e co

mpr

ehen

sive

test

ing

Sig

nific

ant r

educ

tion

in te

stin

g la

bor

•C

RA

S a

nd c

omm

unic

atio

ns: T

he n

eed

for s

peed

and

aw

aren

ess

of c

ondi

tions

at m

ultip

le

subs

tatio

ns in

volv

ing

mul

tiple

tran

smis

sion

line

s dr

ives

the

need

for h

igh

spee

d, p

reci

se

com

mun

icat

ions

pro

toco

ls s

uch

as th

e re

cent

ly a

vaila

ble

RG

OO

SE

–w

hich

was

des

igne

d by

in

dust

ry e

xper

ts in

the

IEC

618

50 s

tand

ards

gro

ups

for t

hat v

ery

purp

ose.

RG

OO

SE

pro

vide

s “r

outa

ble”

com

mun

icat

ions

–w

hich

giv

es p

reci

se ta

rget

ing

to e

ach

mes

sage

–un

like

GO

OS

E,

the

curr

ent b

road

cast

(non

-targ

eted

) pro

toco

l tha

t CR

AS

use

s.

14



CRAS

Simplified

System

Diagram

6

•Blue

lines

indicate

high

speeddiversepath

commun

icationlinks

with

switche

sand

routers.AandBsid

emon

itorin

gandmitigatin

gdata

goes

toandfrom

controlcenters.Per

WECCrequ

irementsRA

Sshave

AandBsid

esanddiversepathsfor

redu

ndancy/reliabilitypu

rposes.The

smallarrow

srep

resent

high

volumeof

messages.

•CR

AScentralcon

trollersareserversincontrolcentersthat

evaluate

mon

itorin

gdata

andsend

mitigatio

nsig

nals.

•Mitigatio

nrelays

tripgene

ratio

nor

shed

load

asne

eded

toprotectg

rid(viacircuitb

reakersn

otshow

n).

•RG

OOSE

isthecommun

icationarchite

cturethat

enablesh

ighspeedandreliablecommun

icationbe

tweenthesubstatio

nandcontrolcenter.Im

portantto

hand

lethehigh

volumeof

complex

messaging

need

ed.

1. O

nly

one

sim

plifi

ed s

ubst

atio

n sh

own.

RA

Ss

are

tight

ly in

tegr

ated

with

one

or m

ore

subs

, gen

erat

ors,

and

tran

smis

sion

line

s.

AlhambraCo

ntrol

Center

IrvineCo

ntrol

Center

Mitigatio

nRe

lay

Mitigatio

nRe

lay

Mon

itorin

gRe

lay

Mon

itorin

gRe

lay

Bsid

eAsid

e

Substatio

n1

Gene

rator

orTrans

mission

Line

Sm

all a

rrow

s re

pres

ent h

igh

volu

me

of

com

plex

m

essa

ges

6CR

ASCo

stStud

yOverviewandRe

ference

CB CB

CircuitB

reaker

15



Busin

ess

Driv

er –

RASs

Nea

ring

or E

xcee

ding

Cap

acity

Lim

its

6CR

ASCo

stStud

yOverviewandRe

ference

16



Arm

ing

Poin

ts (C

urre

nt &

Fut

ure)

6CR

ASCo

stStud

yOverviewandRe

ference

•Armingpo

intsbe

stmeasure

ofcomplexity

andcapa

city.

•Th

esearethe4RA

Sson

priorslid

e

17



9

Busin

essP

roblem

&Options

Considered

•Bu

sine

ssProb

lem:C

apacity

issue

sonup

comingRA

Ssareexpe

cted

with

numerou

sgen

erationcustom

ers

inqu

eue.SCEtariffreq

uiresthatthe

gene

ratorsbe

accommod

ated

insomemanne

r.•Options:

1.CR

ASwith

RGOOSE

2.Increase

capacity

ofstandalon

eRA

Srelays

3.CR

ASwith

GOOSE

4.Bu

ildtransm

ission

•Re

commen

datio

n:Option#1

bestaddressesthe

busin

essp

roblem

servinggene

ratio

ninasecure

manne

r.Option2on

lyworks

for3

ofthe4RA

Ssun

dercon

sideration(see

testim

onydraftfor

anexplanationof

why

astandalon

eRA

Sisno

tfeasib

leforN

orthernArea

RAS).O

ption2ismoreexpe

nsivethan

Option1andison

eof

thealternatives

inthiscost

stud

y.Option3isdiscussedinthetestim

onydraft.Theup

comingRA

Sshave

muchhigher

volumedata

requ

irementsthan

project

phaseRA

SsandGO

OSE

does

notg

ivethepe

rform

ance

orabilityto

trackandqu

icklyfix

commun

icationprob

lemsthat

RGOOSE

does.

Option4isthealternativeto

CRAS

with

RGOOSE

forN

orthernArea

RASandison

eof

thealternatives

inthiscoststud

y.

18



10

SCE’

s C

ost R

ecov

ery

Posi

tion

on C

RA

S an

d R

GO

OSE

•R

GO

OS

E, a

s ex

plai

ned

furth

er in

the

RG

OO

SE

sec

tion

of th

e G

RC

test

imon

y, is

a

netw

ork

com

mun

icat

ions

pro

toco

l upg

rade

that

ser

ves

as a

n en

able

r for

fu

rther

CR

AS

dep

loym

ent.

Com

pare

d to

GO

OS

E s

tand

ard

(onl

y av

aila

ble

prot

ocol

whe

n C

RA

S la

unch

ed),

RG

OO

SE

sta

ndar

d gi

ves

mor

e re

liabl

e co

mm

unic

atio

ns p

erfo

rman

ce, i

s si

gnifi

cant

ly m

ore

scal

able

, and

pro

vide

s en

hanc

ed c

omm

unic

atio

ns tr

oubl

esho

otin

g an

d au

tom

atio

n.

•C

RA

S is

mor

e co

st e

ffici

ent t

han

the

alte

rnat

ives

con

side

red

on p

rior s

lide.

C

RA

S c

ost e

ffici

ency

is c

over

ed a

t a h

igh

leve

l in

the

CR

AS

test

imon

y se

ctio

n,

deta

iled

in th

e C

RA

S C

ost S

tudy

Wor

kshe

et, a

nd e

xpla

ined

in d

epth

in th

is w

ork

pape

r.

•Th

eref

ore

CR

AS

cos

t avo

idan

ces

shou

ld c

over

bot

hC

RA

S re

mai

ning

un

reco

vere

d pr

ojec

t cos

ts a

nd R

GO

OS

E p

roje

ct c

osts

.

19



Summarytableusingda

tafrom

Expe

cted

Savingsa

ndTran

smission

tabs

ofCR

ASCo

stStud

yWorkshe

et

Summaryof

Results

11CR

ASCo

stStud

yOverviewandRe

ference

20



Impl

emen

tatio

n C

ost P

er R

elay

: Rec

orde

d C

ost D

iffer

ence

sVirtua

llyallcostsallocatedto

relays

arelabo

rand

overhe

adso

nlabo

r.Th

ereisvery

little

materialcost.

Stan

dAlon

eRe

lay

CRAS

Relay

7%

42%

51%STANDALO

NERA

SRE

LAY

Material

Engine

eringandDe

sign

FieldWork

Stan

d-Al

one

RAS

Rela

y, E

ach

Cos

t Cat

egor

yP

erce

ntC

ost

Mat

eria

l7%

15,0

00$

E

ngin

eerin

g an

d D

esig

n42

%84

,000

$

Fiel

d W

ork

51%

101,

570

$

To

tal

100%

200,

570

$

CRAS

Rel

ay, E

ach

Cos

t Cat

egor

yP

erce

ntC

ost

Mat

eria

l12

%15

,000

$

Eng

inee

ring

and

Des

ign

40%

47,7

42$

Fi

eld

Wor

k48

%57

,973

$

Tota

l10

0%12

0,71

5$

12%

40%

48%

CRASRE

LAY

Material

Engine

eringandDe

sign

FieldWork

$200,570

$120,715

12CR

ASCo

stStud

yOverviewandRe

ference

21



CRAS

CostStud

yOverviewandRe

ference

13

Nor

ther

n A

rea

Avoi

ded

Tran

smis

sion

Cos

t

Reason

swhy

newtransm

issionbu

ildison

lyalternativeto

CRAS

with

RGOOSE

forN

orthernArea:

SeeCR

ASTestim

onysectionand

workpape

r:“Transmission

Alternativeto

CRAS

forN

orthern

Area.”

Form

oreinform

ationon

thecost

aspe

ctsa

ndannu

alcostdistrib

ution:

See“TransmissionAlternativeto

CRAS

forN

orthernArea”or

CRAS

CostStud

yWorkshe

et.

22



Cos

t Com

pone

nt D

iffer

ence

s B

etw

een

CR

AS

and

Stan

d-A

lone

RA

Ss

Com

pone

ntR

AS

CR

AS

Con

trolle

rLo

gic

cont

rolle

r is

in th

e fie

ld –

hard

mem

ory

step

s lim

its w

hat i

t ca

n ha

ndle

for c

ompl

ex g

ener

atio

n in

terc

onne

ctio

ns.

Cen

traliz

ed lo

gic

is n

ot li

mite

d an

d ca

n ha

ndle

eve

n th

e m

ost

com

plex

gen

erat

ion

inte

rcon

nect

ions

.

Rel

ay (A

lloca

ted

Labo

r and

Cou

nt)

Eac

h R

AS

has

a s

et o

f ded

icat

ed re

lays

–re

sulti

ng in

mul

tiple

re

lays

for o

ne li

ne/b

ank

elem

ent.

Few

er re

lays

nee

ded

in th

e lo

ng te

rm: E

ach

line/

bank

ele

men

t has

a

dedi

cate

d re

lay

–on

e tim

e in

stal

latio

n an

d co

mm

issi

onin

g.

Rel

ay s

harin

g of

line

mon

itorin

g re

lays

pos

sibl

e w

ith C

RAS

, re

quire

s ad

ditio

nal r

elay

s w

ith s

tand

-alo

ne.

Com

mun

icat

ion

Pro

prie

tary

poin

t-to-

poin

t pro

toco

l.S

tand

ards

-bas

edm

ultic

ast i

nter

natio

nal p

roto

col.

Alg

orith

m“G

ener

ator

-cen

tric:

” Non

-sys

tem

atic

, not

as

focu

sed

on

cont

inge

ncie

s as

it s

houl

d be

.“C

ontin

genc

y-ce

ntric

:” B

ette

r arc

hite

ctur

e –

syst

emat

ic a

nd a

ble

to

take

mor

e fo

cuse

d an

d pr

ecis

e ac

tion

to p

rote

ct li

nes.

Test

ing

(Sig

nific

ant L

abor

C

ompo

nent

)

Fiel

d cr

ew e

nd-to

-end

test

ing

requ

ires

mul

tiple

cre

ws

at e

ach

subs

tatio

n an

d fre

quen

t shi

fts o

f phy

sica

l con

nect

ions

with

test

se

ts (l

abor

inte

nsiv

e)

CR

AS

’ onb

oard

test

tool

s en

able

sam

e va

lidat

ion

wor

king

with

fie

ld c

rew

s bu

t is

muc

h fa

ster

(low

labo

r im

pact

, les

s cr

ews,

less

du

ratio

n)

14CR

ASCo

stStud

yOverviewandRe

ference

•Significant

driversa

rehighlighted

inyellow:C

RASstandardiza

tionof

relaysettings,increased

automationintesting

process,andlong

term

redu

ctioninrelaycoun

tper

RAS.Nextslidedrillsd

ownfurthe

r.

23



Cos

t Per

Rel

ay: S

peci

fic C

ost F

acto

rs D

rivin

g C

RA

S Fa

vora

ble

Varia

nce

CRAS

isless

expe

nsivethan

tradition

al,stand

alon

eRA

Ss(ofthe

type

ofRA

Ssplanne

dto

bebrou

ghtinto

CRAS

).AThreemainareaso

fcostsavings

forC

RAS:

1.Re

lays:Lesslab

orfora

llRA

Ss,from

design

toim

plem

entatio

n(la

borisa

llocatedto

relays

from

design

on)

CRAS

relays

andfie

ldde

ploymentsarestandardize

dandtestingisautomated

andstream

lined

(vs.muchmore

labo

rintensivestandalon

eRA

Ss)–

significantred

uctio

nintestinglabo

r2.

Relays:A

llocatedlabo

rcostsassociated

with

chan

gesinRA

Ssaremuchless

onaverageforC

RAS

CRAS

Analyticchangesa

remucheasie

rtoprogram

andtestcentrally

Endto

endfie

ldcrew

testingistim

econsum

ingandexpe

nsive(one

ormorecrew

sate

achsubstatio

n,all

substatio

nsinRA

S,extend

edpe

riodof

time)

–isrequ

iredforstand

alon

eRA

Ssbu

tthe

testingmetho

dsforC

RAS

aremuchmorestream

lined

inthefie

ld,tho

ughthesamethings

arevalidated

.CRA

Sen

dto

endtestingproves

outthe

RASfunctio

nalitymoreefficiently.

CRAS

haso

nboard

automated

testtoolsa

ndismuchlesstim

econsum

ingto

testas

RASs

areadde

d.3.

Relaycoun

t:Less

relays

need

edlong

term

whe

nusingCR

ASdu

eto

relaysharingbe

tweenRA

Ss21

%fewer

relays

forC

RASinthelong

term

versus

standalon

eRA

Sapproach.

Dueto

somede

sign/settings

diffe

rences

basedon

standardiza

tion,CR

ASuses

10%morerelays

tostartw

ithand

over

timetheCR

ASrelaysharingadvantagekicksinto

give

fewer

relays

overall.

[A].Allnew

RASs,and

conversio

nRA

Ssthat

meetcriteria(com

plex

RAS,high

grow

threne

wablesa

rea)

15CR

ASCo

stStud

yOverviewandRe

ference

24



Gre

ater

Effi

cien

cy o

f CR

AS

Fiel

d Te

stin

gAfterind

ividua

lrelay

testingiscomplete(assum

ediden

ticalcostsfor

stan

dalon

eRA

Srelayan

dCR

ASrelay),req

uiredlabo

rdivergesd

ramaticallybe

tweenthetw

oalternatives:

•Standalon

eRA

Sfie

ldtestinguses

100%

physical/electricalinpu

tsas

provided

bybu

lkyfie

ldtestsets.The

testsetshave

tobe

hooked

upto

multip

lerelays

totestseveral“testplan

lines”(in

othe

rwords,run

throughaserie

sofsteps

inatest

scen

ario).

•Then

thetestsetleads

have

tocarefully

bediscon

nected

from

liverelayeq

uipm

entw

ithshockhazards.

•Ane

wseto

frelaysish

ookedup

usingtestleads.Thisusually

willrequ

iremovingthetestset.Then

anothe

rfew

test

plan

lines

canbe

done

.•Thisprocessisrep

eatedas

need

edto

completethetestplan

forthe

RAS,which

istypically

250–10

00lines

inlength.

•Thisisacumbe

rsom

e,manualprocessandcann

otbe

done

quicklybe

causeof

theshockhazardsa

nddangerou

ssubstatio

nenvironm

ent.

Diffe

rences

inCR

AStestingprocesstha

tdriv

elargelabo

rsavings:

•Inessence,CR

ASbe

nefitsfrom

itsability

toqu

icklyload

virtualscenario

swith

outreq

uirin

grepe

titiveph

ysicalinpu

ts.

•Thetestscen

ariosa

re,incompu

tingterm

sand

abilityto

validatetheRA

S,identical.

•Bu

tsettin

gthescen

ariosu

pandrunn

ingthem

with

fullfie

ldverificationcantake

minutes

insteadof

hours.

•Partof

thereason

forthisisthatp

riortestin

gof

theRA

Slogicisdo

neby

ITPo

wer

System

sCon

trolsp

riortofie

ldtesting(in

clud

edinITPSCcostsfor

CRAS

costs)andallthe

scen

ariosb

eing

referred

toarealreadyde

velope

dandeasy

toload

(essentia

lly“point

andclick”).

16CR

ASCo

stStud

yOverviewandRe

ference

25



Det

ail L

evel

/Bac

kup

Sect

ion

Purp

ose:

Set

s in

pla

ce th

e fa

ctor

s an

d as

sum

ptio

ns th

at d

rive

the

cost

equ

atio

ns•

Assu

mpt

ions

abo

ut fu

ture

RA

S g

row

th•

Diff

eren

ces

(CR

AS

ver

sus

stan

d-al

one

RA

S) i

n en

gine

erin

g an

d de

sign

•D

iffer

ence

s (C

RA

S v

ersu

s st

and-

alon

e R

AS

) in

test

met

hods

•Te

stin

g P

roce

ss F

low

Cha

rts (C

RA

S v

ersu

s st

and-

alon

e R

AS

)•

Gen

erat

or s

ite c

osts

for C

RA

S c

onve

rsio

ns (h

ow th

e co

sts

wer

e es

timat

ed fo

r 3 b

asic

type

s)•

Base

cos

ts u

sed

in e

quat

ions

(sum

mar

y ta

ble)

•Eq

uatio

n de

tails

: Bec

ause

onl

y ha

rd c

opy

prin

tout

s an

d P

DFs

are

pro

vide

d in

the

filin

g, th

ese

slid

es e

xpla

in

and

brea

k do

wn

the

8 ba

sic

RA

S c

ost e

quat

ions

from

spe

cific

cel

ls o

f the

CR

AS

Cos

t Sav

ings

Wor

kshe

et:

1.S

tand

-alo

ne R

AS

, New

, Yea

r 12.

Sta

nd-a

lone

RA

S, N

ew, Y

ear 2

and

follo

win

g3.

CR

AS

, New

, Yea

r 1

4.C

RA

S, N

ew, Y

ear 2

and

follo

win

g5.

Sta

nd-a

lone

RA

S, C

apac

ity U

pgra

de, Y

ear 1

6.S

tand

-alo

ne R

AS

, Cap

acity

Upg

rade

, Yea

r 2 a

nd fo

llow

ing

7.C

RA

S, C

onve

rsio

n of

Exi

stin

g S

tand

-alo

ne R

AS

, Yea

r 18.

CR

AS

, Con

vers

ion

of E

xist

ing

Sta

nd-a

lone

RA

S, Y

ear 2

and

follo

win

g

17CR

ASCo

stStud

yOverviewandRe

ference

26



GENER

ALAS

SUMPT

IONS–NormalDe

ploymen

tand

Future

Busine

ssas

UsualAssumptions

•Standalon

eRA

S:Years1

and2:Use

2relays/gen

erator

and1relay/gene

ratoryear3

on(ProtectionEngine

ering)

•ForC

RAS,assumesameas

standalon

e+10

%to

accoun

tfor

diffe

rences

inCR

ASrelaysettings

(Protection

Engine

ering)

•Forstand

alon

eRA

Srelaycapacityup

grade(existingRA

SlikeCo

lorado

River)assumeaddrelayCP

Umod

uleand

upgraderelaypo

wer

supp

ly.Testeach

relaylocally

afterflashingne

wfirmware.Then

dofie

ldcrew

endto

endtestfor

themod

ified

standalon

eRA

S.(ProtectionEngine

eringandSC&M

Test)

•Telecom

assumptions

forR

ASs(whe

ther

CRAS

orstandalon

e)mandatedby

WECC:

99.95%

availabilityeach

path,

dualredu

ndantp

aths

requ

iredwhe

retelecom

isused

.(ProtectionEngine

ering)

Forw

ardLook

ingAssumptions

•Use

year

2030

astarget

form

axim

umrelaysharingby

CRAS

.Thatism

andatory

year

for5

0%rene

wablesa

ndqu

eue

sizes

andgrow

thprospe

ctssup

portthisou

tlook.(System

Planning)

•Use

21%lessrelays

forC

RASversus

standalon

eRA

Sapproach

perthe

agreed

relaysharingcoststud

yincorporated

in20

15GR

Cfiling

(ProtectionEngine

ering)

•ExistingRA

SsinCR

Tde

ck(W

hirlw

ind,Co

lorado

River,MojaveDe

sert)a

rerunn

ingou

tofcapacity

basedon

arming

pointsanalysisandrene

wablesq

ueue

analysis.

(ProtectionEngine

eringandSystem

Planning)

•NorthernArea

RAS,ane

wRA

Swith

76–12

4armingpo

ints(QC8

total–

QC9

total)requ

iredby

System

Planning,

cann

otbe

done

asastandalon

eRA

S(stand

alon

erelaycapacityup

gradeapproach

nota

dequ

atebasedon

available

relayfirmwareup

grades).

(ProtectionEngine

eringandSystem

Planning)

18CR

ASCo

stStud

yOverviewandRe

ference

27



ENGINEERINGAN

DDE

SIGN

ASSU

MPT

IONS–Stan

dAlon

eRA

San

dCR

ASStan

dalon

eRA

Ss•

Weknow

that

engine

eringandde

signsoak

upalargepe

rcentage

oflabo

r(abou

t45%

oftotalbased

onrecorded

costs).

•Thesecostsn

eedto

berefle

cted

incapacityup

grades

toan

existingstandalon

eRA

Sas

wellaslater

gene

ratio

nadditio

ns.

•Major

activ

ities

involved

perchangeinStandAlon

eRA

S:1.

Abou

t3mon

thso

fEngineerin

geffortby

Engine

eringTeam

.(Typical2

FTE,may

bemorebasedon

complexity

ofthechange)

oActiv

ities

includ

e,gene

ratin

gandreview

ingne

wde

sign

oGe

neratin

gne

wdraw

ings

tomatch

with

newde

sign

oProcureadditio

nalhardw

are(gen

eratebillof

material,placetheorde

rand

ensure

itreache

ssub

station)

2.Ab

out1

mon

thof

Protectio

nEngine

er'seffortto

writethetestplan

andgene

rate

testcases.(Typical1FTE)

oRe

view

thene

wde

signandgene

rate

testplan

oGe

nerate

andreview

testcases

3.Forb

asecase

RAS,abou

t1weekof

testingwith

testcrew

inthefie

ld(Abo

ut2days

forA

sideand2days

forB

sidewith

onedaycontingency).

oDe

pend

sonnu

mbe

rofsub

stations

andcrew

sneede

d,1Protectio

nEngine

er,1

Supe

rviso

r.o

PerH

owardHa

m(ProtectionEngine

ering),PSC

wou

ldhave

tested

thetarget

armingselection(based

onrequ

iredcontingencies)priortofie

ldtesting.

oDu

ringFieldtesting,on

lythene

wchangesa

retested

,acrossa

llrelays

affected

.19

CRAS

CostStud

yOverviewandRe

ference

28



ENGINEERINGAN

DDE

SIGN

ASSU

MPT

IONS–Stan

dAlon

eRA

San

dCR

ASCR

AS•

Comparedto

standalon

eRA

S,hasa

diffe

rent

andlessfreq

uent

patternof

rede

signs

basedon

itsmoreefficient

metho

dsof

testing.

•ForC

RAS,rede

signs

areno

ttrig

geredby

each

gene

ratora

ddition

,but

typically

aredo

neon

anannu

albasis.Testin

ginvolvingthefie

ldcrew

scoversa

llthesameplanne

dgene

ratorsandallpermutations

ofcontingenciesa

sastand

alon

eRA

Swou

ldtestbu

tdon

einadvance.

•Individu

allocalrelay

testing(prio

rtoen

dto

endfie

ldtesting)isassumed

tobe

thesamecostforstand

alon

erelays

orCR

ASrelays.

•Someextratim

eisinclud

edinthe“CRA

SRe

ductionFactor”that

isused

tocalculateCR

AStestingcostsp

erroun

dof

testversus

astandalon

eRA

Spe

rrou

ndof

test.The

purposeof

theextratim

eisto

allowcrew

sand

testsupe

rviso

rsto

becomeused

tothene

wmetho

dsof

CRAS

endto

endtesting.

oInitialassumption:

One

crew

persub

station,tw

odays

duratio

n.(Thisisw

hatcoststudy

uses).

oLong

term

assumption:

One

crew

perR

AS,twodays

duratio

npe

rRAS

.(Thisisalong

term

goal,not

refle

cted

inthecoststud

yeq

uatio

ns).

oEven

shorterd

urations

perrou

ndof

CRAS

testingareclearly

feasible,but

SCEistrying

tokeep

assumptions

for

CRAS

timesavingsc

onservativeforn

ow(highe

rduration).See

“initia

lassum

ption”

above.

•Thereisalso

additio

naltestin

gusingRT

DSor

othe

rautom

ated

toolsintheearlier

CRAS

analytictestph

asethat

gowellbeyon

dwhatisp

ossib

lewith

standalon

etesting.CR

AStestingisthereforehigher

quality

(morecompreh

ensiv

e,checks

form

orepo

ssiblescen

ariosa

ndresulting

RASbe

haviors).

•ForC

RAS,laterred

esigns

assumed

done

annu

ally,

coverin

gallgen

eratorsp

lann

edto

beadde

dinthecomingyear.

20CR

ASCo

stStud

yOverviewandRe

ference

29



TESTINGAS

SUMPT

IONS–Individu

alRe

lays

andCa

pacity

Upgrade

sIndividu

alrelaytesting(prio

rtofie

lden

dto

endtesting):

•Assumed

identicalforC

RASandStandalon

e(in

clud

edinfully

loaded

relaycostsfor

each

optio

n,en

dsup

beinga

washcostandthereforehasn

oim

pacton

thecostbe

nefits/avoidances

forC

RAS).O

neexception:

capacityup

grades

–seebe

low.

•Note:Inreality,itw

ouldbe

reason

ableto

expe

ctsomeefficienciesfrom

CRAS

’stand

ardizedsettings

with

onlytw

omajor

optio

ns,m

itigatio

nor

mon

itorin

g,versus

theindividu

allycustom

izedsettings

ofstandalon

eRA

Srelays.

•Itwou

ldbe

reason

ableto

expe

ctfurthe

rlearningcurvebasedassumptions

todrivelower

costsfor

CRAS

inthe

future,since

therecorded

costsw

eused

werethevery

firsttim

eSCEhaddo

neCR

AS.W

eshou

ldgetb

etterw

ithpractice.SCEhasn

otattempted

tomod

elthisaspe

ctof

learning

curveim

provem

entsintheCR

AScoststud

y.

Stan

dAlon

eRA

SCa

pacity

Upgrade

s•

One

area

whe

reindividu

altestingdo

esne

edto

befactored

iniscapacityup

grades

forstand

alon

eRA

Srelays.This

change

triggersindividu

alrelaytestingas

wellase

ndto

endtesting.

•Individu

alrelaytestingaftercapacity

upgradeassumes

tworelays

individu

allytested

pertesttechpe

rday

(not

includ

ingen

dto

endtestingcosts)

•One

aspe

ctthat

isim

portanttoremem

berw

ithfie

ldworkisthereis“m

orethan

justtesttechs”

involved

(sup

ervisio

n,MPO

,other

supp

ortin

gpe

rson

nel,etc.)(Re

corded

costsreflectthis)

•Tw

ocompo

nents:

1.Re

desig

nanden

gine

eringsupp

ortp

ertestcyclepe

rRAS

,calculatedusingprop

ortio

nalrelay

recorded

costsfor

a)en

gine

eringandde

signversus

b)im

plem

entatio

nandtestinthefie

ld–calculated

perrelay

acrosstheRA

S,pe

rtestcycle

21CR

ASCo

stStud

yOverviewandRe

ference

30



TESTINGAS

SUMPT

IONS

Stan

dAlon

eRA

SCa

pacity

Upgrade

s–Co

ntinue

d2.

Additio

nalsup

portcostsinthefie

ld(sup

ervisio

n.MPO

,etc.)pe

rrelay

(cross

checkedusingprop

ortio

nalrelay

data

asin#1above)

•Existingrelays

andretestingandsupp

ortin

gcosts

oThisisaccoun

tedforinthefully

loaded

costsp

errelayforn

ewrelays

inthecoststud

y,whe

ther

CRAS

orstand

alon

e(based

onrecorded

costs)

oNeeds

tobe

refle

cted

inadditio

nalcostsforthe

standalon

eretestingfore

achtestcycle(Coststudy

willrefle

ctthis,

basedon

recorded

data)

CRAS

uses

asim

ilarcon

cept,but

itslessfreq

uent

desig

neffortsa

ndmoreefficient

testingapproach

minim

izethese

supp

ortin

gcosts.ForC

RAS,asim

plifyingassumptionisthat

they

arebakedinto

the2days

percrewpe

rsub

stationpe

rtestcycleassumption.Thisisaconservative(highdu

ratio

n)assumption.

Triptestingwith

theindividu

algene

rator:

•IdenticalforC

RASandStandalon

e,1day(8

hours)pe

rgen

erator,one

twoman

crew

•Thesecastareawashbe

tweenthetw

oop

tions

andareno

tdire

ctlyused

inthecoststud

y.

22CR

ASCo

stStud

yOverviewandRe

ference

31



TESTINGAS

SUMPT

IONS(m

ostly

SC&M

Test)

Stan

dAlon

eRA

STesting

Stan

dalon

eTesting

•Everygene

ratora

dded

causes

aroun

dof

fieldcrew

endto

endtesting

•Capacity

upgrades

torelays

causeindividu

alretestingof

upgraded

relayandaroun

dof

testingfora

llrelays.

•AllSCE

substatio

nsrequ

ireat

leasto

necrew

each

•Crew

sper

substatio

nestim

ated

byon

etesttech

per4

relays

•Du

ratio

npe

rtestcycle:Variesw

iththe“durationfactor”o

fthe

RASinvolved

.See

slide

s35and36

.•

Note:One

impo

rtantrealizationconveyed

bySC&M

TestManagem

entisthatthe

rearesig

nificantcon

straintson

the

numbe

roftesttechs

totalthatcan

bemob

ilizedforthisk

indof

testingas

astandalon

eRA

Sbe

comes

morecomplex.

Thisiscaused

bythede

pend

ency

betw

eenDo

bletestsetsandho

wmanyrelays

itisfeasiblefora

singletesttech

toho

okup

to.

•Thecoststud

yhasa

calculator

togene

rate

thenu

mbe

roftesttechs

need

edpe

rsub

station(and

overall,forthe

RAS)

astheoverallrelay

coun

tincreases.Thisisc

apturedas

“excessfieldcosts”

intheRA

Scosteq

uatio

ns,asfurther

mappe

dou

tinde

tailinlaterslides.

23CR

ASCo

stStud

yOverviewandRe

ference

32



TESTINGAS

SUMPT

IONS–CR

ASTesting

1CR

ASTesting

•AllSCE

substatio

nsrequ

ireon

etw

oman

crew

each

inyear

oneandtw

ofora

givenRA

S(Thisislikelyto

beexcessive

basedon

conversatio

nwith

SC&M

TestandSC&M

TestManagem

ent,bu

titw

illtake

timeto

getfieldcrew

scomfortablewith

thediffe

rent

testmetho

dsforC

RAS).

•Four

oppo

rtun

ities

overalltofamiliarize

testtechsw

ithne

wtestmetho

ds:

1.Targeted

training

toanytesttechsn

otyetfam

iliar

with

CRAS

testingmetho

ds:

oCR

ASlogicisresid

entincontrolcenterserversandPSC(Pow

erSystem

sCon

trols)createsthe

analytics.Testscen

arioinform

ationisloaded

byPSCwith

SC&M

fieldtesttechsv

iewingthat

inform

ationandverifying

perfo

rmance

usingmorestream

lined

metho

dsthan

astandalon

eRA

Swou

ldrequ

ire.The

refore,CRA

Sismorearou

ndtraining

anyne

wtechs,no

tyet

familiar

with

test

metho

ds.Thisisa

ssum

edto

bean

ongoingde

partmentalcost.Itwillrampdo

wnover

timeas

RASs

inCR

ASoccurm

ainlyingene

ratio

nrichareas.

oNote:By

contrast,stand

alon

eRA

Sareun

ique

custom

desig

ns,eachandeverytim

e–thisim

posesa

leveloffam

iliariza

tionwith

each

newRA

S,everytim

e,on

going.Re

flected

intestplan

developm

ent

anden

gine

eringcosts.

2.Testingandfamiliariza

tionby

testtechsw

ithstaged

relays

atAlhambrapriortoinitialim

plem

entatio

n.3.

Annu

altestingdo

neon

anyRA

SinCR

ASgiveso

pportunity

toob

serve&learn.

4.Actualde

ploymenta

ndtestingof

CRAS

inthefie

ldfurthe

rreinforcesthe

learning.

24CR

ASCo

stStud

yOverviewandRe

ference

33



TESTINGAS

SUMPT

IONS–CR

ASTesting

2•

Each

relay:Ch

eckinpu

tvoltagesa

ndcurrentssuccessfullysent

toEM

S(Dob

letestsetsused

forthis)

•Use

CRAS

annu

altestto

confirm

mitigatio

nsig

nalsentb

yUA

Pandrelaytripou

tput

contactcloses.Inyear

one,the

duratio

nassumptions

allowforlim

itedtestingof

Dobleinitiated

scen

arios,bu

tthe

preferen

ceisto

usestaged

relays

atAlhambrabefore

deploymentinfie

ldto

provideamorecompactandefficient

testingenvironm

ent.

oSimulatesamescen

arios(setsof

contingencies)as

wou

ldbe

done

with

standalon

eRA

S,bu

tusin

gCR

ASon

boardtoolso

rRTD

S,no

tusin

gDo

bles.

oDu

ratio

n:As

notedon

slide

s35and36

,a“durationfactor”isused

basedon

relativenu

mbe

roftestlines

inthe

testplan

forthe

RASun

dercon

siderationversus

thebase

case

RAStestlines.

•Testingcanbe

done

once

pery

earfor

allplann

edgene

ratorsto

beadde

d(assum

esallnecessary

relays

areinplace)

•Note:Wealso

addincostse

achyear

forP

SCanalyticde

signandtestas

wellasred

esigns/add

ition

seachyear

thereafte

r

25CR

ASCo

stStud

yOverviewandRe

ference

34



26

RelayTestSequ

ence

forcom

missioning

aRA

SSche

me

RelayInstall

RelayUnitTest

RelayPo

inttoPo

intTest

RelayEndto

EndTest

Thisisthetesting

segm

entthath

asvery

diffe

rent

labo

rimpacts

forS

tand

alon

eRA

Sversus

CRAS

Samelabo

rimpacts

forS

tand

alon

eRA

Sversus

CRAS CR

ASCo

stStud

yOverviewandRe

ference

35



27

RelayUnitTestin

g

1.TS&Sde

velops

relaytestscrip

tsandshares

them

with

TestTechsfor

execution.

2.SC&M

TestTechsinstalls

relays

andload

therelaysettings

issue

dby

Protectio

n.3.

SC&M

TestTechsp

erform

sunittestin

gof

therelay.

CRAS

CostStud

yOverviewandRe

ference

36



28

RelayPo

inttoPo

intTestin

g(CRA

SShow

n)Po

inttoPo

intT

estin

g

UAP

XA21

Objectiv

eVe

rifypo

intm

apping

with

UAP

,XAandeD

NA.

ValidateGO

OSE

message

from

relay

GOOSE

Simulator

Relay

PhysicalParameters

such

asVo

ltage,

Curren

tsandPo

wer

UAP

XA21

Step

1

Step

2

Step

1(Perform

edby

PSC):

1.Validatepo

intm

apping

with

UAPandXA

21priortovalidatingthepo

intswith

relays.

2.Allrelay

pointswillbe

simulated

usinga

GOOSE

simulator

totestUA

PsandXA

data

flow.

Step

2(Perform

edby

SC&M

andPSC):

1.Validaterelaypo

intsby

simulatingph

ysical

parameters.

2.Programmaticapproach

fortestin

gthe

points.

3.Priorvalidationwith

inUA

PandXA

wou

ldhave

significantsavings

ontestingsche

dule

andfie

ldresources.

CRAS

CostStud

yOverviewandRe

ference

37



29

Tradition

alEndto

EndTesting(Stand

alon

eRA

S)

1.Highlylabo

rinten

sive.

2.With

increasednu

mbe

rofrelays(forincreased

load

and/or

numbe

rofgen

erators)thisadds

substantialsched

uleim

pactto

testing.

3.As

RASs

getm

orecomplex,crewrequ

irements

calculations

incoststud

yspreadsheetsho

wthat,for

thiskind

oflabo

rintensivetesting,

SCE’slocalandregion

alavailablecrew

coun

tswillbe

greatly

exceed

ed,m

akingthestand

alon

eapproach

infeasibleinanypractical

busin

esss

ense

becauseof

indu

stry

wide

constraintson

thesehighlyskilled

,scarce

resource

person

nel.

CRAS

CostStud

yOverviewandRe

ference

38



30

CRAS

Endto

EndTesting

1.Multip

lescen

ariosc

anbe

simulated

andtested

.2.

Testingoverlapbe

tweenun

ittesting,P2

Ptesting,therefore

notm

uchof

impactby

usingsim

ulators.

3.Fewselected

scen

ariosw

illbe

simulated

such

that

UAP

issue

strip

toan

actualmitigatio

nrelay.(Hybrid

approach).

4.Alltestscriptsshallbevery

detailedverifying

everyinpu

tand

output.

5.Subset

oftestscrip

tswillbe

defin

edby

TS&Sthat

wou

ldne

edto

beob

served

byTestTechsp

riortosig

ning

offo

nthe

testresults.

6.GO

OSE

Simulator

orRT

DSshalluse

relaysettingfileforthe

irconfiguration.

7.RT

DSTraining

willbe

requ

iredforT

S&Sandpo

ssiblySC&M

TestTechs.

8.Forn

extfew

RASs

TS&Spreferstohave

oneroun

dof

endto

endtesting(limite

d)priortonextfewRA

Ssgoinginto

Prod

uctio

n.CR

ASProgram

Managem

ent’s

suggestio

nisto

usestaged

relays

atAlhambraforthisp

urpo

se(m

ore

efficient

testingenvironm

ent).

CRAS

CostStud

yOverviewandRe

ference

39



Gene

ratorS

iteCo

stsfor

ExistingGe

nerators

Gen

erationProject

RAS

#CB

sType

Scop

eCo

stGe

nesisI

Colorado

River

2Standard

One

rack

with

2relays

150,000

$Ge

nesisII

Colorado

River

2Standard

One

rack

with

2relays

150,000

$BlackCree

kCo

lorado

River

4Standard

One

rack

with

2relays

150,000

$Dracker

Colorado

River

4Standard

One

rack

with

2relays

150,000

$Alba

MojaveDe

sert

1Standard

One

rack

with

2relays

150,000

$Ocaso

MojaveDe

sert

1Standard

One

rack

with

2relays

150,000

$LSP220kV

lineatKram

erMojaveDe

sert

2Standard

One

rack

with

2relays

150,000

$Av

enue

AWhirlw

ind

3Standard

One

rack

with

2relays

150,000

$Av

enue

BWhirlw

ind

2Standard

One

rack

with

2relays

150,000

$Kingbird

Whirlw

ind

2Standard

One

rack

with

2relays

150,000

$Free

bird

Whirlw

ind

4Standard

One

rack

with

2relays

150,000

$SolarR

anch

AWhirlw

ind

1Standard

One

rack

with

2relays

150,000

$SolarR

anch

Whirlw

ind

1Standard

One

rack

with

2relays

150,000

$

Soleil:

Whirlw

ind

3Standard

1CB

atplant1,2

CBsa

tplant

2(sep

araterelays

atthetw

oplants,

butthe

ybo

thtripatthesametim

e)150,000

$

Astoria

:Whirlw

ind

7Special

4CB

satp

lant

1,3CB

satp

lant

2(sep

araterelays

atthetw

oplants,

butthe

ybo

thtripatthesametim

e)Sameapproach

asatTedd

y)see

belowand"Ted

dy"tab).

290,000

$

Garla

nd:

Whirlw

ind

6Special

1CB

atplantA

,5CB

satp

lant

B/C(sep

araterelays

atthetw

oplants,but

they

both

tripatthesametim

e).

290,000

$Ro

yWhirlw

ind

4Standard

One

rack

with

2relays

150,000

$Tedd

yph

ases

1and2

Whirlw

ind

4Standard

One

rack

with

2relays

150,000

$

Tedd

yWhirlw

ind

9Special

Multip

leph

ases

seeno

teso

n"Ted

dy"tab.Phases3

and4:6CB

s.Tedd

yph

ase5willadd3moreCB

s.4racks,6relays

total

540,000

$Total

3,520,000

$Av

eragepe

rSite

185,263

$

31CR

ASCo

stStud

yOverviewandRe

ference

40



Pha

se 1

& 2

Bld

g

4CB

tripping

relays

(2)

CommAg

gregator

Relays

(2,A

&B)

Altogether:

2racks,2relays

each

Pha

se 3

& 4

Bld

g

6-C

B tr

ippi

ng re

lays

(2)

= O

ne ra

ck, A

&B

, 2

rela

ys to

tal

Pha

se 5

Bld

g

6-C

B tr

ippi

ng re

lays

(2)

= O

ne ra

ck, A

&B

, 2

rela

ys to

tal

ExistingGe

nerators–Standard

Approach

versus

Special

Gen

erat

ion

Pro

ject

4C

Bs

to tr

ip o

r les

s

4CB

tripping

relays

(one

Asid

e,on

eB

side)

1rack,2

relays

total

Stan

dard

(Type1,Co

versmajority

Ofcustomers)

SpecialUsing

“Ted

dy”as

exam

ple

(Twodiffe

rent

“recipes,”Type

2an

dType

3,coverrem

aining

custom

ers)

Tedd

yph

ases

3,4,and5aretrippe

dwith

thesamearmingpo

int,requ

iring

tripping

atotalof9

CBs.Ph

ases

3and4areinon

econtrolbuilding,and

phase5isinaseparate

controlbuilding.ForTed

dyph

ases

1and2,a4CB

tripping

relaywilldo

thejob.Forp

hases3

,4,and

5,aCo

mmun

ications

Aggregator

relaywillbe

need

edintheph

ases

1and2controlbuilding(w

here

thetelecommfrom

Whirlw

indterm

inates),with

a6CB

tripping

relay

locatedintheph

ases

3and4controlbuildinganda6CB

tripping

relaylocatedintheph

ase5controlbuilding.Existingfib

ersw

illconn

ectthe

tripping

relays

totheCo

mmun

ications

Aggregator

relayviaGO

OSE.

32CR

ASCo

stStud

yOverviewandRe

ference

41



ExistingGe

nerators–Standard

Approach

Details

One

rack

with

2relays

–coversmostcustomer

situatio

ns(Type1of

3)Telecom

•$1

0Ktotal:N60

relayspec

with

DirectI/Ouses

C37.94

protocol(con

firmed

byProtectio

nEngine

ering).Thecostfor2

newOHS

Uchanne

lcards

(A&Bsid

es)inan

existingchanne

lbankwith

labo

risa

bout

$10,00

0.$2

,300

fore

achcard

andtotalof4

Engine

eringman

days

and4Tech

man

days

(based

onTelecom’sstandard

estim

atingtool).–from

Telecom

Engine

eringem

ail6/16/16

•Other

telecom

(existingchanne

lbanks

andfib

er)alre

adyinplaceor

requ

iredat

gene

ratorcustomer

expe

nse.

Costsp

er2relayrack,pre

fabb

edandde

livered

•Perrecorde

dcosts,wehadStationElectriccharge

us$5

44,445

forw

iring

onCR

ASProject.With

26relays

with

inSCEandassuming2relays

per

rack,thisc

omes

to13

racksw

ired@

$41,88

0pe

rrack.Weassumeprefabb

edrack

costto

be$5

0Keach

(with

escalatio

nandsomecontingency).

•Re

lays

=$1

5Keach

*2=$3

0K.

Gene

ratorO

nSite

Labo

rCosts

•Ap

prop

riate

duratio

nsandcrew

numbe

rsprovided

bySC&M

Test

•Includ

estim

econtingency.Theserelays

aresim

pler

than

averageinsettings.

•Calculation:

One

crew

(firstw

iring,the

ntest)X

2men

/crewX20

busin

essd

aysX

8ho

urs/dayX$1

50/hou

r=$5

0Kwith

roun

ding

•Outagecoordinatio

n&gene

ratorsite

trip

testing=$5

K•

Total$55

Kwith

roun

ding.

Bmaterials(m

iscellane

ousw

ire,jum

pers,etc.)

•$5

K

Total=

$10K+$5

0K+$3

0K+$5

5K+$5

K=$1

50Kpe

r2relayrack

completepe

rstand

ardapproach

33CR

ASCo

stStud

yOverviewandRe

ference

42



ExistingGe

nerators–“Spe

cial”Ap

proach

Details

SpecialA

pproachCo

stFactors

TwoRa

cks,2relays

each

(Type2of

3)Scop

e:Afewof

theup

cominggene

ratorcustomers(such

asGa

rland

onslide

25)tobe

conn

ectedhave

moregene

ratorcircuitb

reakerstotripthan

the

“Stand

ard”

approach

canhand

le.This“

Special”approach

hand

lesu

pto

8gene

rator C

Bswith

minor

adjustmentsinconfiguration.

Telecom

•$1

0Ktotal:N60

relayspec

with

DirectI/Ouses

C37.94

protocol(con

firmed

byProtectio

nEngine

ering).Thecostfor2

newOHS

Uchanne

lcards

(A&B

sides)inan

existingchanne

lbankwith

labo

risa

bout

$10,00

0.$2

,300

fore

achcard

andtotalof4

Engine

eringman

days

and4Tech

man

days

(based


estim

atingtool).–from

Telecom

Engine

eringem

ail6/16/16

•Other

telecom

(existingchanne

lbanks

andfib

er)alre

adyinplaceor

requ

iredat

gene

ratorcustomer

expe

nse.

Costsp

ertw

o2relayracks,prefabb

edan

dde

livered

•Perrecorde


us$5

44,445

forw

iring

onCR

ASProject.With

26relays

with


perrack,this

comes

to13

racksw

ired@

$41,88

0pe


edrack

costto

be$5

0Keach

(with

escalatio

nandsomecontingency).=

$50*2racks =

$100

K•Re

lays

=$1

5Keach

*4relays

=$6

0K.

Gene

ratorO

nSite

Labo

rCosts

•Ap

prop

riate

duratio

nsandcrew

numbe

rsprovided

bySC&M

Test

•Includ

estim


aresim

pler

than

averageinsettings.

•Calculation:

One

crew

(firstw

iring,the

ntest)X

2men

/crewX20

busin

essdays

X8ho

urs/dayX$1

50/hou

r=$5

0Kwith

roun

ding


n&gene

ratorsite

trip

testing=$5

K•Total$55

Kpe

rrackwith

roun

ding.=

$55K*2racks=

$110

K.

Bmaterials(m

iscellane

ousw

ire,jum

pers,etc.)

•$1

0K

Total=

$10K+$1

00K+$6

0K+$1

10K+$1

0K=$2

90Kpe

rtwo2relayracksc

ompletepe

rspe

cialap

proa

ch

34CR

ASCo

stStud

yOverviewandRe

ference

43



ExistingGe

nerators–“Ted

dy”ProjectE

xample

SpecialA

pproachCo

stFactors–

forsitu

ations

likeTedd

yprojectfrom

slide25

Four

Racks,2relays

each

–9+Ge

neratorC

Bs(Type3of

3)Scop

e:Afewof

theup

cominggene

ratorcustomers(such

asGa

rland

onslide

25)tobe

conn

ectedhave

moregene

ratorcircuitb

reakerstotripthan

the

“Stand

ard”

approach

canhand

le.This“

Special”approach

hand

les9

ormoregene

ratorC

Bswith

minor

adjustmentsinconfiguration.

Telecom

•$1

0Ktotal:N60

relayspec

with

DirectI/Ouses

C37.94

protocol(con

firmed

byProtectio

nEngine

ering).Thecostfor2

newOHS

Uchanne

lcards

(A&B

sides)inan

existingchanne

lbankwith

labo

risa

bout

$10,00

0.$2

,300

fore

achcard

andtotalof4

Engine

eringman

days

and4Tech

man

days

(based


estim

atingtool).–from

Telecom

Engine

eringem

ail6/16/16

•Other

telecom

(existingchanne

lbanks

andfib

er)alre

adyinplaceor

requ

iredat

gene

ratorcustomer

expe

nse.

Costsp

erfour

2relayracks,prefabb

edan

dde

livered

•Perrecorde


us$5

44,445

forw

iring

onCR

ASProject.With

26relays

with


perrack,this

comes

to13

racksw

ired@

$41,88

0pe


edrack

costto

be$5

0Keach

(with

escalatio

nandsomecontingency).=

$50*4racks=

$200

K•Re

lays

=$1

5Keach

*8relays

=$9

0K.

Gene

ratorO

nSite

Labo

rCosts

•Ap

prop

riate

duratio

nsandcrew

numbe

rsprovided

bySC&M

Test

•Includ

estim


aresim

pler

than

averageinsettings.

•Calculation:

One

crew

(firstw

iring,the

ntest)X

2men

/crewX20

busin

essd

aysX

8ho

urs/dayX$1

50/hou

r=$5

0Kwith

roun

ding


n&gene

ratorsite

trip

testing=$5

K•Total$55

Kpe

rrackwith

roun

ding.=

$55K*4racks=

$220

K.

Bmaterials(m

iscellane

ousw

ire,jum

pers,etc.)

•$2

0K

Total=

$10K+$2

00K+$9

0K+$2

20K+$2

0K=$5

40Kpe

rfou

r2relayracksc

omplete

35CR

ASCo

stStud

yOverviewandRe

ference

44



Base

CostsU

sedInEquatio

nsinCR

ASCo

stStud

yWorkshe

et

36CR

ASCo

stStud

yOverviewandRe

ference

RASType

CostFactor

Descrip

tion

2015

StandAlon

eLong

Term

RelaySharing

AsRA

Sscontinue

togrow

andprolife

rate

inremew

ablesrich

areas,overlaps

occur.CR

AScansharerelays,stand

alon

ene

edsa

ddition

alrelays.

0

Changesp

erYe

arAssumed

changesp

eryearinrene

wablesrichareas

0

CRAS

AnalyticTestingcostsp

erchange

inCR

AS(IT

Testing

cost)

Thisisanalytictestingcostfore

verycompleteCR

ASde

sign.

ByPSC,verifieso

utto

andinclud

ingtripof

relay.

100,800

$

CRAS

Additio

nalA

nalytic

Testing

Form

odificatio

nsto

existin

gCR

ASde

sign

64,800

$

CRAS

CRAS

RelayTotalCost

Installnew

relayandgetitind

ividually

ready.Includ

eslabo

randmaterial.Noen

dto

endtesting.

120,715

$

CRAS

CRAS

Existin

gGen

erator

Cost

Costinyearon

eto

payform

odificatio

nsto

existin

gIntercon

nectionFacilities

SCEpays

185,263

$

CRAS

CRAS

RelayRatio

Ratio

with

StandAlon

eRe

lays

is1.1:1

(i.e.10%more)

becauseof

somede

sign

diffs

TestTech

Rate

Rate

perh

our

75

StandAlon

eTestingcostsp

erchange

instandalone

RAS

Thisisadditio

naltestin

gcostfore

verychange

madeun

der

standalone

costso

npe

rrelay

basis.Note:Allrelaysm

ustb

eretested

whe

nne

won

esareadde

d.20,000

$

StandAlon

eRe

laymod

ulecostsfor

standalone

RASs

1CP

Umod

uleand1Po

wer

Supp

lymod

ule(existRA

Srelay

upgrade)

8,000

$

StandAlon

eStandAlon

eRe

layTotalCost

Installnew

relay,standalone

RAS.Escalatedvaluebasedon

2009

2010

recorded

costs.Includ

eslabo

rand

material.

200,570

$

2015

Dollarsareshow

n.Co

sts

areescalatedat

3%pe

ryear

anddraw

nfrom

columns

totherig

htinthecoststud

yto

match

theyear

oftheRA

Sun

dercon

sideration

45



New

RASCo

st–StandAlon

eRA

SYear

1=L47

*L$3

4/10

00+IF(L51

<1,0,L47

*L$3

2*(L51

1)/100

0)+L50

+IF(L44

=0,0,L44

*L47

*L$3

2*0.5*(L51

1)/100

0)+L44*L50

1)Accoun

tfor

costof

newrelays

Totalrelays*

newrelaycosteach/100

0L47*L$34

/100

02)

Addexcesscoststofirstroun

d,over

thebase

case

testroun

dcostinclud

edwith

relay,ifany:

+(IF

(durationfactor

<1,0,nu

mbe

rofrelays*

((per

relaybase

case

testroun

dcost+excessfie

ldsupp

ortcosts)*

duratio

nfactor)–

base

case

testroun

dcost))/10

00+excessfie

ldsupp

ortcostsifany

+IF(L51

<1,0,L47

*L$3

2*(L51

1)/100

0)+L50

3)Ad

dsubseq

uent

testroun

dsthat

year

with

ongoingredu

ctionfactor,ifany.

+(IF

(new

gene

rators=0,0,ne

wgene

rators*nu

mbe

rofrelays*

(per

relaybase

case

testroun

dcost*on

goingredu

ction

factor

*(durationfactor

–1))/10

00+excessfie

ldsupp

ortcostsifany

+IF(L44

=0,0,L44

*L47

*L$3

2*0.5*(L51

1)/100

0)+L44*L50

Note:Thiseq

uatio

ncomes

from

NorthernArea

RAS,cellL52of

workshe

et,w

hich,despite

beingabrandne

wRA

S,hassom

eexisting

gene

ratio

ncustom

ersa

lreadyconn

ectedto

anothe

rRAS

.The

assumptionisthat

fora

llsuch

existingcustom

ers,thestandalon

eRA

Swill

bebu

iltwith

enou

ghrelays

forthe

existingcustom

erstotransfer

over,w

ithallthe

testinginon

eroun

d.New

gene

ratorslaterthatyear

willeach

causeon

eroun

dof

additio

naltestin

gas

theirrelaysg

etadde

d.Thisisbe

causeSCEhastoaccommod

ateeach

newcustom

er’s

diffe

rent

operatingdate.See

earlier

slide

sfor

howthepatternandfreq

uencyof

standalon

eRA

Stestingdiffe

rsfrom

CRAS

.

37CR

ASCo

stStud

yOverviewandRe

ference

46



New

RASCo

st–StandAlon

eRA

SYear

2On

=(M47

L47)*M

$34/10

00+IF(M51

<1,0,(M

47L47)*M

$32*0.5*(M

511)/100

0)+M

50+IF(M44

=0,0,L44

*L47*L$32

*0.5*(L51

1)/100

0)+IF(M44

<2,0,(M

441)*M

47*L$3

2*0.5*(L51

1)/100

0)Accoun

tfor

costof

newrelays

New

relays

*ne

wrelaycosteach/100

0Note:Theseinclud

eon

lybase

case

RAStestroun

dcost

=(M47

L47)*M

$34/10

00Ad

dinanyexcessfirsttestroun

dcoststothene

wrelays

that

year

usingdu

ratio

nfactor

forR

ASun

dercon

sideration

+IF(durationfactor

<1,0,(new

relays

*pe

rrelay

base

case

testroun

dcost*o

ngoing

redu

ctionfactor*(durationfactor

1))/10

00)+

excessfie

ldsupp

ortcosts

IF(M

51<1,0,(M

47L47)*M

$32*0.5*(M

511)/100

0)+M

50Ad

dallexistingrelays

testcostforfirstrou

ndusingon

goingredu

ctionfactor

toadjust

+IF(durationfactor

<1,0,(existingrelays

*pe

rrelay

base

case

testroun

dcost*on

goingredu

ctionfactor

*(durationfactor

–1))/10

00)

+IF(M

44=0,(L44*L47*L$32

*0.50

*(L51

1))/10

00)

Addanyadditio

naltestrou

ndcostsa

fter the

firstroun

dcaused

byfirstgene

ratoru

singon

goingredu

ctionfactor

toadjust

+IF(new

gene

rators<2,0,((n

ewgene

rators–1)

*totalrelays*

perrelay

base

case

testroun

dcost

*on

goingredu

ction

factor

*(durationfactor

–1))/10

00)+

(new

gene

rators–1)

*M50

+IF(M44

<2,0,((M

441)*M

47*L$3

2*0.50

*(L51

1))/10

00)+(M

44–1)

*M50

38CR

ASCo

stStud

yOverviewandRe

ference

47



New

RASCo

st–CR

ASYear

1=L$5

3*L$16

/100

0+0.4*IF(L51

<1,0,L53

*L$3

2*(L$5

11)/100

0)+0.4*L50+L$9/10

00+L43*L$17

/100

0Accoun

tfor

costof

newrelays

(forthe

entireyear,allplanne

dgene

rators)

New

relays

*ne

wCR

ASrelaycosteach/100

0L$53

*L$1

6/10

00Ad

dinanyexcesstestroun

dcoststothene

wrelays

forthe

entireyear

+CR

ASredu

ctionfactor

*IF(durationfactor

<1,0,(new

relays

*pe

rrelay

base

case

testroun

dcost*(durationfactor

1))/10

00)+

CRAS

redu

ctionfactor

*excessfie

ldsupp

ortcosts

0.4*IF(L51

<1,0,L53

*L$3

2*(L$5

11)/100

0)+0.4*L50

AddintheITPSCcostsfor

aninitialde

signandtestingwith

fieldinvolvem

ent

+ITPSCcostsfor

initialde

signandtest

+L$9/10

00Ad

dinSCEcostform

aterialsprovided

andlabo

rpaidto

existinggene

ratorsto

transfer

tone

wRA

S(year1

only)

+existinggene

rators*CR

ASexistinggene

ratorcost/10

00+L$4

3*L$17

/100

0

Note:Thiseq

uatio

ncomes

from

NorthernArea

RAS,which,despite

beingabrandne

wRA

S,has som

eexistinggene

ratio

ncustom

ers

alreadyconn

ectedto

anothe

rRAS

.The

assumptionforC

RASisthat,due

tothestream

lined

testingandlower

crew

impacts,theRA

Swill

bebu

iltto

accommod

ateallexistingcustom

erstransferringas

wellasa

llexpe

cted

year

1ne

wcustom

ers.One

roun

dof

testingwillbe

done

tovalidatetheen

tireRA

S.39

CRAS

CostStud

yOverviewandRe

ference

48



New

RASCo

st–CR

ASYear

2On

=(M

53L53)*L$1

6/10

00+0.4*IF(M

51<1,0,(M

53L53)*M

$32*0.5*(M

511)/100

0)+0.4*0.5*M50

+0.4*IF(L51

<1,0,L53

*L$3

2*0.5*L$51

/100

0)+L$10

/100

0Accoun

tfor

costof

newrelays

(forthe


dne

wgene

rators)

New

relays

*ne

wCR

ASrelaycosteach/100

0(M

$53

L$53

)*L$16

/100

0Ad


dcoststothene

wrelays

forthe

entireyear

+CR

ASredu

ctionfactor

*IF(durationfactor

<1,0,(new

relays

*pe

rrelay

base

case

testroun

dcost*on

goingredu

ctionfactor

*(durationfactor

1))/10

00)+

CRAS

redu

ctionfactor

*on

goingredu

ctionfactor

*excessfie

ldsupp

ortcosts

+0.4*IF(L51

<1,0,((M53

L53)*L$3

2*0.5*(L$5

11))/10

00)+

0.4*0.5*L50

Addinanytestroun

dcoststoexistingrelays

forthe

entireyear

(singleroun

d)Note:Excess

fieldcostsa

lreadytallied

above

+CR

ASredu

ctionfactor

*(existingrelays

*pe

rrelay

base

case

testroun

dcost*on

goingredu

ctionfactor

*du

ratio

nfactor)

/100

0+0.4*IF(L51

<1,0,(L53

*L$3

2*0.5*L51)/100

0)Ad

dintheITPSCcostsfor

aninitialde

signandtestingwith

fieldinvolvem

ent

+ITPSCcostsfor

initialde

signandtest

+L$9/10

00

40CR

ASCo

stStud

yOverviewandRe

ference

49



ExistingStandAlon

eRA

SCo

st–Capacity

Upgrade

Year

1=(L67

K67)*L$3

4/10

00+IF(L71<1,0,(L67

K67)*L$3

2*(L71

1)/100

0)+L70+(L67

*(L$3

3+L$32

*L71))/10

00+(L64

*L67*L$32

*L71*

0.5)/100

0+L64*L70

Addne

wrelaycostinyear

1New

relays

*ne

wrelaycost/100

0(L67

K67)*L$3

4/10

00Ad

dexcesscoststofirstroun

dne

wrelays

ifany,over

thebase

case

testroun

dcostinclud

edwith

relay:

+(IF

(durationfactor

<1,0,ne

wrelays

*(per

relaybase

case

testroun


1))/10

00)+

excessfie

ldsupp

ortcosts

+IF(L71<1,0,(L67

K67)*L$3

2*(L71

1)/100

0)+L70

Addcoststodo

capacityup

gradeandtestingto

existingrelays, i.e.,thecoun

taso

fprio

ryear:

Existingrelays

*(capacity

upgradeparts+

perrelay

base

case

testroun

dcost*du

ratio

nfactor)

+(L67

*(L$3

3+L$32

*L71))/10

00Ad

dsubseq

uent

testroun

dsfora

llrelays

that

year

with

ongoingredu

ctionfactor,ifany.

+(new

gene

rators*nu

mbe

rofrelays*

perrelay

base

case

testroun

dcost*du

ratio

nfactor

*on

goingredu

ctionfactor)/10

00+gene

ratorcou

nt*excessfie

ldsupp

ortcosts

+(L64

*L67*L$32

*L71*0.5)/100

0+L64*L70

41CR

ASCo

stStud

yOverviewandRe

ference

50



ExistingStandAlon

eRA

SCo

st–Capacity

Upgrade

Year

2On

=(M

67L67)*M

$34/10

00+IF(M71

<1,0,(M

67L67)

*L$32

*(M

711)/100

0)+M

70+IF(M

67L67=0,0,(L67

*M$3

2*M71

*0.5)/100

0)+

IF(M

64<2,0,((M64

1)*M67

*L$32

*M71

*0.5)/100

0)+IF(M

64<2,0,M

64*M

70)

Addne

wrelaycostinyear

2New

relays

*ne

wrelaycost/100

0(M

67L67)*M

$34/10

00Ad

dexcesscosts tofirstroun

dne

wrelays

ifany,over

thebase

case

testroun

dcostinclud

edwith

relay:

+(IF

(durationfactor

<1,0,ne

wrelays

*(per

relaybase

case

testroun


1))/10

00)+

excessfie

ldsupp

ortcosts

+IF(M71

<1,0,(M

67L67)

*L$32

*(M

711)/100

0)+M

70Ad

dcoststodo

testingto

existingrelays,i.e.,therelaycoun

taso

fprio

ryearthatisinroun

d1of

testing:

Existingrelays

*pe

rrelay

base

case

testroun

dcost*du

ratio

nfactor

*on

goingredu

ctionfactor

+IF(M

67L67=0,0,(L67

*M$3

2*M71

*0.5)/100

0)Ad

dsubseq

uent

testroun

dsfora

llrelays

that

year

with

ongoingredu

ctionfactor,ifany.

+((n

ewgene

rators–1)

*totalnum

bero

frelays1*pe

rrelay

base

case

testroun

dcost*du

ratio

nfactor

*on

goingredu

ction

factor)/10

00+gene

ratorcou

nt*excessfie

ldsupp

ortcosts

+IF(M

64<2,0,M

64*M

70)

1.Simplifyingassumptionusingtotalnum

bero

frelays

42CR

ASCo

stStud

yOverviewandRe

ference

51



ExistingRA

SCo

nversio

nCo

st–CR

ASYear

1==L53

*L$1

6/10

00+0.4*IF(L51<1,0,L53*L$32

*(L511)/100

0)+0.4*L50+L$9/10

00+L43

*L$1

7/10

00

Accoun

tfor

costof

newrelays

(forthe


dgene

rators)

Allrelays*

newCR

ASrelaycosteach/100

0L53*L$16

/100

0Ad


dcoststothene

wrelays

forthe

entireyear

(one

roun

d,diffe

rent

metho

dology

forC

RAS)

+CR

ASredu

ctionfactor

*IF(durationfactor

<1,0,(allrelays

*pe

rrelay

base

case

testroun


1))/10

00)+

excessfie

ldsupp

ortcosts*CR

ASredu

ctionfactor

+0.4*IF(L51<1,0,(L53

*L$3

2*(L51

–1))/10

00)+

0.4*L50


aninitialde

signandtestingwith

fieldinvolvem

ent

+ITPSCcostsfor

initialde

signandtest

+L$9/10

00Ad

dinSCEcostform

aterialsprovided

andlabo

rpaidto

existinggene

ratorsto

transfer

tone

wRA

S(year1

only)

+existinggene

rators*CR

ASexistinggene

ratorcost/10

00+L43

*L$1

7/10

00

43CR

ASCo

stStud

yOverviewandRe

ference

52



ExistingRA

SCo

nversio

nCo

st–CR

ASYear

2=(M

73L73)*M

$16/10

00+0.4*IF(M71

<1,0,(M

73L73)*L$3

2*0.5*(L71

1)/100

0)+0.4*0.5*L70+0.4*IF(M71

<1,0,(M

73L73)

*L$32

*0.5*L71/10

00)+

L$10

/100

0Accoun

tfor

costof

newrelays

(forthe


dgene

rators)

New

relays

*ne

wCR

ASrelaycosteach/100

0(M

53L53)*M

$16/10

00Ad


dcoststone

wrelays

forthe

entireyear

(one

roun

d,diffe

rent

metho

dology

forC

RAS)

+CR

ASredu

ctionfactor

*IF(durationfactor

<1,0,(new

relays

*pe

rrelay

base

case

testroun

dcost*on

goingredu

ction

factor

*(durationfactor

1))/10

00)+

excessfie

ldsupp

ortcosts*on

goingredu

ctionfactor

*CR

ASredu

ctionfactor

+0.4*IF(M51

<1,0,(M

53L53)*L$3

2*0.5*(L51

1)/100

0)+0.4*0.5*L50

Addinanytestroun

dcostsfor

existingrelays

forthe

entireyear

(one

roun

d,diffe

rent

metho

dology

forC

RAS)

+CR

ASredu

ctionfactor

*IF(durationfactor

<1,0,(existingrelays

*pe

rrelay

base

case

testroun

dcost*on

g oingredu

ction

factor

*du

ratio

nfactor)/10

00)

Note:Excess

fieldsupp

ortcostsalreadytallied

above

+0.4*IF(M51

<1,0,(M

53L53)

*L$32

*0.5*L51/10

00)+


arede

signandtestingwith

fieldinvolvem

ent

+ITPSCcostsfor

rede

signandtest(smallera

mou

ntthan

year

one)

+L$10

/100

0

44CR

ASCo

stStud

yOverviewandRe

ference

53



Dur

atio

n Fa

ctor

(mod

ifies

dur

atio

n on

RA

S un

der c

onsi

dera

tion

vers

us b

ase

case

RA

S)•

Acc

ount

s fo

r diff

eren

ces

in th

e st

and-

alon

e R

AS

und

er c

onsi

dera

tion

vers

us th

e ba

se c

ase

stan

d-al

one

RA

S u

sed

to c

alcu

late

bas

ic re

lay

cost

s.•

Cal

cula

ted

by (C

urre

nt R

AS

test

pla

n #

of li

nes)

/ (B

ase

case

RA

S #

of t

est l

ines

)•

See

tabl

e ne

xt s

lide

for h

ow d

urat

ion

fact

ors

are

calc

ulat

ed.

Ong

oing

redu

ctio

n fa

ctor

(mod

ifies

full

stan

d-al

one

cost

per

rela

y pe

r rou

nd o

f tes

t) •

Red

uces

cos

t per

roun

d of

test

afte

r the

initi

al in

stal

latio

n to

refle

ct th

at th

e te

st p

lans

for a

RA

S g

ener

ally

get

so

mew

hat s

impl

er a

nd re

lay

coun

ts in

volv

ed w

ith te

sts

tend

to g

o do

wn,

unl

ess

addi

tiona

l con

tinge

ncie

s ar

e ad

ded.

Th

is is

a s

traig

ht n

umer

ical

ave

rage

adj

ustm

ent o

f 0.5

0.o

Ref

lect

s up

war

d pr

essu

re o

n co

mpl

exity

cau

sed

by p

erio

dic

addi

tions

of A

A-b

ank

trans

form

ers

•B

alan

ced

agai

nst r

educ

tion

in c

ompl

exity

bas

ed o

n re

duce

d nu

mbe

r of r

elay

s pe

r rou

nd fo

r add

ing

an

indi

vidu

al g

ener

a

CR

AS

redu

ctio

n fa

ctor

(con

vert

s st

and-

alon

e te

st c

ost t

o C

RA

S te

st c

ost)

•R

educ

es c

ost p

er ro

und

of C

RA

S te

st b

y th

e ob

serv

ed ra

tio o

f CR

AS

dur

atio

n ve

rsus

sta

nd-a

lone

dur

atio

n fo

r the

ba

se c

ase

RA

S. T

his

is a

stra

ight

num

eric

al a

vera

ge a

djus

tmen

t of 0

.40.

It is

con

serv

ativ

e (h

ighe

r dur

atio

n th

an

actu

ally

exp

ecte

d).

Mod

ifiers

45CR

ASCo

stStud

yOverviewandRe

ference

54



Howthesemod

ifiersa

reused

•Theadjustmentism

adeto

thebase

assumptioninvolvingallthe

relays

beingtested

atthefulltest

roun

dcostlevel=

Fullroun

dtestcostbase

case

RAS(allrelays

incurrentR

AS)*

duratio

nfactor

*on

goingredu

ctionfactor.

•Ingene

ral,thou

gh,w

efoun

dthat

recorded

costsw

iththestandalon

eRA

Ssforv

irtually

anytesting

fora

nychange

(overa

largesampleof

twoyearso

fsuchchanges)werestub

bornlyhigh.

Mod

ifiers

DURA

TIONFA

CTORCA

LCUL

ATIONS

Stan

dAlon

eRA

SLine

Coun

tDu

ratio

nFactor

Notes

ElSegund

o/ElNidoTestPlan

242

1.00

Thisisthebase

case

RAS

NorthernArea

1000

4.13

Testplan

length

estim

ated

byProtectio

nEngine

ering6/21/16

Colorado

River

790

3.26

Actualtestplan

length

MojaveDe

sert

427

1.76

Actualtestplan

length

Whirlw

ind

234

0.97

Actualtestplan

length

46CR

ASCo

stStud

yOverviewandRe

ference

55



Protectio

nEn

gine

eringNotes

ontestplan

complexity

over

time–ba

lancingfactors

Downw

ardfactor

oncomplexity

:“The

testproced

ures

form

odified

RASs

areactuallysim

pler

than

theoriginalinstallatio

ntest

proced

ures.W

henyouaddane

wgene

rator,it’se

ither

adde

dto

anexistingrelayor

it’sa

dded

toane

wrelay.Thearmingpo

intsforthe

newgene

ratorm

ight

beinon

eor

moreothe

rrelays.Youon

lyne

edto

testtherelays

that

have

been

changed,so

therearefewer

relays

totestwhe

nyouaddagene

rator

than

therewerewhe

nyoufirstpu

tthe

RASinservice.

Upw

ardfactor

oncomplexity

:“Som

emod

ificatio

nshave

amuchlarger

impacton

thetestproced

ure.Exam

ples:A

Abanksg

ettin

gadde

dat

Whirlw

ind,Co

lorado

Rover,Re

dBluffsub

sovertim

edu

eto

increasin

ggene

ratio

n.Thiscan

makethesubseq

uent

roun

dof

testMORE

complex

than

thefirstroun

d.

Net

results:

Basedon

adiscussio

nwith

Protectio

nEngine

ering6/28/2016:Re

commen

datio

nwas

touse0.50

asthe

standalon

eRA

Son

goingdu

ratio

nfactor.Thisfactorb

alanceso

utthetw

oeffectsa

bove.

Mod

ifiers–

Additio

nalN

otes

47CR

ASCo

stStud

yOverviewandRe

ference

56



CRAS Cost Study Worksheet

57



CRAS

CostStud

yWorkshe

et

ThisExcelw

orkshe

ethasthe

equatio

nsandactualcalculations

togetthe

estim

ated

costavoidancetotalsshow

nintheCR

ASGR

Ctestim

onysection.

SuggestedOrder

ofRe

view

It'sb

esttostartw

iththeassociated

workpa

percalled"CRA

SCo

stStud

yOverviewan

dRe

ference,"which

gives:

•High

levelintrodu

ctionon

busin

essd

rivers,alternatives

that

wereconsidered

,and

costdrivers.

•Explanationof

whatd

ifferen

cesb

etweenCR

ASandstandalon

eRA

Ssaremajor

diffe

rences

incostdrivers.

•An

alysisof

each

costdriver

andtheassociated

activ

ities/processes

that

drivelargediffe

rences

inrequ

iredlabo

rbetweenthetw

odiffe

rent

RAS

techno

logy

approaches

(CRA

Sversus

standalon

eRA

S).

•Ho

wtheeq

uatio

nsarebu

ilt,w

hatthe

varia

bles

are,andwhatm

odifiersh

avebe

enused

tobu

ildan

effectivecostmod

el.

•Themod

elistheou

tcom

eof

detailedworkbe

tweenSCE'sP

rotectionEngine

ering,System

Planning,SC&

MTest,Finance,and

Project

Managem

entd

epartm

ents.

•Themod

eluses

data

from

CRAS

projectp

hase

aswellasrecorde

ddata

from

standalon

eRA

Sim

plem

entatio

nsandchanges.Please

see"CRA

SCo

stStud

yOverviewandRe

ference"

form

oreinform

ation.

StartH

ere

CRAS

CostStud

yWorkshe

et.xlsx

58



RAS

RASType

#of

Relays

asStan

dAlon

eRA

S20

1820

30

#of

Relays

asCR

AS20

1820

30

Nom

inal

Savings1

PVRR

Savings1

2

NorthernArea

RASAv

oide

dTransm

ission

New

1444

1647

234,28

8$

210,35

7$

Colorado

RiverC

RAS/RG

OOSE

vs.Cap.U

pgrade

Conversio

n20

5822

5146

,599

$24

,325

$MojaveDe

sertCR

AS/RGO

OSE

vs.Cap.U

pgrade

Conversio

n28

4931

4610

,768

$4,56

7$

Whirlw

indCR

AS/RGO

OSE

vs.Cap.U

pgrade

Conversio

n10

25024

9$

(1,385

)$

291,66

4$

237,864

$1$inthou

sand

s220

16ba

seyear

PVRR

2,3

Bene

fits

237,864

$CR

AS/RGO

OSE

vs.Cap

Upgrad

e27

,507

$NorthernArea

RASAv

oidedTran

smission

210,35

7$

Costs

118,693

$CR

AS1

107,05

1$

RGOOSE

11,643

$B/C

2.00

1Inclu

desrecordedcostsfor

initialim

plem

entatio

nan

d2system

refreshes

2$inthou

sand

s320

16ba

seyear

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Total

PVRR

2,3

CRAS

/RGO

OSE

vs.Cap

Upgrade

2(2,618

)2,50

3(817

)3,01

54,03

84,22

24,94

05,30

75,93

96,34

77,41

98,35

88,72

357

,376

27,507

NorthernArea

RASAv

oide

dTransm

ission

22,34

32,34

32,34

321

,086

51,543

65,601

53,886

35,143

234,28

821

0,35

7To

talN

ominalBe

nefits

2,34

32,34

3(275

)23

,589

50,726

68,615

57,924

39,366

4,940

5,30

75,93

96,34

77,41

98,358

8,72

329

1,664

237,864

CRAS

1,2

342

9,47

615

,881

8,12

24,81

49,28

01,51

34,31

14,31

14,71

74,71

767

,483

107,05

1RG

OOSE

23,55

36,34

39,89

611

,643

TotalN

ominalCo

sts

342

9,476

15,881

8,12

24,814

9,280

5,066

6,34

34,31

14,31

14,71

74,71

777

,379

118,693

120

1020

16:recordedcostsfor

initialim

plem

entatio

n2$inthou

sand

s320

16ba

seyear

Notes

1.NorthernArea

CRAS

/RGO

OSE

vs.N

ewStandAlon

e43

.05

$

2.Aw

aitin

grecommen

datio

nfrom

attorneyso

nwhe

ther

existingRA

Sgene

ratorscanbe

madeto

payforstand

ards

basedup

grades.

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

TotalN

ominalCo

sts

342

9,476

15,88

8,122

4,814

9,280

5,066

6,343

4,311

4,311

4,717

4,717

TotalN

ominalBe

nefits

2,343

2,343

(275)

23,58

50,72

68,61

57,92

39,36

4,940

5,307

5,939

6,347

7,419

8,358

8,723

(10,000)

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

CRAS

TotalN

ominalCo

sts

TotalN

ominalBe

nefits

$inthou

sand

s

The

stan

d-al

one

is du

mbe

d do

wn

and

over

trips

gen

erat

ion

-w

e w

ould

not

act

ually

do

stan

d-al

one

if RG

OO

SE

not a

ppro

ved.

Pro

vided

just

as h

ypot

hetic

al c

ompa

rison

. Act

ual a

ltern

ative

to C

RAS

with

RG

OO

SE is

tran

smiss

ion

(see

"Tra

nsm

issio

n" ta

b of

CRA

S Co

st S

tudy

Wor

kshe

et).

Curr

ently

the

estim

ates

for C

RAS

assu

me

SCE

pays

for e

xistin

g cu

stom

er fa

cility

cha

nges

on

cust

omer

side

of t

he

fenc

e. H

owev

er, G

ener

atio

n Co

ntra

cts b

elie

ves

likel

y w

e ca

n m

ake

exist

ing

cust

omer

s pay

bas

ed o

n im

prov

ed c

ontra

ct

lang

uage

we

have

bee

n us

ing.

Thi

s w

ould

add

$10

M to

avo

ided

nom

inal

cos

t tot

al a

bove

.

GRCSummaries

CRAS

CostStud

yWorkshe

et.xlsx

59



Bene

fits

($inthou

sand

s)

AssetC

lass

Item

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Gran

dTo

tal

PVRR

2

Transm

ission

353

StationEquipm

ent

Colorado

RiverR

AS1

(158

)$

1,81

9$

2,02

5$

2,23

9$

3,14

4$

2,72

1$

3,87

4$

3,59

4$

4,68

4$

4,40

1$

5,36

7$

6,12

9$

6,75

9$

46,599

$24

,325

Transm

ission

353

StationEquipm

ent

MojaveDe

sertRA

S1

(2,460

)$

684

$49

6$

688

$73

0$

1,32

0$

866

$1,49

5$

1,01

7$

1,68

6$

1,18

2$

1,89

5$

1,16

8$

10,768

$4,56

7Transm

ission

353

StationEquipm

ent

Whirlw

indRA

S1

$$

(3,338

)$

87$

164

$18

1$

199

$21

8$

238

$25

9$

870

$33

4$

796

$9

$(1,385

)Transm

ission

354

Towers&

Fixtures

NorthernArea

Transm

issionLine

s3

2,34

32,34

32,34

321

,086

51,543

65,601

53,886

35,143

234,28

8$

210,35

7To

talB

enefits

2,34

3$

2,34

3$

(275

)$

23,589

$50

,726

$68

,615

$57

,924

$39

,366

$4,94

0$

5,30

7$

5,93

9$

6,34

7$

7,41

9$

8,35

8$

8,72

3$

291,664

$23

7,864

1SeeExpe

cted

Savingstab

2In20

16do

llars

3SeeTransm

issiontab

Costs

($inthou

sand

s)

AssetC

lass

Item

2010

120

111

2012

120

131

2014

120

151

2016

1,2

2017

220

182

2019

220

202

2021

220

222

2023

220

242

2025

2Gran

dTo

tal

PVRR

3

303

Software

CIT00

SDPM

0001

02CR

AS23

56,01

514

,057

4,64

23,99

96,71

51,36

54,31

14,31

14,71

74,71

755

,083

$81

,572

397

Telecom

Equipm

ent

CIT00

SDPM

0000

16CR

AS10

780

843

895

204

604

472,78

0$

5,51

1Transm

ission

353

StationEquipm

ent

CETOTOTBP

6428

00CR

AS3,38

198

12,58

561

11,96

110

19,62

0$

19,968

303

Software

RGOOSE

3,55

36,34

39,89

6$

11,643

$To

talCosts

342

$9,47

6$

15,881

$8,12

2$

4,814

$9,28

0$

5,06

6$

6,34

3$

4,31

1$

4,31

1$

$$

$$

4,71

7$

4,71

7$

77,379

$11

8,69

31CR

ASbasedon

recorded

2Ba

sedon

forecast

3In20

16do

llars

B/C

2.00

($ in

thou

sand

s)PV

RRBe

nefi

ts23

7,86

4$

CRAS

CostAv

oida

nce

27,507

NorthernArea

Tran

smissionAv

oida

nce

210,35

7Co

sts

118,

693

$

CR

AS C

osts

107,

051

$

RGO

OSE

Cos

ts11

,643

$

B/C

2.00

BCRa

tioCR

ASCo

stStud

yWorkshe

et.xlsx

60



RASType

CostFactor

Descrip

tion

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Stan

dAlon

eLong

Term

RelaySharing

AsRA

Sscontinue

togrow

andprolife

rate

inremew

ablesrichareas,overlaps

occur.CR

AScansharerelays,stand

alon

ene

edsa

ddition

alrelays.

00

00

00

02

22

22

22

22

Chan

gesp

erYe

arAssumed

changesp

eryear

inrene

wablesrichareas

00

00

33

22

22

22

22

22

CRAS

AnalyticTestingcostsp

erchan

geinCR

AS(IT

Testingcost)Thisisanalytictestingcostfore

very

completeCR

ASde

sign.By

PSC,verifieso

utto

andinclud

ingtripof

relay.

100,80

0$

103,82

4$

106,93

9$

110,14

7$

113,45

1$

116,85

5$

120,36

0$

123,97

1$

127,69

0$

131,52

1$

135,46

7$

139,53

1$

143,71

7$

148,02

8$

152,46

9$

157,04

3$

CRAS

Additio

nalA

nalytic

Testing

Form

odificatio

nsto

existingCR

ASde

sign

64,800

$66

,744

$68

,746

$70

,809

$72

,933

$75

,121

$77

,375

$79

,696

$82

,087

$84

,549

$87

,086

$89

,698

$92

,389

$95

,161

$98

,016

$10

0,95

6$

CRAS

CRAS

OverallTesting

SC&M

testtech

supp

ortcost

$7,86

8$

8,10

4$

8,34

7$

8,59

7$

8,85

5$

9,12

1$

9,39

4$

9,67

6$

9,96

6$

10,265

$10

,573

$10

,891

$11

,217

$CR

ASCR

ASOverallTesting

Man

hours/ite

ratio

n0

9696

9696

9696

9696

9696

9696

96CR

AS#Men

/FieldCrew

Headcoun

t2

22

22

22

22

22

22

22

2CR

ASCR

ASFieldTestingDu

ratio

nHo

urs

1616

1616

1616

1616

1616

1616

1616

1616

CRAS

CRAS

TripTestDu

ratio

nHo

urs

88

88

88

88

88

88

88

88

CRAS

CRAS

RelayTo

talCost

Installnew

relayandgetitind

ividually

ready.Includ

eslabo

rand

material.No

endto

endtesting.

120,71

5$

124,33

7$

128,06

7$

131,90

9$

135,86

6$

139,94

2$

144,14

1$

148,46

5$

152,91

9$

157,50

6$

162,23

2$

167,09

8$

172,11

1$

177,27

5$

182,59

3$

188,07

1$

CRAS

CRAS

Existin

gGe

neratorC

ost

Costinyear

oneto

payform

odificatio

nsto

existingIntercon

nectionFacilities

SCEpays

185,26

3$

190,82

1$

196,54

6$

202,44

2$

208,51

5$

214,77

1$

221,21

4$

227,85

0$

234,68

6$

241,72

6$

248,97

8$

256,44

7$

264,14

1$

272,06

5$

280,22

7$

288,63

4$

CRAS

CRAS

RelayRa

tioRa

tiowith

StandAlon

eRe

lays

is1.1:1

(i.e.10

%more)

becauseof

somede

sign

diffs

TestTech

Rate

Rate

perh

our

7577

8082

8487

9092

9598

101

104

107

110

113

117

All

TripTestIte

ratio

nsTriptests/year

(one

percustomer

OD)

04

32

22

22

22

22

22

All

TripTestCo

stOne

2man

crew

persub

perg

enerator

3,93

4$

4,05

2$

4,17

3$

4,29

9$

4,42

8$

4,56

0$

4,69

7$

4,83

8$

4,98

3$

5,13

3$

5,28

7$

5,44

5$

5,60

9$

Stan

dAlon

eStan

dalon

eTesting

Num

bero

fend

toen

dfie

ldcrew

testite

ratio

ns0

43

22

22

22

22

22

2Stan

dAlon

eStan

dalon

eTesting

Num

bertesttechs

requ

ired

04

56

67

88

99

1010

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Stan

dAlon

eStan

dalon

eTesting

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45

55

56

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dalon

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048

048

064

064

064

080

080

080

080

096

096

0Stan

dAlon

eStan

dalon

eTesting

Costpe

riteratio

n$

26,225

$40

,518

$41

,734

$42

,986

$59

,034

$60

,805

$62

,629

$80

,635

$83

,054

$85

,546

$88

,112

$10

8,90

6$

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Stan

dAlon

eTestingcostsp

erchan

gein

stan

dalone

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Thisisadditio

naltestin

gcostfore

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change

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derstand

alon

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npe

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basis.N

ote:Allrelaysm

ustb

eretested

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$21

,218

$21

,855

$22

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$23

,185

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,881

$24

,597

$25

,335

$26

,095

$26

,878

$27

,685

$28

,515

$29

,371

$30

,252

$31

,159

$

Stan

dAlon

eRe

laymod

ulecostsfor

stan

dalone

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uleand1Po

wer

Supp

lymod

ule(existRA

Srelayup

grade)

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8,24

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7$

8,74

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9,00

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9,27

4$

9,55

2$

9,83

9$

10,134

$10

,438

$10

,751

$11

,074

$11

,406

$11

,748

$12

,101

$12

,464

$

Stan

dAlon

eStan

dAlon

eRe

layTo

talCost

Installnew

relay,standalone

RAS.Escalatedvaluebasedon

2009

2010

recorded

costs.Includ

eslabo

rand

material.

200,57

0$

206,58

7$

212,78

5$

219,16

8$

225,74

3$

232,51

6$

239,49

1$

246,67

6$

254,07

6$

261,69

8$

269,54

9$

277,63

6$

285,96

5$

294,54

4$

303,38

0$

312,48

2$

New

RAS

NorthernArea

CRAS

/RGO

OSE

vs.N

ewStan

dAlon

e20

1520

1620

1720

1820

1920

2020

2120

2220

2320

2420

2520

2620

2720

2820

2920

30

Num

berS

CEsubstatio

nsassumed

00

03

33

33

33

33

33

33

Num

bero

fexistinggene

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2022

2426

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3234

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Num

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fgen

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00

04

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22

22

22

22

22

Stan

dalon

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lays

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014

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2426

2830

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4042

Relaysharingde

ficit

00

00

00

00

20

20

20

22

Stan

dalon

etotalrelaysb

yyear

00

814

2022

2426

3030

3434

3838

4244

Stan

dalon

eexcess

fieldsupp

ortcostsby

subcoun

t0

00

00

00

00

00

00

Stan

dalon

eexcess

fieldsupp

ortcostsby

relaycoun

t0

00

00

00

11

11

22

Excess

fieldsupp

ort

00

00

00

017

1718

1837

39Du

ratio

nfactor

versus

referenceRA

S4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

4.13

OptionA

New

stan

dalon

eRA

Scosts

5,94

1$

4,84

9$

3,42

6$

3,02

1$

3,33

6$

4,33

1$

3,56

8$

5,10

2$

4,30

8$

5,93

3$

5,10

6$

6,86

4$

6,82

1$

62,607

$CR

ASSCErelays

byyear

00

016

2225

2729

3133

3638

4042

4447

OptionB

CRAS

with

RGOOSE

Costs

4,88

5$

1,23

6$

933

$86

4$

929

$99

8$

1,06

9$

1,32

2$

1,24

9$

1,33

2$

1,41

9$

1,51

4$

1,81

2$

19,562

$Nom

inalCo

stDe

ltaCR

ASCo

stAv

oida

nce

1,05

6$

3,61

4$

2,49

3$

2,15

7$

2,40

7$

3,33

4$

2,49

9$

3,78

0$

3,05

9$

4,60

1$

3,68

6$

5,35

0$

5,01

0$

43,046

$

Conversion

RAS

Colorado

RiverC

RAS/RG

OOSE

vs.C

ap.U

pgrade

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Num

berS

CEsubstatio

nsassumed

00

33

33

33

33

33

33

33

Num

bero

fexistinggene

rators

00

04

68

1012

1416

1820

2224

2628

Num

bero

fgen

eratorsa

dded

pery

ear

00

02

22

22

22

22

22

22

Stan

dalon

eSCERe

lays

byyear

00

1620

2426

2830

3234

3638

4042

4446

Relaysharingde

ficit

00

00

00

02

02

02

02

22

Stan

dalon

etotalrelaysb

yyear

00

1620

2426

2832

3438

4044

4650

5458

Stan

dalon

eexcess

fieldsupp

ortcostsby

subcoun

t0

00

00

00

00

00

00

Stan

dalon

eexcess

fieldsupp

ortcostsby

relaycoun

t0

00

00

11

12

23

34

Excess

fieldsupp

ort

00

00

012

1313

2728

4344

61

Duratio

nfactor

versus

referenceRA

S3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

3.26

OptionA

Capa

city

upgrad

estan

dalon

eRA

Scosts

4,09

9$

2,68

9$

2,42

8$

2,65

4$

3,57

1$

3,34

1$

4,33

0$

4,06

3$

5,16

8$

4,90

2$

6,09

1$

6,66

3$

7,30

9$

57,307

$

CRAS

SCErelays

byyear

00

022

2729

3133

3638

4042

4447

4951

OptionB

CRAS

with

RGOOSE

Costs

4,25

7$

871

$40

3$

415

$42

7$

620

$45

6$

469

$48

3$

500

$72

4$

534

$55

0$

10,708

$

Nom

inalCo

stDe

ltaCR

ASCo

stAv

oida

nce

(158

)$

1,81

9$

2,02

5$

2,23

9$

3,14

4$

2,72

1$

3,87

4$

3,59

4$

4,68

4$

4,40

1$

5,36

7$

6,12

9$

6,75

9$

46,599

$

IMPO

RTAN

T:NorthernArea

RASinto

CRAS

willworkandgive

desired

76armingpo

ints.A

standalon

eRA

Scanon

lyaccommod

atethat

manyarmingpo

intsby

tripping

twogene

ratorsat

once.Please

refertoCR

AStestim

onyandworkpape

ronNorthernArea

RASandtheun

desirabiltyof

trying

touseastandalon

eRA

Sapproach.SCE

wou

ldspecify

ane

wtransm

issionbu

ildinsteadof

astandalon

eRA

SifCR

ASwith

RGOOSE

wereno

tavailable.

Standalon

ecostsp

rovide

dforh

ypothe

ticalcostcomparison

purposes

only.

Expe

cted

Savings

CRAS

CostStud

yWorkshe

et.xlsx

61



Conversion

RAS

MojaveDe

sertCR

AS/RGO

OSE

vs.C

ap.U

pgrade

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Num

berS

CEsubstatio

nsassumed

00

66

66

66

66

66

66

66

Num

bero

fexistinggene

rators

00

02

34

56

78

910

1112

1314

Num

bero

fgen

eratorsa

dded

pery

ear

00

01

11

11

11

11

11

11

Stan

dalon

eSCERe

lays

byyear

00

2628

3031

3233

3435

3637

3839

4041

Relaysharingde

ficit

00

00

00

00

20

20

20

20

Stan

dalon

etotalrelaysb

yyear

00

2628

3031

3233

3637

4041

4445

4849

Stan

dalon

eexcess

fieldsupp

ortcostsby

subcoun

t2

22

22

22

22

22

22

Stan

dalon

eexcess

fieldsupp

ort costsby

relaycoun

t0

00

01

11

12

22

23

Excess

fieldsupp

ort

1212

1213

1313

1414

1515

1616

25Du

ratio

nfactor

versus

referenceRA

S1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

1.76

OptionA

Capa

city

upgrad

estan

dalon

eRA

Scosts

2,35

5$

1,05

1$

874

$92

1$

970

$1,56

7$

1,12

1$

1,75

7$

1,28

7$

1,96

5$

1,46

9$

2,19

1$

1,67

6$

19,207

$CR

ASSCErelays

byyear

00

031

3335

3637

3839

4041

4243

4446

OptionB

CRAS

with

RGOOSE

Costs

4,81

5$

367

$37

8$

233

$24

0$

248

$25

5$

263

$27

1$

279

$28

7$

296

$50

8$

8,43

8$

Nom

inalCo

stDe

ltaCR

ASCo

stAv

oida

nce

(2,460

)$

684

$49

6$

688

$73

0$

1,32

0$

866

$1,49

5$

1,01

7$

1,68

6$

1,18

2$

1,89

5$

1,16

8$

10,768

$

Conversion

RAS

Whirlw

indCR

AS/RGO

OSE

vs.C

ap.U

pgrade

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

Num

berS

CEsubstatio

nsassumed

00

01

11

11

11

11

11

11

Num

bero

fexistinggene

rators

00

00

012

1314

1516

1718

1920

2122

Num

bero

fgen

eratorsa

dded

pery

ear

00

00

01

11

11

11

11

11

Stan

dalon

eSCERe

lays

byyear

00

08

1012

1314

1516

1718

1920

21Re

laysharingde

ficit

00

00

00

00

00

00

20

22

Stan

dalon

etotalrelaysb

yyear

00

08

810

1213

1415

1617

1821

2225

Stan

dalon

eexcess

fieldsupp

ortcostsby

subcoun

t0

00

00

00

00

00

00

Stan

dalon

eexcess

fieldsupp

ortcostsby

relaycoun

t0

00

00

00

00

00

00

Excess

fieldsupp

ort

00

00

00

00

00

00

Duratio

nfactor

versus

referenceRA

S0

0.97

0.97

0.97

0.97

0.97

0.97

0.97

0.97

0.97

0.97

0.97

OptionA

Capa

city

upgrad

estan

dalon

eRA

Scosts

895

$59

5$

390

$41

4$

439

$46

5$

492

$52

1$

1,14

0$

611

$1,27

0$

7,23

3$

CRAS

SCErelays

byyear

00

00

011

1415

1617

1819

2021

2224

OptionB

CRAS

with

RGOOSE

Costs

4,23

3$

508

$22

6$

233

$24

0$

247

$25

4$

262

$27

0$

278

$47

4$

7,22

3$

Nom

inalCo

stDe

ltaCR

ASCo

stAv

oida

nce

(3,338

)$

87$

164

$18

1$

199

$21

8$

238

$25

9$

870

$33

4$

796

$9

$

Expe

cted

Savings

CRAS

CostStud

yWorkshe

et.xlsx

62



This page intentionally leftblank.

63



Nor

ther

n A

rea

RA

S A

void

ed T

rans

mis

sion

Cos

tEl

emen

tQ

uant

ity$/

ea$

sub

Line

term

inat

ion

2.00

11,2

10,0

00$

22

,420

,000

$

Mile

s of

500

kV

tran

smis

sion

line

36.4

54,

578,

000

$

16

6,86

8,10

0$

18

9,28

8,10

0$

1. N

ote:

Thi

s is

a h

igh-

leve

l est

imat

e/eq

uipm

ent o

nly

45,0

00,0

00$

2. C

onse

rvat

ive

figur

e. A

ctua

l lic

ensi

ng c

osts

like

ly

234,

288,

100

$

hig

her.

Uni

t Cos

t Ref

eren

ce In

form

atio

nS

CE

’s 2

016

Fina

l Per

Uni

t Cos

t Gui

de is

pos

ted

at th

is li

nk:

http://w

ww.caiso.com

/Docum

ents/SCE

2016

FinalPerUnitCostGuide

.xlsx

Tota

l not

incl

udin

g lic

ensi

ng c

osts

Hig

h le

vel l

icen

sing

cos

t est

imat

eO

vera

ll To

tal

Met

hodo

logy

Ene

rgy

from

rene

wab

le g

ener

atio

n re

sour

ces

in S

CE

’s N

orth

ern

area

is c

urre

ntly

del

iver

ed s

outh

to th

e LA

Bas

in b

y w

ay o

f a th

ree-

line

500

kV tr

ansm

issi

on c

orrid

or li

nkin

g W

indh

ub, W

hirlw

ind,

Ant

elop

e, a

nd V

ince

nt s

ubst

atio

ns. W

ith

all t

hree

line

s in

ser

vice

, the

max

imum

out

put o

f all

inte

rcon

nect

ed g

ener

atio

n ca

n be

relia

bly

deliv

ered

. Whe

n un

plan

ned

outa

ges

of o

ne o

r mor

e of

thes

e lin

es o

ccur

, the

max

imum

gen

erat

ion

outp

ut e

xcee

ds th

e ca

paci

ty o

f the

re

mai

ning

line

s. In

ord

er to

elim

inat

e da

mag

e to

tran

smis

sion

equ

ipm

ent f

rom

ove

rload

s, a

Rem

edia

l Act

ion

Sch

eme

(RA

S) i

s th

e m

ost c

ost e

ffect

ive

way

to b

ring

gene

ratio

n ou

tput

and

ava

ilabl

e tra

nsm

issi

on c

apac

ity in

to b

alan

ce. A

R

AS

wor

ks b

y au

tom

atic

ally

cal

cula

ting

the

amou

nt o

f gen

erat

ion

that

nee

ds to

be

take

n of

f-lin

e in

ord

er fo

r tot

al o

utpu

t no

t to

exce

ed a

vaila

ble

trans

mis

sion

cap

acity

, mon

itorin

g fo

r unp

lann

ed li

ne o

utag

es, a

nd th

en a

utom

atic

ally

sen

ding

si

gnal

s to

the

gene

rato

rs to

dis

conn

ect t

hem

from

the

grid

the

inst

ant t

he o

utag

e oc

curs

.

With

out a

RA

S, a

dditi

onal

tran

smis

sion

line

cap

acity

bet

wee

n S

CE

’s W

hirlw

ind

and

Vin

cent

sub

stat

ions

will

be

need

ed

to a

ccom

mod

ate

the

high

vol

ume

of re

new

able

gen

erat

ion

outp

ut fr

om p

roje

cts

inte

rcon

nect

ing

in S

CE

’s N

orth

ern

area

. B

y in

stal

ling

a V

ince

nt –

Whi

rlwin

d N

o. 2

500

kV

line

, N-1

and

N-2

con

tinge

ncy

outa

ges

(i.e.

unp

lann

ed tr

ansm

issi

on

line

faul

ts in

volv

ing

any

one

line

or c

ombi

natio

ns tw

o lin

es a

t a ti

me)

will

leav

e en

ough

line

s in

ser

vice

to d

eliv

er th

e m

axim

um g

ener

atio

n ou

tput

with

out o

verlo

ads

that

wou

ld d

amag

e tra

nsm

issi

on e

quip

men

t. Th

e ba

sic

com

pone

nts

of

this

tran

smis

sion

line

are

the

cond

ucto

r and

sup

porti

ng to

wer

s th

at c

ompr

ise

the

line

itsel

f, an

d th

e te

rmin

atin

g eq

uipm

ent t

hat c

onne

ct th

e lin

e to

the

subs

tatio

n sw

itchr

acks

. Ter

min

atin

g eq

uipm

ent i

nclu

des

circ

uit b

reak

ers

(two

at

each

term

inat

ion)

, dis

conn

ect s

witc

hes

(four

at e

ach

term

inat

ion)

, and

oth

er e

quip

men

t, al

l of w

hich

is c

olle

ctiv

ely

refe

rred

to a

s a

“line

term

inat

ing

posi

tion.

For

a s

ingl

e tra

nsm

issi

on li

ne, o

ne li

ne te

rmin

atin

g po

sitio

n is

requ

ired

at

each

of t

he tw

o en

ds o

f the

line

.”

1.NorthernArea

Transm

ission

CRAS

CostStud

yWorkshe

et.xlsx

64



Year

1Ye

ar2

Year

3Ye

ar4

Year

5Ye

ar6

Year

7

2016

2017

2018

2019

2020

2021

2022

1.00

%1.00

%1.00

%9.00

%22

.00%

28.00%

23.00%

2,34

2,88

1$

2,34

2,88

1$

2,34

2,88

1$

21,085

,929

$51

,543

,382

$65

,600

,668

$53

,886

,263

$Note:An

nualallocatio

nprovided

byT&

DMPO

andWorkManagem

ent

$

$10,000,000

$20,000,000

$30,000,000

$40,000,000

$50,000,000

$60,000,000

$70,000,000

2016

2017

2018

2019

2020

2021

2022

2023

RoughTran

smission

Costsb

yYear

1.NorthernArea

Transm

ission

CRAS

CostStud

yWorkshe

et.xlsx

65



PerA

ndyFree

Tue5/24

/201

67:33

PM

InitialDe

ploymen

tofR

AS:

Desig

nandDe

velopm

ent

Unittestin

gIntegrationTesting

PointtoPo

intT

estin

g3FTE1mon

th0.5FTE1mon

th1FTE1mon

th0.5FTE1mon

th(3*160

*75=$3

6,00

0)(0.5*160

*75=$6

,000

)(1*160

*75=$1

2,00

0)(0.5*160

*75=$6

,000

)

Increm

entalCha

nges

toRA

S(totheRA

Sthat

was

develope

dbe

fore):

Desig

nandDe

velopm

ent

Unittestin

gIntegrationTesting

PointtoPo

intT

estin

g2FTE1mon

th0.0FTE1mon

th0.5FTE1mon

th0.5FTE1mon

th(2*160

*75=$2

4,00

0)(0.0*160

*75=$0

,000

)(0.5*160

*75=$6

,000

)(0.5*160

*75=$6

,000

)

PSC

PSC

2.CR

ASAn

alyticTestingCo

sts

CRAS

CostStud

yWorkshe

et.xlsx

66



Endto

EndTesting

D400

sand

RTU

Total

Contingency

Totalw

ithCo

ntingency

1FTE1mon

th1FTE1mon

th10

0,80

0$

(1*160

*75=$1

2,00

0)(1*160

*75=$1

2,00

0)

Endto

EndTesting

D400

sand

RTU

Total

Contingency

Totalw

ithCo

ntingency

1FTE1mon

th0.5FTE1mon

th64

,800

$(1*160

*75=$1

2,00

0)(0.5*160

*75=$6

,000

)

$84,00

020

%

$54,00

020

%

2.CR

ASAn

alyticTestingCo

sts

CRAS

CostStud

yWorkshe

et.xlsx

67



SeeCR

ASCo

stStud

yOverviewandRe

ferenceform

oreinform

ation

Gene

ratorS

iteCo

stsfor

ExistingGe

nerators

Gen

erationProject

RAS

#CB

sType

Scop

eCo

stGen

esisI

Colorado

River

2Standard

One

rack

with2relays

150,000

$Gen

esisII

Colorado

River

2Standard

One

rack

with2relays

150,000

$BlackCree

kCo

lorado

River

4Standard

One

rack

with2relays

150,000

$Dracker

Colorado

River

4Standard

One

rack

with2relays

150,000

$Alba

MojaveDesert

1Standard

One

rack

with2relays

150,000

$Ocaso

MojaveDesert

1Standard

One

rack

with2relays

150,000

$LSP220kV

lineatKram

erMojaveDesert

2Standard

One

rack

with2relays

150,000

$Avenu

eA

Whirlwind

3Standard

One

rack

with2relays

150,000

$Avenu

eB

Whirlwind

2Standard

One

rack

with2relays

150,000

$Kingbird

Whirlwind

2Standard

One

rack

with2relays

150,000

$Free

bird

Whirlwind

4Standard

One

rack

with2relays

150,000

$SolarR

anch

AWhirlwind

1Standard

One

rack

with2relays

150,000

$SolarR

anch

Whirlwind

1Standard

One

rack

with2relays

150,000

$

Soleil:

Whirlwind

3Standard

1CB

atplant1,2

CBsatplant2

(sep

araterelays

atthetw

oplants,

butthe

ybo

thtripatthesametime)

150,000

$

Astoria:

Whirlwind

7Special

4CB

satplant1,3

CBsatplant2

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araterelays

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oplants,

butthe

ybo

thtripatthesametime)

Sameapproach

asatTe

ddy

)see

belowand"Ted

dy"tab).

290,000

$

Garland

:Whirlwind

6Special

1CB

atplantA

,5CB

satplantB

/C(sep

araterelays

atthetw

oplants,but

they

both

tripatthesametime).

290,000

$Ro

yWhirlwind

4Standard

One

rack

with2relays

150,000

$Tedd

yph

ases

1and2

Whirlwind

4Standard

One

rack

with2relays

150,000

$

Tedd

yWhirlwind

9Special

Multipleph

ases

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71



Northern Area Arming Points Comparison

72



ArmNo.

CAISO QUEUE# Project No. CLUSTER

MainTransformer MW

ArmingPoints

Max MWsArmed

Point ofInterconnection

Q643AJ TOT494 Q3 T1 100 WhirlwindQ768 TOT585 Q4 T2 20 AntelopeTBD TOT815 Q9 T1 305 WhirlwindQ746 TOT573 Q4 T1 100 WhirlwindQ768 TOT585 Q4 T3 20 AntelopeTBD TOT819 Q9 T1 300 WindhubQ768 TOT585 Q4 T6 20 AntelopeQ967 TOT668 Q6 T1 60 WhirlwindQ971 TOT672 Q6 T2 100 WhirlwindTBD TOT807 Q9 T1 240 WindhubQ768 TOT585 Q4 T1 60 AntelopeQ971 TOT672 Q6 T1 100 Whirlwind

Q1214 TOT769 Q8 T1 6 WhirlwindTBD TOT821 Q9 T1 24 WhirlwindTBD TOT807 Q9 T2 230 WindhubQ506 TOT411 Q1 T3 86 WhirlwindQ602 TOT455 Q2 T1 110 WhirlwindTBD TOT807 Q9 T3 230 Windhub

Q1215 TOT777 Q8 T1 150 WhirlwindTBD TOT828 Q9 T1 150 WindhubTBD TOT824 Q9 T1 92 WhirlwindQ602 TOT455 Q2 T2 20 WhirlwindQ506 TOT411 Q1 T4 86 WhirlwindQ795 TOT544 Q4 T1 20 Whirlwind

Q1208 TOT762 Q8 T2 225 AntelopeTBD TOT824 Q9 T2 92 WhirlwindQ768 TOT585 Q4 T4 85 Antelope

Q1208 TOT762 Q8 T3 225 AntelopeTBD TOT795 Q9 T1 24 WhirlwindTBD TOT824 Q9 T3 92 WhirlwindQ506 TOT411 Q1 T5 19.6 Whirlwind

Q1208 TOT762 Q8 T1 200 AntelopeTBD TOT826 Q9 T1 200 WhirlwindQ796 TOT545 Q4 T1 20 Whirlwind

Q1209 TOT763 Q8 T1 105 AntelopeTBD TOT791 Q9 T1 200 Highwind

Q1209 TOT763 Q8 T2 105 AntelopeQ643R TOT497 Q3 T1 78 WhirlwindQ746 TOT573 Q4 T2 75 WhirlwindQ768 TOT585 Q4 T7 20 Antelope

Q1074 TOT727 Q7 T1 75 WhirlwindTBD TOT828 Q9 T2 150 WindhubQ768 TOT585 Q4 T9 30 AntelopeQ506 TOT411 Q1 T1 54 WhirlwindQ602 TOT455 Q2 T3 20 Whirlwind

Q643R TOT497 Q3 T2 75 WhirlwindQ768 TOT585 Q4 T5 55 Antelope

Q1076 TOT726 Q7 T1 50 WhirlwindQ1074 TOT727 Q7 T2 50 WhirlwindQ1209 TOT763 Q8 T3 105 AntelopeQ506 TOT411 Q1 T2 54 Whirlwind

Q1211 TOT753 Q8 T1 100 WhirlwindQ1212 TOT754 Q8 T1 100 WhirlwindTBD TOT793 Q9 T1 125 WhirlwindTBD TOT806 Q9 T4 56 WhirlwindQ768 TOT585 Q4 T8 20 Whirlwind

Q1217 TOT778 Q8 T1 100 WhirlwindQ1209 TOT763 Q8 T4 105 AntelopeTBD TOT791 Q9 T2 200 HighwindTBD TOT790 Q9 T2 125 WhirlwindTBD TOT793 Q9 T2 125 WhirlwindTBD TOT823 Q9 T1 110 WhirlwindTBD TOT790 Q9 T1 125 Whirlwind

Arming Points 45Min Arming Size 409Max Arming Size 485Mean 426.5981503Average 426.9066667

15

Table 1RAS Arming Utilzinig Traditional RAS

(15 Total Groups Requiring 45 Arming Points)

9 3 419.6

10

3 426

7 3 423

6 3

425

3

3 4204

3 3 420

426

412

5

14 3 425

3 485

13 3 435

3 40912

3 430

3 42811

8 3

2 420

1 3

Northern Area RAS Arming Points Comparison

73



ArmNo.

CAISO QUEUE# Project No. CLUSTER

MainTransformer MW

ArmingPoints

Max MWsArmed

Point ofInterconnection

1 T1 54 3 542 T2 54 3 543 T3 86 3 864 T4 86 3 865 T5 19.6 3 19.66 T1 110 3 1107 T2 20 3 208 T3 20 3 209 Q643AJ TOT494 Q3 T1 100 3 100 Whirlwind10 T1 78 3 7811 T2 75 3 7512 Q795 TOT544 Q4 T1 20 3 20 Whirlwind13 Q796 TOT545 Q4 T1 20 3 20 Whirlwind14 T1 100 3 10015 T2 75 3 7516 Q967 TOT668 Q6 T1 60 3 60 Whirlwind17 T1 100 3 10018 T2 100 3 10019 Q1076 TOT726 Q7 T1 50 3 50 Whirlwind20 T1 75 3 7521 T2 50 3 5022 Q1211 TOT753 Q8 T1 100 3 100 Whirlwind23 Q1212 TOT754 Q8 T1 100 3 100 Whirlwind24 Q1214 TOT769 Q8 T1 6 3 6 Whirlwind25 Q1215 TOT777 Q8 T1 150 3 150 Whirlwind26 Q1217 TOT778 Q8 T1 100 3 100 Whirlwind27 T1 125 3 12528 T2 125 3 12529 T1 125 3 12530 T2 125 3 12531 TBD TOT795 Q9 T1 24 3 24 Whirlwind32 TBD TOT806 Q9 T4 56 3 56 Whirlwind33 TBD TOT815 Q9 T1 305 3 305 Whirlwind34 TBD TOT821 Q9 T1 24 3 24 Whirlwind35 TBD TOT823 Q9 T1 110 3 110 Whirlwind36 T1 92 3 9237 T2 92 3 9238 T3 92 3 9239 TBD TOT826 Q9 T1 200 3 200 Whirlwind40 T1 60 3 6041 T2 20 3 2042 T3 20 3 2043 T4 85 3 8544 T5 55 3 5545 T6 20 3 2046 T7 20 3 2047 T8 20 3 2048 T9 30 3 3049 T1 200 3 20050 T2 225 3 22551 T3 225 3 22552 T1 105 3 10553 T2 105 3 10554 T3 105 3 10555 T4 105 3 10556 T1 200 3 20057 T2 200 3 20058 T1 240 3 24059 T2 230 3 23060 T3 230 3 23061 TBD TOT819 Q9 T1 300 3 300 Windhub62 T1 150 3 15063 T2 150 3 150

Arming Points 189Min Arming Size 6Max Arming Size 305Mean 75.16473132Average 101.6444444

Table 2RAS Arming Utilzinig C RAS

(63 Arming Elements Requiring 189 Arming Points)

Q1

Q2

Q3

Q746

Q971

Q1074

TOT411

TOT455

TOT497

TOT573

TOT672

TOT727

Q506

Q602

Q643R

Whirlwind

Whirlwind

Whirlwind

Whirlwind

Whirlwind

Whirlwind

Whirlwind

Whirlwind

Whirlwind

TOT585

Q9

TOT790

TOT793

TOT824

Antelope

Q1208 TOT762

Q4

Q8 Antelope

Q768

Antelope

Q9TOT791TBD Highwind

Windhub

TBD TOT828 Q9 Windhub

Q6

Q7

Q9

Q9

TBD TOT807 Q9

Q1209 TOT763 Q8

TBD

TBD

TBD

Q4

Northern Area RAS Arming Points Comparison

74



Evolution of RAS Complexity - Base Data

75



N60

InNo.of

Relay

Per

Subscribed

Publish

edLogic

Service

RASNam

eSubstatio

nRe

lays

Type

RelayFunctio

nRe

lay

Total

Bits

Bits

Line

sYear

Commen

tsBishop

RAS

Control

2RX

IL20

Line

Mon

itor

22

1980

sNon

redu

ndantlegacyRA

S1

RFL67

45Transfer

Tripto

Plants3and4

1RFL67

45Transfer

Tripto

Plant2

1RFL67

45Transfer

Tripto

Plants5and6

Blythe

Energy

RAS

JulianHind

s2

GEN60

JulianHind

sMira

geOverlo

ad1

21

557

2010

Armed

atalltim

es2

GEN60

MWDBu

sSectio

nOverlo

ad1

73

101

Colorado

RiverC

orrid

orRA

SRe

dBluff

2GE

N60

Line

Mon

itorin

g/LogicProcessin

g8

1611

1941

320

152

GEN60

Line

Mon

itorin

g/LogicProcessin

g8

1420

406

2GE

N60

Bank

Mon

itorin

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g0

3511

433

2GE

N60

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Mon

itorin

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g0

2123

432

Colorado

River

2GE

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Line

Mon

itorin

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GEN60

Bank

Mon

itorin

g2

GEN60

Bank

Mon

itorin

gDe

vers

2GE

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Line

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itorin

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320

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403

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327

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Tripping/LogicProcessin

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Allavailablesubscribed

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g6

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10Re

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2GE

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4107

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4111

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Load

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g2

25

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gHD

PPRA

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g16

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1ArmingCo

ntrol

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SEL35

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ntrol

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SEL21

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g/ArmingCo

ntrol

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Line

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itorin

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SEL35

1Ba

nkMon

itorin

gInland

Empire

RAS

Valley

2GE

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Line

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itorin

g/LogicProcessin

g2

23

324

520

14Serrano

2GE

N60

Line

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itorin

gIvanpahArea

RAS

Eldo

rado

2GE

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Line

Mon

itorin

g/LogicProcessin

g5

510

1838

120

132

GEN60

Bank

Mon

itorin

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g18

615

02

G EN60

Bank

Mon

itorin

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g11

987

Ivanpah

2GE

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Line

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itorin

g4

GEN60

Bank

Mon

itorin

g

RelayTo

RelayDa

taArmingPo

ints

Evolutionof

RASCo

mplexity

Base

Data

H.Ha

m,5/19/16

Evolutionof

RASCo

mplexity

Base

Data.xlsx

1

76



N60

InNo.of

Relay

Per

Subscribed

Publish

edLogic

Service

RASNam

eSubstatio

nRe

lays

Type

RelayFunctio

nRe

lay

Total

Bits

Bits

Line

sYear

Commen

ts

RelayTo

RelayDa

taArmingPo

ints

Evolutionof

RASCo

mplexity

Base

Data

H.Ha

m,5/19/16

2GE

N60

Tripping

Prim

m2

GEN60

Line

Mon

itorin

gKram

erRA

SKram

er1

RXIL20

Line

Mon

itorin

g1

1980

sNon

redu

ndantlegacyRA

SMidway

Vincen

tRAS

Vincen

t2

SEL21

00LogicProcessin

g/ArmingCo

ntrol

1010

2002

2GE

N60

Line

Mon

itorin

g2

SEL351

Line

Mon

itorInterface

2SEL20

30EM

S/ArmingInterface

Whirlw

ind

2GE

N60

Line

Mon

itorin

gLa

Cien

ega

2SEL35

1Load

Tripping

Laguna

Bell

2SEL35

1Load

Tripping

Lighthipe

2SEL35

1Load

Tripping

Mesa

2SEL35

1Load

Tripping

Mira

Loma

2SEL35

1Load

Tripping

RioHo

ndo

2SEL35

1Load

Tripping

Valley

2SEL35

1Load

Tripping

Walnu

t2

SEL35

1Load

Tripping

Mira

LomaLVLS

RAS

Mira

Loma

1RFL67

45Transfer

Tripto

Padu

a19

96Non

redu

ndantlegacyRA

S1

RFL67

45Transfer

Tripto

Villa

Park

1RFL67

45Transfer

Tripto

Walnu

t2

RFL97

45Lugo

Rancho

Vistalinestatus

Rancho

Vista

2RFL97

45Lugo

Rancho

Vistalinestatus

Padu

a1

RFL67

45Load

Tripping

Villa

Park

1RFL67

45Load

Tripping

Walnu

t1

RFL67

45Load

Tripping

MojaveDe

sertRA

SKram

er2

GEN60

Line

Mon

itorin

g/LogicProcessin

g1

2944

1332

920

142

GEN60

Line

Mon

itorin

g/LogicProcessin

g12

1116

410

2GE

N60

Line

Mon

itorin

g/LogicProcessin

g12

1117

320

2GE

N60


g4

816

260

CoolWater

2GE

N60

Line

Mon

itorin

g2

GEN60

Gene

ratorT

ripping

Lugo

4GE

N60

Bank

Mon

itorin

g2

GEN60

Line

Mon

itorin

gSand

lot

2GE

N60

Line

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itorin

gRo

adway

4GE

N60

Line

Mon

itorin

gVictor

2GE

N60

Line

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itorin

gMou

ntainView

RAS

SanBe

rnardino

2SEL21

00LogicProcessor/ArmingCo

ntrol

33

2003

8SEL351

Line

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itorin

g4

SEL35

1Overlo

ad/Trip

ping

2SEL20

30EM

S/ArmingInterface

Devers

4SEL351

Line

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itorin

gElCasco

4SEL351

Line

Mon

itorin

gEtiwanda

2SEL351

Line

Mon

itorin

gVista

2SEL351

Line

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itorin

gPEFRA

SPastoria

2SEL21


ntrol

1427

2005

2SEL21


ntrol

134

GEF35

Line

Mon

itorin

g2

SEL20

30EM

S/ArmingInterface

Antelope

4SEL351

Line

Mon

itorin

gMagun

den

2SEL351

Line

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itorin

g

Evolutionof

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mplexity

Base

Data.xlsx

2

77



N60

InNo.of

Relay

Per

Subscribed

Publish

edLogic

Service

RASNam

eSubstatio

nRe

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Type

RelayFunctio

nRe

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Total

Bits

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Line

sYear

Commen

ts

RelayTo

RelayDa

taArmingPo

ints

Evolutionof

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mplexity

Base

Data

H.Ha

m,5/19/16

Bailey

2SEL351

Line

Mon

itorin

gPardee

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itorin

gSanJoaquinVa

lleyRA

SRe

ctor

2GE

N60

Line

Mon

itorin

g/LogicProcessin

g9

4114

2245

420

082

GEN60

Line

Mon

itorin

g/LogicProcessin

g11

1622

473

2GE

N60

LogicProcessin

g10

2411

463

2GE

N60

Line

Mon

itorin

g/LogicProcessin

g11

1426

505

Near5

11lin

elim

it2

GEN60

LogicProcessin

g0

383

132

BigCreek1

2GE

N60

Line

Mon

itorin

gBigCreek3

4GE

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Line

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itorin

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d2

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Gene

ratorR

unback

andTripping

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andTripping

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den

4GE

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Line

Mon

itorin

gSprin

gville

4GE

N60

Line

Mon

itorin

gVe

stal

4GE

N60

Line

Mon

itorin

gLibe

rty

2GE

N60

Load

Tripping

Southof

Lugo

RAS

Mira

Loma

2SEL21

00LogicProcessin

g3

320

052

GEF35

Line

Mon

itorin

g2

SEL35

1Load

Tripping

1SEL20

30EM

S/ArmingInterface

Lugo

2GE

F35

Line

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itorin

g2

SEL351

Line

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itorInterface

Rancho

Vista

2GE

F35

Line

Mon

itor

2SEL351

Line

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itorInterface

Chino

2SEL35

1Load

Tripping

Padu

a2

SEL35

1Load

Tripping

Whirlw

indAA

Bank

RAS

Whirlw

ind

2GE

N60

Bank

Mon

itorin

g/LogicProcessin

g10

1010

2046

820

142

GEN60

Bank

Mon

itorin

g/LogicProcessin

g28

930

02

GEN60

Bank

Mon

itorin

g/LogicProcessin

g4

597

2GE

N60

Bank

Mon

itorin

g/LogicProcessin

g3

555

NorthernArea

500kVRA

SWhirlw

ind

2GE

N60

Line

Mon

itorin

g/LogicProcessin

g?

88?

??

Exceed

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itof

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ints

18GE

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g?

??

?An

telope

4GE

N60

Line

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itorin

g2

GEN60

Gene

ratorT

ripping

Vincen

t2

GEN60

Line

Mon

itorin

g2

GEN60

Gene

ratorT

ripping

Notes:

GEN60

logiclim

itedto

511lines

ofcode

perrelay.

GEN60

limite

dto

12armingpo

intspe

rrelay.

GEN60

limite

dto

64subscribed

and64

publish

edrelayto

relaydata

bits(viaGO

OSE)p

errelay.

Evolutionof

RASCo

mplexity

Base

Data.xlsx

3

78



Arming Points (Current and Future)

79



RAS Current Future TotalKramer 1 0 1Bishop 2 0 2Blythe Ene 2 0 2Inland Emp 2 0 2Mountainv 3 0 3South of Lu 3 0 3Ivanpah Ar 5 0 5Midway Vi 10 0 10High Deser 16 0 16Pastoria En 27 0 27Big Creek/S 41 0 41Whirlwind 10 38 48Devers 48 0 48Colorado R 16 50 66Mojave De 29 39 68Northern A 36 88 124

1 2 2 2 3 3 5 10 1627

41

10

48

1629

36

0 0 0 0 0 0 00

0

0

0

38

050

39

88

0

20

40

60

80

100

120

140

Arming Points (Current & Future)

Current Future

80



RASs Nearing or Exceeding Capacity Limits

81



RASs Nearing or Exceeding Capacity Limits (Backup for Diagram V-4)

Summary and Recommendations:

TSSA recommends moving forward with work necessary to complete the Colorado River CRAS conversion by Q4 2017, the Mohave Desert CRAS conversion by Q2 2018, the Northern Area CRAS by Q4 2018, and the Whirlwind AA-Bank RAS conversion by Q2 2020. These three CRAS implementations will be required accommodate interconnections whose participation is beyond the technical capability of traditional, "stand-alone" RAS technology. Logic processing in conventional, relay-based RAS schemes is limited to approximately 50 arming points. The numbers of generation projects applying for interconnection in those areas are such that the stand-alone RAS arming point limitation would be exceeded if high-resolution arming/tripping schemes were to be implemented. The work-around for overly complex stand-alone systems is to aggregate blocks of generation output such that they can be tripped en masse. While this allows RAS schemes to function within the capabilities of relay-based logic processing, it risks over-tripping of generation, which translates to interconnection customers as unnecessary curtailment and lost revenue, making their business models less robust. Negative pressure on renewable interconnection customers could potentially lead to withdrawals, which translates to electric utilities as lost opportunities for both capital investment and progress toward aggressive, mandatory Renewable Portfolio Standards.

Given that Gov. Brown has recently signed legislation requiring a 50% renewable energy portfolio by 2030, we can expect the number of potential interconnections to increase above the already high number currently in queue. Transmission projects in flight such as the West of Devers Transmission Project will add substantial capacity to the grid, alleviating a potential hurdle to future interconnections. Considering these factors, it is not unreasonable to expect the current pace of interconnections to not only continue, but potentially to accelerate, creating a situation that is unsustainable under the existing, stand-alone RAS paradigm.

Below are some details on the CRAS deployment projects we propose for the upcoming few years.

Scope Elements and Justification:

Colorado River Corridor RAS Conversion to CRAS The Colorado River Corridor RAS has 42 arming points allocated for projects that either are currently in service, are currently in construction, or are active in the Interconnection Queue and expected to move forward. These projects have expected Operating Dates occurring between now and December 1, 2017. Additionally, there are more projects interconnecting at Colorado River and Red Bluff Substations with executed or pending GIAs that have expected Operating Dates in the Q1 2018 to Q4 2020 time-frame. The traditional Colorado River RAS has 8 arming points available for future use, which have

82



been reserved by projects already considered in the design of the RAS. The first two of these, set to come on-line in Q1 and Q3 of 2018, respectively, would require a total of ten arming points, at which point the stand-alone RAS arming point limitation would be exceeded. Looking ahead a bit, the latest Queue Cluster contains no less than seven additional projects seeking interconnection at Colorado River and Red Bluff Substations, with some seeking interconnect by Q3 and Q4 of 2018. Finally, as generation projects along the corridor continue to connect, additional tripping may ultimately be required to mitigate potential future N-1 contingency overloads on the Devers - Valley No. 1 and No. 2 500 kV Lines.

Mojave Desert RAS Conversion to CRAS The Mojave Desert RAS, in its current form, has a total of 29 arming points allocated to existing generation in the area. Several QC8 generation projects in the area are seeking interconnection with Operating Dates beginning in April 2018. These projects would need to participate in the Mojave Desert RAS. The output of these generators also exceeds transmission line and transformer capacity under both normal conditions (making necessary the installation of a third 500/220 kV "AA" transformer bank at Lugo Substation) and contingency outage conditions (requiring the addition of several new N-1 and N-2 contingencies not previously included in the RAS analytic). These factors greatly increase the complexity of the Mojave River RAS. When QC8 generation is considered, the RAS would require 68 arming points, which is well beyond the technical limitations of relay-based logic processing.

One factor that could affect the recommendation for converting the Mojave Desert RAS to CRAS is the status of Coolwater Generating Station. The owner of the station has officially ceased generation activity at the site, but is granted by the applicable tariff a period of three years in which they may elect to repower the facility (this period began in January, 2015). During this period, Coolwater retains the deliverability it was allocated by CAISO. Coolwater also continues to pay for and retain its transmission access rights pursuant to the Radial Lines Agreement (RLA). As long as the agreement is in force, SCE must preserve the interconnection facilities, including the allocation of RAS arming points to Coolwater. The owner may elect to sell the project, in which case the allocated deliverability and transmission access rights retained under the RLA would transfer to the new owner. With the new Renewable Portfolio Standard (RPS) increasing the state of California’s targeted renewable generation capacity to 50% by 2030, the potential profitability of the site to new developers who could purchase the project has improved, thereby increasing the likelihood that the site would be sold and that the arming points allocated to Coolwater will be unavailable for use by new interconnection customers.

Assuming Coolwater’s owner uses the entirety of the three-year period do decide to repower, there would still be some time required for the necessary study and interconnection agreement processes to take place. In the meantime, the arming points used by Coolwater may not be allocated to new interconnections. An amendment or termination of Coolwater’s RLA would be required in order for SCE to justify going in and pulling relays, etc. Should that come to pass, or should additional detail surface that

83



would provide clarity as to the future of Coolwater, the conversion of the Mojave Desert RAS to CRAS would be less time-sensitive.

Northern Area SPS Implementation in CRAS The Northern Area RAS is conceptual in nature, and is needed to accommodate generation projects seeking interconnection in the North of Vincent area of the SCE system. The Northern Area RAS mitigates transmission line contingency overloads by monitoring for four N-2 contingencies and tripping generation at Antelope, Whirlwind, and Windhub Substations. Considering all active interconnection requests in the area, a total of 23 projects would be required to participate in this RAS. These projects cover a span of time from the Serial Interconnection process forward to QC8, and have Operating Dates from mid-2015 to late-2018. A total of 12 of these projects have either filed or executed GIAs or are in execution, and are expected to come on-line in 2015 and 2016. Considering only these latter 12 projects, 47 arming points within the RAS would be allocated. With all active Northern Area generation interconnection requests considered, the technical limitations of a traditional RAS would be exceeded in late 2018.

Whirlwind AA-Bank RAS Conversion to CRAS The Whirlwind AA-Bank RAS trips existing generation projects interconnected at the 230 kV bus of the Whirlwind 500/230 kV substation. The 230 kV bus is connected to the 500 kV bus by way of two 500/230 kV transformers, called “AA-banks.” When one of the two AA-banks experiences a contingency outage, the remaining AA-bank will exceed its rated capacity unless generation is tripped. Currently, there are 12 projects interconnected that are required to participate in the RAS. Each of these projects is assigned an arming point for the loss of either transformer, for a total of 12 arming points. A third AA-bank is scheduled to be in service by early 2017. With three AA-banks in service, the loss of any one of the three will not cause the remaining two banks to be overloaded. However, with two banks out, the remaining bank will exceed its rated capacity. Therefore, when the third AA-bank goes into service, all projects will be assigned another arming point for the simultaneous loss of any two AA-banks. This will double the number of assigned arming points to 24. Additional queued generation projects will be required to assume two additional arming points. By July 2020, the number of participating generators will require a total number of arming points that exceeds stand-alone RAS logic processing, making the conversion of the Whirlwind AA-Bank RAS necessary by Q2 2020.

Methodology Used for Developing Timeline in “Business Driver – RASs Nearing Capacity Limits” (Diagram V-4)

SCE’s Generation Interconnection Planning group maintains a database of all generation projects seeking interconnection to the SCE grid via CAISO’s established interconnection process. This database consists of the project-specific information contained in CAISO’s Interconnection Queue (which is available for download as an Excel spreadsheet at http://www.caiso.com/planning/Pages/GeneratorInterconnection/Default.aspx), as well as additional data fields useful for SCE’s study and contract management processes. The database is periodically filtered by the CRAS sponsoring organization (Transmission

84



Special Assessments) into subsets of active projects that are seeking interconnection to parts of the grid (called points of interconnection or POIs) where a known congestion issue exists and for which a RAS has been identified to mitigate transmission equipment overloads due to outage contingencies. Projects that have withdrawn from the queue or that do not show acceptable progress in moving forward through the interconnect study, posting, and execution process are disregarded from further consideration. Active projects are then sorted by their proposed commercial operating dates. Each project is assigned arming points in the RAS according to their chosen POI (for example, a project interconnecting to the 230 kV bus of a 500/230 kV substation that is connected to known congested 500 kV transmission lines would be assigned arming points for both 500/230 kV transformer bank outages and 500 kV transmission line outages, while a project interconnecting to the 500 kV bus of the same substation would be assigned arming points for transmission line outages only). A cumulative total of assigned arming points is calculated according to each project’s queue position. The point in time at which the cumulative total of arming points exceeds the capability of existing RAS logic processing is the point at which a conversion of the RAS to CRAS (which has virtually unlimited arming point capacity and logic processing capability) is required. Thus, the more complicated a RAS becomes over time (i.e., the more generation projects are required to participate and the more contingencies the RAS mitigates), the sooner a conversion to CRAS is required. The required conversion dates for the first four RAS to reach this capacity limit are shown in the table “Business Driver – RASs Nearing Capacity Limits.”

85



Northern Area RAS Arming Points - Base Data

86



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NOTES:

Each

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ASde

ploymen

t

87



Stand-Alone RAS Capacity Increase Factors

88



Stand-Alone Relay Capacity Increase Factors

There are three basic components needed in a GE N60 relay that give it capacity for arming points:

1. “FlexLogic” lines available in memory.

2. Communications channels (limited in version 7.4 relay firmware to 64 bits).

3. “Virtual outputs,” variables used to store intermediate logic results in FlexLogic.

Based on the increases in memory and communications channels in relay firmware version 7.4, as limited by available virtual outputs, Protection Engineering calculates an approximate 31% increase in arming points is feasible.

This increased arming points threshold means we could technically do stand-stand alone RASs longer and delay CRAS, but this is not the recommended technical option:

1. Does not provide the long term architectural and scalability advantages of CRAS.

2. Does not provide the arming point capacity of CRAS and its precise mitigation action, which has potential electric customer impacts over time (unnecessary load sheds) and generation customers (unnecessary overtripping of generation).

Source: Based on notes provided by SCE Protection Engineering.

89



Cumulative Completion Percentage of Transmission

Interconnection Queue Projects

90



CumulativeCo

mpletionPe

rcen

tage

ofTran

smission

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nectionQue

ueProjects,200

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Cumulative

Percen

tage

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Cumulative

Completions

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2006

21

50%

21

2007

00

50%

21

2008

20

25%

41

2009

30

14%

71

2010

23

44%

94

2011

41

38%

135

2012

53

44%

188

2013

88

62%

2616

2014

55

68%

3121

2015

15

81%

3226

2016

94

73%

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Metho

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UsedforD

evelop

ing“Cum

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mpletionPe

rcen

tage

ofTran

smission

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nectionQue

ueProjects,2006–2016”

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ystem

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aintains

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wnloadableExcelspreadshe

etat

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ithprop

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rcen

tage

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ral trend

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issionprojectscanbe

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ffectiveandtim

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theelectricgrid.

91



RGOOSE Project

92



0

1,000

2,000

3,000

4,000

5,000

6,000

7,000



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2017


Year4,500

5,900

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

10,400


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

RGOOSE Conversion

See Testimony.

See Testimony.

RGOOSE Project

93



(1 of 8)

SOUTHERN CALIFORNIA EDISON

RGOOSE Project

94



I. Business Initiative DescriptionA. Initiative Name

RGOOSE Project Communications Protocol Upgrades to CRAS Central Controllers and Network Gear

B. Initiative Description

The purpose of this project to upgrade the CRAS network and its network components to support the RGOOSEportion of the IEC 61850 90 5 standard, which will convert it into a routable network, providing increasedcommunications efficiency and greater visibility into the network.

RGOOSE is the latest communications standard required to mitigate increasing RAS complexity on SCE’stransmission grid. RGOOSE (Routable GOOSE) changes the existing substation communications protocol(GOOSE, Generic Object Oriented Substation Events, a broadcast protocol) to a routable format that isaddressable (i.e., can be sent to specific devices or groups of devices) and compatible with SCE’s existing WideArea Network (WAN).

Timeline and Scope High Level Diagram

Diagram NotesRAS Complexity and Capacity relate to “arming points”

o The increasing RAS complexity that SCE described in its 2015 filing is being experienced, withfour RASs required in 2018 2019 that have a high complexity level. That complexity iscomposed of a higher number of generators, substations, and lines to protect – and therefore

95



more contingency conditions to evaluate and take action on. The best measure of RAS capacityand complexity combines these factors in what are called “arming points:” Arming points arethe specific thresholds where a RAS will arm for a particular generator as it evaluates a specificcontingency (problematic system condition) related to that generator.

Arming Points create additional data volume on the networko Each arming point drives continuous messaging traffic on the network about the conditions

affecting that arming point, such as electric current flow or the status of a transmission line.This data volume requires the certainty of message delivery as well as the rapid diagnostics ofcommunication failure. We can obtain these capabilities by deploying RGOOSE on the CRASnetwork for future RAS deployments.

CRASCRAS is an automated grid control system which responds to grid events that move more swiftly thandispatchers and operators can react to.

CRAS’ primary use is as a Remedial Action Scheme (RAS).RASs protect transmission assets when third party generators hook up to our transmission grid. If notfor a RAS, the only option would be to build very expensive long term transmission each time there isan interconnection request.

CRAS is driven by the growing CISO monitored Generation Interconnection Queue, which comprises large (20megawatt and greater) generation projects that want to hook up to SCE’s transmission grid. Many of theseprojects are renewables like wind and solar which are driven by state mandates. A growing Interconnectionqueue made it an imperative to start CRAS in 2011 mainly due to the growing size of the queue. Besides thesheer volume of interconnections, the trend over the past ten years shows that the RAS complexity hasincreased significantly. When future growth is considered, the upcoming RASs we focus on in testimony(Northern Area, Colorado River, Mojave Desert, and Whirlwind) are too complex to deploy in the stand aloneRAS configuration, which has hard limits on arming point capacity.

The Need for RGOOSEThe initial implementation of CRAS, which heavily relies upon very high speed communications, had to proceedwith the implementation on the available communications protocol, GOOSE. GOOSE was designed for broadcastcommunication only within the substation, where all devices are broadcasting and all other devices hear all themessages whether they need to or not. GOOSE protocol was extended for the CRAS implementation on a widearea network (WAN) while the industry developed the RGOOSE standard.

The industry has now developed the standard for RGOOSE. The standards process was the pacing item on use ofRGOOSE, in that the standard had to be solidified enough to be commercially and technically feasible toimplement. The RGOOSE protocol offers significant improvements in the networking performance and securityover the WAN.

Communications performance and uptime is critical to RAS function – WECC requires very high communicationsavailability and dual redundant communications paths. GOOSE is inherently less able to handle high datavolumes than RGOOSE from a network perspective and this leads to several significant issues:

1. Communications outage risk increases – meaning the RAS does not function. If this occurs, it meansdirect customer impacts from lower transmission line utilization, generator trips, and load sheds.

2. Chances of degraded or inaccurate performance increase, increasing chances of outages or unnecessarygeneration trips or load sheds.

96



3. Time to restore can go up dramatically because GOOSE communications is inherently much moredifficult to troubleshoot, which could lengthen grid outages.

4. GOOSE communication is not “hot swappable” on failure – hardware failures can cause reducedvisibility and performance for grid operations.

These risks all potentially lead to a lack of timely action on the grid to mitigate events. Deploying CRAS toupcoming very complex RASs using GOOSE further increases these risks with each deployment.

ScopeUpgrade network gear and central controller software to “RGOOSE” in preparation for upcoming RASdeployments. It is important to note that the upcoming RASs are much more complex than previously deployedRAS’s. They need the RGOOSE network improvements.

The CRAS RGOOSE Conversion will upgrade the capability of the network and its components to supportthe new standard protocol. Implementing the new standard provides improvements to networking andsecurityThere are three basic parts of the CRAS system that are affected by RGOOSE:

o Relays – GE will deliver RGOOSE compatible relayso Network and CRAS central controllers.o Cybersecurity requirements – the project will implement authentication, encryption and other

security measures required to protect this grid critical application.

Since the commercial firmware for the relays will be available in mid 2016, the RGOOSE project willcomplete the first phase of RGOOSE conversion by completing the network and central controllerchanges, and then test end to end functionality and backwards compatibility.

Time criticality with implementing RGOOSEIncreasing RAS complexity in the field makes stand alone RASs either a) provide substandard protection totransmission assets or b) not possible to implement.

RAS complexity is increasing much faster than it was at CRAS project launch or the time of the last GRCfiling. See Arming Points (Current and Future) and Queue Completion charts below.The risks SCE’s System Planning, Protection Engineering, and Telecom Network Services see with GOOSEover WAN networking echo the industry concerns that prompted creation of the RGOOSE standard.The risks of communications outages tend to be HILP (High Impact Low Probability). A key considerationfor whether the project should move forward is the risk of delaying implementation of the newstandard which mitigates the HILP risks.

97



98



Not in Scope

A Test Environment for SAT 1 is already separately funded, so is not in this request.The Colorado River RAS deployment already has approved infrastructure funding and is in the T&Dcapital plan and the Integrated Work Plan.Security key management (GDOI) Centralized security key distribution and related functionality oncethe IEC 61850 90 5 is ratified

C. Business Strategic Alignment

This project will update the CRAS configuration to enable its wider roll out throughout SCE’s territory. The CRASsystem is essential for better compliance with state generation interconnection requirements and RenewablePortfolio Standards, which were recently further modified and signed into law to require 50% renewables by2030.

Company Initiatives and Goals that RGOOSE SupportsOpX Initiative – Reliability

o Operations Productivity CRAS implementations will reduce operating risks on the transmissiongrid by reducing the amount of generation tripped and/or firm load shed. Each CRASdeployment will deliver avoided cost compared to stand alone RAS deployments due to savingson both equipment and labor.

T&D 2015 Goals Alignmento Achieve Reliability Targets – RGOOSE will provide greater stability and reliability to the CRAS

application, which is a critical protection application required to maintain reliability of thetransmission grid. Specifically, RGOOSE reduces the risk of occurrence of communicationsoutages, or the risk of degraded performance, enables faster troubleshooting after a failureminimizing any grid impact and makes the solution more fault tolerant and resilient.

o Bulk System Reliability and Security – In addition to making monitor and control on CRAS morereliable, RGOOSE will secure communications over the WAN to ensure that unauthorizedmessages are detected and blocked.

D. Anticipated Business Outcomes & Benefits

Re usable Architecture: RGOOSE opens the door to many potential additional applications of CRASstyle architecture on the grid, whether transmission or distribution – anywhere high speed, ultra highreliability automated control is needed. CRAS is considered a model for this kind of centralizedcontrol, and was designed from the beginning as a true grid controller.Enable CRAS Deployment: This project will deliver the product changes required to enable thedeployment of CRAS to the Colorado River RAS (per T&D System Planning’s RAS deployment plan) inthe RGOOSE configuration. The Colorado River RAS deployment already has approved infrastructurefunding and is in the T&D capital plan and the Integrated Work Plan.Reduced Operating Risks: Implementation of RGOOSE will enable deeper and faster penetration ofCRAS deployment. CRAS implementations will reduce operating risks on the transmission grid byreducing the amount of generation tripped and/or firm load shed.Reduced Operating Costs:

99



o Adding new schemes under CRAS will also be less expensive (less relays and less field laborneeded) than stand alone RASs. On average, this computes to a cost avoidance of $900,000per RAS.

o In addition to these equipment savings, CRAS’ relay standardization means that relay testcreation, test execution, and the level of test tech required in the field are all significantlyreduced than for a stand alone RAS, where hundreds of man hours were spent to create andhundreds to thousands of crew man hours in the field to actually test.

o In addition, RGOOSE has O&M savings over time because of its standardized network andrelay testing approach.

Benefits applicable to RAS deployment now apply to CRAS:Given the clear direction of T&D Protection Engineering and System Planning that standalone RAS technology is outmoded and no longer meets the challenges of an increasinglycomplex grid, CRAS is the only technology left that is workable in the long term aside frombuilding new transmission. CRAS, therefore, has the benefits of a RAS approach going forwardand is paid for by cost avoidance of just 20 miles of transmission line.CRAS then saves cost going forward (over time) as new RASs get added to CRAS instead ofbeing added as stand alone RASs.With respect to existing RASs, the majority do not need conversion at this time. Only certainexisting RASs meet the criteria for conversion to CRAS: Complex RASs in high renewablesgrowth areas. Because change costs (such as for generator or transformer bank additions) areso much higher for stand alone RASs (see CRAS cost study work papers), it is possible for astand alone RAS with remaining capacity to still be cost beneficial to bring into CRAS.Regarding cost recovery, RGOOSE is a key enabler of CRAS to deploy further, so SCE’s positionis that CRAS cost avoidances should be used to gain remaining cost recovery for CRAS projectand RGOOSE project.

100



E. Business Impact Assessment

Minimal impact on business, should be transparent to core clients/users.Reduced cycle time of preparing & provisioning new RASs will allow business to accelerate rate ofdeployment to substationsEliminates limitations and risks of one off custom stand alone RAS solutionsEliminates limitations and risks of current CRAS network design with its cumbersome manual configurationand scalability and performance risks – the very risks and concerns the RGOOSE standard was intended toresolve.T&D’s SC&M impacts should be minimal in that CRAS system will already be NERC CIP v5 compliant at thetime of this proposed upgrade and relays will already be considered NERC CIP assets.

F. Technology/Automation Rationale

Upgrade CRAS network and its network components to support the RGOOSE IEC 61850 90 5 standard,which will convert it into a routable network, providing increased efficiency and greater visibility into thenetwork.Enhance CRAS component interfaces to support the protocol change at the back end to make the solutionmore efficient by reducing hops and reducing points of failures, and improving the scalability of thearchitecture.

G. Proposed Options

Alternative 1:Do not implement the RGOOSE protocol and do not deploy CRAS further due to the risks of using GOOSEprotocol with significantly more complicated RASs. Instead, implement stand alone relay capacity increaseson 3 of the 4 RASs (Colorado River, Mojave Desert, and Whirlwind) and a new transmission build forNorthern Area, the remaining RAS that is too complex for a stand alone RAS architecture. This combinedalternative is not recommended, as described above in the CRAS testimony. For 3 of the 4 RASs, thisalternative does not provide a long term solution to capacity issues, and is not cost efficient. For NorthernArea RAS, the only other alternative besides CRAS with RGOOSE is building out very expensive and redundanttransmission.

Alternative 2:Do not do RGOOSE Project and, instead, deploy CRAS with existing GOOSE network approach. Thisalternative is not recommended, as complex data volumes make it technically difficult and cumbersome todetermine where a failure occurs without the use of a routable protocol. Though it was necessary to have awide area network approach in order to properly develop and test the CRAS platform, GOOSE is less stablethan RGOOSE, and its non standard usage on the wide area network would be imprudent, given that a betterstandardized approach is now available. SCE has seen a large increase in RAS and required arming pointcomplexity. This increased complexity drives higher data volume requirements and the need for the stronger,more stable, and more precise RGOOSE communications network protocol.

101



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102



GOOSE Data Volume Study

103



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104



GOOSE

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Energy Management System (EMS) Refresh

107



01,0002,0003,0004,0005,0006,0007,0008,000



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2018


Year6,210

7,220

2,670

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

16,100


2016 2017 2018 2019 2020




SOUTHERN CALIFORNIA EDISON COMPANYCAPITAL WORKPAPERS - CAPITALIZED SOFTWARE

PROJECT DETAIL WORKSHEET: SOFTWARE UPGRADES


SCE-04, Vol. 02IT

Capitalized SoftwareCapitalized SoftwareSoftware Upgrades790

2016

2017

2018

2019

2020

Total

EMS Refresh

See Testimony.

See Testimony.

EMS Refresh

108



INVESTMENT MEMO

(0 of 5)


EMS Refresh

109



(1 of 5)


Energy Management System (EMS) Refresh


The project is being proposed to perform and support a planned refresh of the EnergyManagement System(EMS) and consolidate the Phasor System. Both Phasor and EMS are Commercial Off The Shelf (COTS)product developed and maintained by General Electric (GE).

The Energy Management System (EMS) is operated by the Grid Control Center (GCC). The GCC monitorsand controls the bulk power system 24/7, using SCE’s EMS and a video wall which graphically depicts thestatus of SCE’s and neighboring utilities’ bulk power systems. GCC personnel use EMS to monitoroperating parameters such as voltage, frequency, power flow, and equipment status. The day to dayoperation of the sub transmission and distribution system is carried out by 14 switching centersgeographically dispersed around the SCE system.

This project will refresh the aging hardware and software components of the EMS system in order tomaintain system availability. In addition to a technical refresh of the EMS hardware and software, thisproject will consolidate the EMS and Phasor systems. The Phasor system collects, stores, and sharesPhasor Measurement Units (PMU) data. Consolidating EMS and Phasor onto a single platform will reducehardware and software costs and simplify the maintenance of both systems. It will also provide a unifiedoperator view, eliminating the need for two separate but related systems.

The primary driver for the EMS Refresh Project is to refresh the aging EMS system, whose current versionwill no longer be supported by the vendor after 2017. The risk of hardware failures continues to rise asthe system ages. By the time of the refresh, the hardware will be 7 years old. Refreshing EMS will allowSCE to maintain system reliability at 99.95% or greater and reduce the risk posed by components reachingend of useful life. System reliability of EMS is important to SCE Grid Operations because EMS systemfailures could result in a direct impact to safety, customer service, operations, and compliance mandates.In addition to the reliability needs, the current EMS configuration is also nearing its maximum capacityand needs expansion.

EMS is used to remotely monitor and control 225,000+ devices at over 1000 Transmission andDistribution Substations using the EMS SCADA – Supervisory Control and Data AcquisitionEMS and Phasor systems are used to manage the planned and emergent outage coordination withCAISO, PEAK RC (Reliability Coordinator for the Western Interconnection) and neighboring utilitiesGCC studies and manages power flow for system reliability to minimize risk of customer serviceimpactsGCC personnel use EMS and Phasor to monitor operating parameters such as voltage, frequency,power flow, and equipment statusDay to day operation of the sub transmission and distribution system using EMS is carried out byswitching centers geographically dispersed around the SCE system

110



INVESTMENT MEMO

(2 of 5)

Scope

The EMS Refresh scope will replace aging computing hardware and network equipment critical tomaintain communications with field devices. It will also enhance existing test environments to providemore effective testing prior to deployment. In addition, the refresh project will upgrade system andapplication software and expand user capacity to meet projected future growth.The EMS and Phasor consolidation will migrate the separate instances of the GE solution to a sharedinfrastructure. This consolidation will substantially reduce the total number of components in the systemthereby reducing maintenance and support costs.This project was launched in June 2016 and is expect to complete in mid 2018.

Criticality of Refreshing EMSSome of the system components are reaching end of life at the end of 2017 which will causesupport issues as well as compliance issuesThe risk of hardware failures continues to rise as the system ages. The system hardware andsoftware are from 2010 and will be 7 years old at the time of deploymentConsolidation will offer the obvious benefit of optimizing the IT portfolio, align with thecompletion of the 5 year maintenance cycle of the Phasor system, thereby avoiding the cost of acostly Phasor system refreshUnifying the view of Phasor and EMS for the users will improve user adoption, thereby improvingrealization of benefits on the investments made in the Phasor system

EMS Out of Scope are:Enhanced Business Resiliency for EMS

111



INVESTMENT MEMO

(3 of 5)


Consolidating Phasor and Refreshing EMS supports NERC and PEAK RC Reliability standards.

Compliance GuidelinesRefreshing EMS will allow SCE to maintain system reliability at 99.95% or greater and reduce the risk posed bycomponents reaching end of useful life. System reliability of EMS is important to SCE Grid Operations becauseEMS system failures could result in a direct impact to safety, customer service, operations, and compliancemandates. In addition to the reliability needs, the current EMS configuration is also nearing its maximumcapacity and needs expansion.

EMS data must be shared with CAISO Peak RC and adjacent entities to ensure overall situational awareness inthe western interconnection.


Maintain system reliability at 99.95%. EMS system failures could result in a direct impact to Safety,Customer Service, Operations and Compliance mandates.Improved efficiency through centralization of configuration management of critical networkinginfrastructure.Quicker recognition of potential system vulnerabilities through integration of phasor data in EMS.Achieve IT Portfolio Optimization by consolidating EMS and Phasor platforms into a single instance,providing unified operator view.Amore robust QA environment will enable greater testing effectiveness and reduce quality risk as wellas the risk of cost and schedule overruns.Reduce the risk of system failures and business impact events, which have a direct impact tocustomers, operations and compliance mandates.


Since all the existing functionalities and capabilities in EMS and Phasor will be retained, the Grid Operators willnot only retain all existing functionality, but will also receive incremental functions, which will help themperform their job more effectively.

Grid Control Operators and Dispatchers will be trained with the updated features to ensure compliance trainingis completed.

Compliance and Training and Substation System Operators will be directly involved in testing to ensure SystemOperator Training Compliance requirements are met. Grid Operators are properly trained on changes made tothe system.

There will also be impacts to the Grid Operators during the cutover, which will be managed through detailedcutover and communication planning to ensure the right level of engagement with all user groups.

112



INVESTMENT MEMO

(4 of 5)


Some of the system components are reaching end of life at the end of 2017 which will cause support acompliance issues.The risk of hardware failures continues to rise as the system ages. The system hardware and softwareare from 2010 and will be 7 years old at the time of deployment.Consolidation will offer the benefit of optimizing the IT portfolio, align with the completion of the 5 yearmaintenance cycle of the Phasor system, thereby avoiding the cost of a costly Phasor system refresh.Unifying the view of Phasor and EMS for the users will improve user adoption, thereby improvingrealization of benefits on the investments made in the Phasor systemConsolidating Phasor with EMS will help SCE optimally manage the transmission grid in a reliable securemanner.The technology will increase overall transmission reliability, proactively minimizing blackouts and helpSCE meet stringent security requirements.Business will derive greater benefit through a consolidated system (EMS, Phasor) so they can have aunified view of the data and a single origination point of control commands. To do this, SCE’s systemoperators and engineers must be able to accurately identify transmission stress and measure how closethe grid is to failure.

RTU -Installed atgeneration plants andsubstations to gatherdata and control devices

Master Station (DAC) Part of the SCADAsystem that initiate data gathering fromRTUs every few seconds

CommunicationTelecommunication facilities suchas, telephone lines, Microwave,Radio, or Satellite

User Interface (UI)User Interface forAlarms, Events andGraphical Mimic of

113



INVESTMENT MEMO

(5 of 5)

G. Proposed Options

Alternative 1: Do not perform the refresh and consolidation project.Alternative 2: Perform refresh of EMS hardware and software now, but do not consolidate thePhasor and EMS systems.Alternative 3: Perform EMS hardware refresh without upgrading software and not consolidate thePhasor and EMS systems.Alternative 4: (Recommended) – Upgrade EMS Hardware and Software, as well as consolidate EMSwith Phasor

114



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115



Outage Management System (OMS) Refresh

116



01,0002,0003,0004,0005,0006,0007,0008,000



Pin #: 3896

WBS Element: CIT-00-DM-DM-000050

2. PROJECT DETAIL:






5. CLOSE DATE: 7/1/2017


Year6,800

3,500

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

10,300


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Outage Management System Refresh (OMS)

See Testimony.

See Testimony.

Outage Management System Refresh (OMS)

117



(1 of 5)

Outage Management System (OMS) RefreshA. Requested Committee Decision / Feedback

The project will request approval from Planning & Performance Reporting (P&PR), and/or Capital PrioritizationTeam (CPT) approval and Treasurers review prior to commencement.

B. Project Overview

This project has been established to perform and support a planned refresh of our Outage Management System(OMS). OMS is a Commercial Off The Shelf (COTS) product developed and maintained by CGI. OMS is the systemused by the T&DGrid Operations Department tomonitor, identify, andmanage electrical system outages on SCE’sdistribution network. It provides critical information for the identification and restoration of electrical serviceoutages down to the meter level. In addition, OMS is the source of outage information for many internal andexternal facing applications such as Customer Service System (CSS), Outage Database & Reliability Metrics System(ODRM), and SCE.com.

Existing SCE software assets are typically on a 5 year refresh cycle in order to avoid obsolescence. However, thelast OMS version refresh was implemented in 2008 and was based on a product version that was commerciallyreleased in 2004, thus making the core components of the current tool over 10 years old. Planned refresh of thissystem is important to ensure SCE maintains a stable and reliable outage management tool that can successfullyintegrate with other critical support systems. Refreshing the OMS application and staying within one version ofthe vendor’s most current product also supports our ability to secure more reliable maintenance and support,whether through CGI or a third party vendor certified to support the application. Additionally, the previoussoftware refresh from version 2 to version 5 did not include a system re architecture.

The OMS Refresh will deliver a systemwith the vendor’s most current software and hardware in order to improvethe level of system availability, usability, and reliability required to support the needs of our businessorganizations and customers, and comply with regulatory mandates concerning capabilities around OutageManagement.

The project will be executed in a three phased approach: 1) upgrade the current application (CGI) to its latestversion, 2) implement a series of enhancements, and 3) implement a Transmission Substation (Trans Sub) model.

OMS Refresh scope includes:

Implementation of the standard suite of products of CGI’s outage management application based on theCGI OMS version 6.5Improvements to the Outage Alert Notes and to the OMS CSS interface to keep Outage Alert Notes insync with OMS InformationWeb access version of OMS for non essential users to lessen the impact on the OMS production databaseNewmodule provides enhanced graphic functions including improved circuit and substation visualizationEnhancements to the usability of the Outage Management Dashboard for effective decision making andsituational awarenessImplementation of the Incident Priority Scoring Algorithm for prioritization of outagesA range of SmartConnect functionality including: Integrated ability to check and report instantaneousline side voltage on SmartConnect meters, including groups of meters

118



(2 of 5)

Modeling of Substation, Transmission, and Sub Transmission systems, which will enable outage/incidentgrouping to these asset levels

OMS Refresh scope excludes:Some enhancement/modifications that were assessed but determined to be out of scope for the OMS Refreshinclude:

Modification or replacement of ODRM in OMSReal time SAIDI/SAIFI reporting from OMSSubstation Outage Request Log (SORL) AutomationExpanded use of Pragma Switch module for unplanned and emergent outage switching and execution

The following assumptions and dependencies are applicable to the OMS system in regards to the RefreshProject:

1. SCE’s Energy Management System will be the source for all Transmission, Sub Transmission, andSubstation model data;

Impact if not correct: Alternate source of model data will need to be located or created, potentiallyextending project timeline and increasing cost;

2. All existing interfaces will be used as is, except CSS interface, which will be re designed into a morestable architecture;

3. Existing EMS SCADA functions will continue to be available;

4. Existing DMS SCADA functions will continue to be available;

5. OMS system will continue to be the primary system for updating and processing trouble call & outageinformation after a call is taken in CSS or received via SmartConnect/AMI notification;

6. Smallworld GIS application will continue to be used for creation and maintenance of the distributionnetwork model;

7. Training will be consistent with T&D standards and procedures. All training material, approach andschedule will need to be evaluated and approved by the core team and project SMEs; and

8. OMS disaster Recovery components shall be available and operational prior to project testing andimplementation phase.

OMS Interfaces with:Consolidated Mobile Solution (CMS)Click ScheduleCustomer Service System (CSS)GE Small World (GESW)SCE.COMSAPEnergy Management System (EMS)Distribution Management System (DMS)Outage Data Reliability Metrics (ODRM)Business ObjectsSmartConnect Network Management System

119



(3 of 5)

Where does the proposed solution fit on the IT roadmap and within existing technologies?

This OMS Refresh has been established as a core part of the T&D Capability Roadmap since it was last filed inthe GRC. OMS also serves many of CS’s business capabilities. Enterprise Architecture was a key part indeveloping the roadmap and evaluating the need and timing of an OMS technical refresh vs. the option ofseeking a full replacement or doing nothing. It was determined that a technical refresh at this point on theCapability Roadmap would be supportive of recently implemented/implementing solutions such as cGIS andCMS, as well as setting the stage for successor efforts such as the Scheduling Refresh and Storm Managementand Analytics capabilities.

A core component of this project is a technical refresh of CGI’s OMS application, which is currentlyimplemented at SCE. Additionally, there are a moderate number of enhancements. This technical refreshprovides a foundation for the following:

Utilization of an industry standard, vendor supported interface solutionTighter integration with SmartConnect data and functionality

C. Implementation Overview

2014• Gather Business Requirements• Business Process Workshops• Capital Review Team (CRT) Approval

2015• Interface Workshops• Design and Build –Technical Refresh• Factory Acceptance Testing (FAT) – Technical Refresh

2016

120



(4 of 5)

• Factory Acceptance Testing (FAT) – Enhancements• Site Acceptance Testing (SAT) – Technical Refresh• Implementation for Technical Refresh

2017• Site Acceptance Testing (SAT) – Trans/Sub Connectivity Model• Site Acceptance Testing (SAT) – Enhancements• Implementation for Enhancements• Implementation of Trans/Sub Connectivity Model

D. Project Rationale

The Outage Management System (OMS) is a critical system that needs a version refresh to the latest OMSsoftware release to maintain the current level of system availability, usability, and reliability.

The OMS Refresh will enhance system performance and reduce the potential for a repeat of past storm andsubstation event impacts such as:

1. Poor production performance during 2011 storm that resulted in extended customer outages. TheCorporate Storm Performance Improvement Program (CSPIP) evaluation concluded that improvementsneeded to be undertaken to improve our performance in areas of storm operations, management, andrestoration. This includes key enhancements based on that evaluation that will further SCE’s ability toprovide real time situational awareness to SCE storm personnel.

2. Assessment of OMS performance during Substation outages (including Rector 66kv and Santa Monica16kv/4kv) identified the benefits of improved OMS performance and enhanced use of the networkconnectivity model as part of Outage Alert Notes, Predictive Grouping, and Outage Prioritizationprocesses.

Consequences of not Implementing the Project

SCE’s OMS software version will become obsolete and there is a risk it will not be supported by thevendorWithout hardware and software improvements, OMS performance will continue to be compromisedduring major system and storm eventsOMS improvements identified during CSPIP evaluation will not be implementedImprovements identified during Rector and Santa Monica root cause analysis will not be implementedImproved integration and efficiencies between OMS and SmartConnect meters will not be achieved

E. Project Benefits

Benefits Overview

Qualitative Benefits:

Highlights of Benefits Associated with the Technology Refresh:• Mitigates OMS performance issues during system events

Creates parallel database for web use which ensures impacts to the production system areminimized in times of heavy useReporting and analytics also utilizes non production database

• Replace OMS CSS InterfaceAlleviates main contributor to OMS related planned and unplanned outagesPI outages affect vital data going to CSS and AOC/SCE.COM, EMS SCADA data to OMS

121



(5 of 5)

Highlights of Benefits Associated with the Enhancements:• SmartConnect Integration:

Voltage checks minimize the use of multiple systems to perform the same function, simplifyingprocess and improving efficiency of dispatcher processAuto energizing PRNs allows for accurate energize times and lessens dependency on multiple touchmanual processes; also contributes to resolution of the ERT metric issue

• Incident Prioritization:Key initiative of Corporate Storm project based on CPUC direction to provide comprehensiveprioritization solution for outage responseProvides automated methodology for prioritizing incidents during highly complex and time sensitivestorm events

• Enhanced Connectivity Model:Perform end to end outage modeling through the use of a Transmission, Sub Transmission, andSubstation As Is connectivity modelQuicker identification of event magnitudeEffective outage grouping above the distribution level

• Miscellaneous Enhancements:See presentation for a full description and associated benefit of each enhancement

Quantitative (Budget savings must be quantified)• Primarily a technical refresh to avoid obsolescence, thus quantitative benefits are N/A

G. Alternatives

There are 3 potential alternatives to the Outage Management System Refresh:

Alternative No. 1 (Recommended): Deliver the following 3 releases: 1) Upgrade the current application (CGI) toits latest version; 2) Implement a series of modest enhancements 3) Implement an end to end outage modelingthrough the use of a Transmission, Sub Transmission, and Substation as is connectivity model.

OMS is a mission critical Level 1 Application that supports the Grid Control and Operations. CGI is the currentvendor for the OMS function, and is a proven industry leading vendor. CGI technology is aligned with SCE’sapproved IT Standards and Road Map. Requirements cannot be met with a manual work around, and no otherexisting SCE applications can be leveraged. Additionally, other major utilities have the same business need andutilize an OMS solution for their Outage Management needs.

Alternative No. 2: Do not upgrade or implement enhancements, and keep the current application as is. Thisalternative has significant risk to a) system availability as the product will be unsupported by the vendor, b)Reliability and public safety while SCE operates manually during times of OMS system outage. Furthermore, anyassociated benefits related to enhancements and the Trans Sub Connectivity model will not be realized.

Alternative No. 3: Refresh the current application to its latest version (technology upgrade only). Selecting thisoption, would prohibit SCE from realizing previously identified benefits from storm response and Smart Meterintegration, as well as any associated benefits related to enhancements and the Trans Sub Connectivity model.

122



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Distributed Management System (DMS)

124



0200400600800

1,0001,2001,4001,600



Pin #: 6425


2. PROJECT DETAIL:






5. CLOSE DATE: 9/1/2016


Year1,500

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,500


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Distribution Management System (DMS) Refresh

See Testimony.

See Testimony.

DMS

125



1. Assumes 10% discount rate; ignores taxes

Distribution Management System (DMS) EXECUTIVE SUMMARY (1 of 2)

PROJECT OVERVIEW

Buy or build: [X]Leverage current capabilities: [ ]

Description:

Distribution Management System (DMS) is the centralized computing system that allows SCE to gather data from various distribution automation devices and facilitate automated operation and control of the distribution system as a whole. The project strategy is to leverage new technology and features that have been commercially developed and replace SCE’s custom-built Distribution Management System.

This system replacement will include installation of software, hardware, and data storage equipment. This new system will allow advanced remote control, monitoring, and analysis of distribution system devices to improve reliability and optimize voltage to reduce SCE’s annual energy costs.

The upgraded DMS is being implemented in two phases:

1. Phase 1 – Perform analysis and detailed system design, and install new DMS hardware platforms and software to replace the currently obsolete DMS; and

2. Phase 2 - Implement DMS advanced engineering applications to improve the electric distribution system capabilities for conservation voltage reduction. An advanced training simulator will provide “real world” training for system operators. Phase 2 will be implemented in 3 releases.

PROJECT RATIONALE

Discretionary / Non-negotiable: Discretionary

Justification:

The existing DMS is at the end of its useful life and the replacement is needed to manage grid reliability. DMS is an essential system to operate SCE’s system and maintain its reliability. Loss of automation would result in customers experiencing more and longer outages.

Rate impact:

Increase

Business needs:

Replacing the existing DMS addresses the following technical shortcomings:

1. Software obsolescence; 2. Insufficient data management capability; 3. Insufficient security; 4. No Operator Training System; and 5. No Advanced Distribution Grid Control and Analysis

Applications.

Urgency:


The new DMS system is required to enable SCE future vision and is foundational to the deployment of Smart Grid technologies. It is also required for implementing and realizing the benefits.

126



1. Assumes 10% discount rate; ignores taxes

Distribution Management System (DMS) EXECUTIVE SUMMARY (2 of 2)

KEY BENEFITS

Benefits:

1. Switches from in-house-built to COTS system, which provides full vendor support for defect resolution and future upgrades;

2. Handles new automated devices added to the distribution network to better analyze circuits, which leads to better planning and remediation of system problems;

3. Improved capabilities of meeting security requirements, for authentication of user-command and control data;

4. Provides an operator training-simulation feature for all switching center operators, which provides a realistic behind-the-wheel training experience that tests the operator’s capabilities to perform under a real-world stress situation; and

5. Provides advanced control and analysis capabilities allowing SCE to implement self-healing security, which provides automated responses to system problems.

Justification of Benefits:

N/A

KEY ISSUES / RISKS

Key risk factors for this multi-year project include:

1. Program management; 2. Turnover in SCE project team; 3. Business ownership from client sponsors; 4. Lack of issue resolution and decision-making; 5. Business processes not aligned with software capabilities; 6. Lack of communication between all parties; 7. Unrealistic goals and timeframes; 8. High caliber end-users; and 9. Strong OCM planning and execution.

ALTERNATIVES

Alternative No. 1: Do nothing is an option in this case as the current software is obsolete and no longer supported by the vendor. The current application is reaching capacity limit of the current equipment database which will limit future substation automation. The current tool set has lack of advanced engineering applications and also lacks Operator training simulation tools;

Alternative No. 2: Discontinue the Phase 1 DMS replacement effort resulting in a $0.9M contract penalty and risking a $19.4M write-off for costs already incurred. This would lead to issues with system availability and performance, along with extended customer outages; and

Alternative No. 3: Complete the Phase 1 DMS replacement and not implement the Phase 2 Advanced Engineering Applications resulting in a $0.9M contract penalty and $6.2M write-off for costs already incurred. This would not allow AVVC benefits to be realized.

127



1

Distribution Management System A. Implementation Overview

DMS Phase 1 was implemented in April, 2012. Phase 2 was planned to be implemented in three releases. Release 1 was implemented in 2014 for AVVC (Advanced Voltage VAR control) capability Release 2 was implemented in 2015 for Operation Training Simulation capability. Release 3 is being implemented in 2016 for advanced control and analysis capabilities.

B. Project Rationale

Distribution Management System addresses the following business needs:

1. Software obsolescence: The existing DMS relies on third party software that is no longer produced or supported by the vendor. The existing DMS uses Sybase for database management, which is no longer supported by the Information Technology group. Factorylink for AIX, a software product from USDATA, was used for the SCADA communications interface in our DMS and this software package is no longer supported by USDATA, now named UGS. As hardware continues to evolve, our obsolete software will limit future hardware upgrades and the total system will become obsolete;

2. Insufficient data management capability: Over the years, SCE’s efforts to automate the distribution grid have resulted in more field equipment communicating more information back to SCE’s back office systems. The internal database for DMS was originally limited to 10,000 devices. Modifications to the software, patches, have extended its capabilities, but it is limited. We currently have over 15,000 field devices in our system and within six years the current system will no longer be capable of handling the anticipated growth;

3. Insufficient security: The existing DMS system suffers from several security shortcomings such as: (1) the inability to authenticate command and control data associated with remote equipment operation, (2) inadequate mechanisms to detect and report anomalous or inappropriate system use, (3) and the inability to perform auditable system administration mechanisms. The lack of system and application support for the existing DMS system makes integrating adequate mitigating measures extremely difficult. The latest generation security features need to be designed into the system from the start to be most effective. SCE requires a DMS that has security architected into the system during the design phases. SCE’s system was designed over a decade ago, and we now live in a post 9/11 environment were the electric grid is a plausible target for cyber terrorists;

4. No Operator Training System: The existing DMS lacks the ability to support operator training simulations that we currently need in light of the demands that we must place on our switching center operators. Existing training for switching center operators consist of training and emergency drills presented in a scripted, paper-based overview method. Simulation training is significantly more powerful than on paper overview-type training. In order to keep our system operators at a sufficient level of readiness to operate a growing distribution grid, it is necessary to provide realistic “behind the wheel” training that can only be provided by an Operator Training Simulator in an upgraded DMS. The difference is akin to classroom Driver’s Ed versus behind-the wheel Driver’s Training; and

5. No Advanced Distribution Grid Control and Analysis Applications: The existing DMS was designed to be a distribution grid remote control and monitoring system, not an automatic control system. It is not designed to take any automatic control actions based on circuit field conditions; rather, the distribution grid operator is required to evaluate all field device information presented on the DMS and then remotely control each field device to mitigate the problem. New generation DMS systems include advanced control and analysis software to provide the grid operator with automatic control functions that can assist the operator in responding to emergencies.


128



2

The new DMS system is required to enable SCE future vision and is foundational to the deployment of Smart Grid technologies. It is also required for implementing and realizing the benefits.

C. Key Benefits

Distribution Management System provides 5 key benefits:

1. Switches from in-house-built to “Commercial-Off-the-Shelf” system, which provides full vendor support for defect resolution and future upgrades;

2. Handles new automated devices added to the distribution network to better analyze circuits, which leads to better planning and remediation of system problems;

3. Improved capabilities of meeting security requirements, for authentication of user-command and control data;

4. Provides an operator training-simulation feature for all switching center operators, which provides a realistic behind-the-wheel training experience that tests the operator’s capabilities to perform under a real-world stress situation; and

5. Provides advanced control and analysis capabilities allowing SCE to implement self-healing security, which provides automated responses to system problems.

D. Key Issues / Risks

Distribution Management System provides 4 key issues/risks:1. Business ownership from client sponsors need to be maintained for overall project acceptance; 2. Informed and rapid issue resolution and decision-making is required; 3. Business processes aligned with software capabilities; and 4. Constant open and candid communication between all parties through strong OCM planning and

execution is required.

E. Alternatives

Distribution Management System provides 3 alternatives:

Alternative No. 1: Do nothing is an option in this case as the current software is obsolete and no longer supported by the vendor. The current application is reaching capacity limit of the current equipment database which will limit future substation automation. The current tool set has lack of advanced engineering applications and also lacks Operator training simulation tools;

Alternative No. 2: Discontinue the Phase 1 DMS replacement effort resulting in a $0.9M contract penalty and risking a $19.4M write-off for costs already incurred. This would lead to issues with system availability and performance, along with extended customer outages; and

Alternative No. 3: Complete the Phase 1 DMS replacement and not implement the phase 2 Advanced Engineering Applications resulting in a $0.9M contract penalty and $6.2M write-off for costs already incurred. This would not allow AVVC benefits to be realized.

129



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2. PROJECT DETAIL:






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Grid Analytics Applications

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E w

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vera

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s en

terp

rise

anal

ytic

s pl

atfo

rm to

sto

re th

e fo

unda

tiona

l grid

dat

a ac

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ed b

y th

ese

grid

ana

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s ap

plic

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nsS

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will

co-

deve

lop

anal

ytic

s w

ith le

adin

g ve

ndor

(s) o

r con

sulta

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) in

this

fiel

dS

CE

will

impl

emen

t ana

lytic

s so

lutio

n in

mul

tiple

pha

ses

(Loa

d/V

olta

ge, W

eath

er, T

LM a

nd P

hase

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tific

atio

n)A

n ex

ampl

e of

an

embe

dded

CO

TS li

cens

e w

ould

be

for s

peci

aliz

ed a

naly

tics

algo

rithm

(s)

Grid

Ana

lytic

s A

pplic

atio

ns

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licat

ion

Dev

elop

men

t Pro

ject

Tota

l Cos

t of P

roje

ctFT

E E

stim

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n

136



Long-Term Planning Tools

137



0

1,000

2,000

3,000

4,000

5,000

6,000

7,000



Pin #: 7963


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year459

6,323

6,029

2,260

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

15,070


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Long Term Planning Tool

See Testimony.

See Testimony.

Long Term Planning Tool

138



2016

2017

2018

2019

2020

Tota

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f var

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Ana

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s, R

isk

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s an

d P

rote

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naly

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SC

E w

ill p

rocu

re s

ever

al C

OTS

pro

duct

sS

CE

may

enh

ance

or c

usto

miz

e th

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oduc

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ill im

plem

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n m

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Foun

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ced

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ptim

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e ha

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are

com

pone

nts

for t

he L

TPT

incl

udes

: App

licat

ion

Ser

ver,

Web

Ser

ver,

and

Dat

abas

e S

erve

r. Th

ese

serv

ers

will

be

mad

e av

aila

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in tw

o da

ta c

ente

rs (P

rimar

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lham

bra

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a C

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ente

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CE

exp

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to h

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appl

icat

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serv

er a

nd T

OM

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bas

ed w

eb s

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rs.

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cle

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data

will

be

used

as

data

base

ser

ver.

>$5M

Long

-Ter

m P

lann

ing

Tool

CO

TS A

pplic

atio

n Pr

ojec

tLa

rge

CO

TS P

roje

ct

139



Grid Connectivity Model

140



0

1,000

2,000

3,000

4,000

5,000

6,000



Pin #: 7963


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year3,440

5,025

5,049

1,432

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

14,946


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total


See Testimony.

See Testimony.


141



2016

2017

2018

2019

2020

Tota

lO

ngoi

ng O

&M

23%

33%

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rmat

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CE

will

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M w

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adin

g ve

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(s) o

r con

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) in

this

fiel

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s to

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r wor

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Dev

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men

t Pro

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Tota

l Cos

t of P

roje

ctFT

E E

stim

atio

n

142



Transmission and Distribution Projects less than $3 Million

143



0

500

1,000

1,500

2,000

2,500

3,000



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2018


Year0

0

2,600

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,600


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Substation Health Assessment Tool (previously Asset Mgmt)

See Testimony.

See Testimony.

Substation Health Assessment Tool

144



INVESTMENT MEMO

(0 of 3)


Substation HealthAssessment Tool

145



Substation Health Assessment Tool INVESTMENT MEMO

(1 of 3)

I. Business Initiative DescriptionA. Initiative NameSubstation Health Assessment (Previously Asset Management)B. Initiative DescriptionThis business initiative is driven by the need to incorporate operational excellence, OpX into SC&M’scurrent Condition BasedMaintenance (CBM) programs (i.e. PredictiveMaintenance Assessment (PMA),Circuit Breaker Analysis (CBA), Dissolved Gas Analysis (DGA), Oil Circuit Breaker Analysis (OCBA), Oil TapChanger Analysis (OTA)) which use a methodology and set of tools designed to determine conditionand/or performance of an asset. This initiative seeks to enhance the Condition Based Maintenanceprograms by utilizing a new tool to perform trending based upon complex algorithms specific to SCE’sassets. As a result of the asset health; there is an opportunity to offset existing maintenance cycleswhich could result in a reduction in unnecessary O&M spending; improve reliability of assets and a riskof catastrophic events.

The overall scope of this project is to reduce O&M costs and improve SC&M’s financially drivenmaintenance decisions through the development of an integrated tool that can assess maintenanceneeds based on equipment condition and probability of failure.

The aim is to acquire a tool, with a common data platform that will integrate predictive maintenancepractices and overcome deficiencies in the health assessment for major critical substation equipmentsuch as transformers, circuit breakers, and protection systems and to accurately monitor, track, andassess the equipment’s performance and lifecycle based upon a calculated assessment of data. It willemploy industry best practices as to enhance themaintenance program, offset maintenance dollars andextend maintenance cycles.

In addition, the new tool should provide a common platform and improved tracking, trending, analysis,and standardized reporting. This process will be accomplished through quantifiable failure analysismetrics, using algorithms developed specifically for SCE equipment, based on industry standards.C. Business Strategic AlignmentOne of the main components of delivering reliable electric power delivery is the capital budgeting andoperation and maintenance of facilities. For the most part, the cost for purchasing equipment andconstructing facilities is fixed; therefore, O&M is the primary candidate for reducing costs. As theequipment continues to age and gradually deteriorate, the probability of service interruption due toequipment failure increases. In order to gain operational and service excellence through affordability,SC&M’s goal is to reduce O&M spending through financial driven maintenance decisions whilemaintaining high reliability. Therefore, an effective maintenance strategy is essential for safe, reliable,and economical delivery of electricity. The Substation Health Assessment tool aligns to this businessstrategy.

The goal of this effort is to acquire an integrated tool designed to perform failure and trending analysisbased on data from operational, historical, test results and industry trends. Once the data is on a commonplatform, assessments of equipment health and performance can be analyzed based on industrystandards. The ability to determine equipment health, utilizing an automated, centralized, data analysisengine, can be determined based on age, maintenance history, and past performance. Through this, theability to perform trending with the use of complex algorithms specific to SCE can begin. It is essential to

146



INVESTMENT MEMO

(2 of 3)

understand of the criticality of our assets within the system, and to possibly eliminate catastrophic inservice failures. The information gathered will be used to maintain and monitor the health of theequipment. In addition, it will provide the potential effects on the predictive maintenance assessment ofwork, through forecasting.D. Anticipated Business Outcomes & BenefitsIn order to achieve affordability for our customers, part of OpX is to gain operational and serviceexcellence of affordability through the reduction of Operation Maintenance (O&M) spending. The O&Mbudget includes maintenance of apparatus equipment; such as transformers, circuit breakers, protectionequipment, etc. In addition, this also includes planned work, unforeseen work, costs associated withemployees, and sunken costs.

As part of OpX, the goal is not only to reduce O&M spending, but also to use prudent judgment inspending; not to risk our reliability, specifically through increased System Average Interruption DurationIndex (SAIDI), and System Average Interruption Frequency Index (SAIFI).

Through the use of this integrated tool, the purpose is to evaluate equipment health within the substationby using a combination of historical data, maintenance records, and trending results analysis. This data,along with a developed complex algorithm, will be used to determine the overall health index of theequipment. Once an evaluation is complete and the equipment is deemed healthy, and not at risk, thereis an opportunity to offset the maintenance cycle. Conversely, if the equipment is proven unhealthythrough the analysis, appropriate steps may be taken to address issues. This practice will allow SC&M toallocate the proper dollars and resources to equipment that truly needs maintenance and reducespending on healthy operating equipment.

The Dissolved Gas Analysis for example; samples are performed at the Material Test Laboratory inWestminster and the cost to evaluate the dissolved gas within a transformer is $157 per sample. Basedon asset management system, currently there are 2,647 B bank transformers on line. Therefore, if thetrending results state that 50 percent of our B bank transformers are performing well and we offset theirmaintenance cycle by one year, this could result in a cost savings of more than $208 thousand annually.

147



INVESTMENT MEMO

(3 of 3)

E. Business Impact AssessmentThe technology solution would be impactful to SC&M’s existing Infrastructure Replacement (IR) programand its condition based maintenance programs (Predictive Maintenance Assessment (PMA), CircuitBreaker Analysis (CBA), Dissolved Gas Analysis (DGA), Oil Circuit Breaker Analysis (OCBA), and Oil TapChanger Analysis (OTA)).

Through the use of this integrated tool, with the ability to more accurately evaluate equipment healthwithin the substation using a combination of historical data, maintenance records, and trending resultsanalysis and the SCE specific complex algorithm; SCE would have the ability to better determine theoverall health index of the equipment. Once an evaluation is completed and the equipment is deemedhealthy, and not at risk, there is an opportunity to offset the maintenance cycle or if proven unhealthythrough the analysis; appropriate steps would be taken to address any issues. Additionally, the technologysolutions report findings can be impactful to the replacement strategy.G. Proposed Options

1. Option No. 1: Do nothing and not move forward with a technology proposal. Currently, SC&M usesthe Infrastructure Replacement, IR program, MS Access databases and SAP’s Condition BasedMaintenance (CBM) programs to facilitate the maintenance effort. To not move forward with a newtechnology solution; means missed opportunity to address more critical asset first and missedopportunity to achieve possible reduction in O&M spend through extending maintenance cycles.

2. Option 2: COTS Solution – Perform an Industry Search and procure and implement the installation andconfiguration of a COTS tool. This includes taking time to analyze and document the requirements inmore detail and to go through the RFI/RFP process. It could require new interfaces, licensing of a newapplication, and additional ongoing maintenance cost with the introduction of a new application.

o Doble Risk Assessment Management, dobleARMS is a COT’s solution; an analytical toolinfused with Doble’s expertise in asset life cycle and associated risk. Providing the ability tomake more informed decisions between times of crisis and long range operational planning.

o Accenture solution – is a COT’s solution; advanced analytics applications with end to endanalytics solution with flexible apps, quickly designed and fully integrated into the workflowprocesses

3. Option 3: SAP solution; continuing with our existing Enterprise SAP solution and building on itsfoundation to extend functionality as required to enhance existing maintenance planning capabilitiesfor SC&M.

148



2016

2017

2018

2019

2020

Tota

lO

ngoi

ng O

&M

0%0%

100%

0%0%

100%

CO

TS L

icen

se50

0,00

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2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year0

0

1,260

720

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0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,980


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Substation 3D Design

See Testimony.

See Testimony.

Substation 3D Design

150



INVESTMENT MEMO

(0 of 3)


Investment MemoSubstation 3D Design

Project

151



(1 of 3)

I. Business Initiative DescriptionA. Initiative NameSubstation 3D Design

B. Initiative DescriptionCurrently, Substation Engineering designs are 2D, which are just lines on paper with very minimal notations.There is no meta data stored in the drawings that provide any valuable information such as features, attributesand more. Additionally due to the lack of integration, it is easy to make changes on one drawing and forget tomake the appropriate changes to the other affected drawings.

The goal of the Substation 3D Design project is to utilize a 3 Dimensional design versus a 2 Dimensional design.The 3D model will increase work efficiency, visualization and leverage the data collected to mitigate futureimpacts for Substation Construction and Infrastructure Replacement activities. The project will help SCEEngineers to efficiently create designs internally and review the designs received from contracted engineeringfirms. With additional standardization, the project will facilitate the communication of a design to seniorleadership and regulatory agencies and customers.

The 3D technology is another step forward to get away from paper drawings. By switching to a 3D CAD system,the engineer would no longer have just lines on paper, but instead would have blocks and features that arefilled with meta data about what exactly it is and why they’re using it. Through the development of associatinginformation, modifying one drawing would update other drawings with associated assets without requiring theadditional drawing to be opened. In a 3D environment, the designs and calculations would be on a correct scalethat will allow the engineers to make a better decision on clearance checks, and identify layout mistakes likebuilding a fence where equipment doors would open. It would also help reduce time in preparing material billsas everything will be associated with meta data, and each block would already know the material required for it,thus, the engineer could associate the SAP numbers with that material giving them a print of everything theyneeded for DM.

The proposed project will deliver a solution set that addresses the needs of the Substation Engineering groupand will help in the efficiency of future designs.

C. Business Capabilities MappedThe following Level 2 Business Capabilities are mapped for this effort :

1. Enterprise Asset Management – Asset Planning – Engineering Drawing2. Work Management – Work Planning – Graphic Design

D. Business Strategic AlignmentThe solution set is expected to implement a change in tools and process to facilitate the utilization of 3D versusa 2D CAD designs. The 3D design technology would augment and enhance SCE’s modular design and align withcommon design for our substations. The solution set is expected to be useful with visualization and utilization ofmeta data across various organizations. The whole idea with the 3 dimensional software is about the efficiencyand visualization of future project conceptualization.

152



INVESTMENT MEMO

(2 of 3)

E. Anticipated Business Outcomes & Benefits

The purpose of this project is to address inefficiencies inherent in the current work process. It is also possibleto address the technology conundrum by leveraging/updating SCE’s existing technology stack. This projectwill allow SCE substation designers and engineers to:

Enable visualizations for project conceptualization and drawing reviews.Eliminate the manual process and be able to see blocks that are filled with Meta data instead of justlines on a paper with no data values.Automatically update other drawings after one drawing is modified without having to open each ofthem separately to update them.The drawing scale would be more accurate in a 3D environment which will help with makingclearance checks or obstructions that may require additional work. For example, allowing users toidentify layout mistakes such as building a fence where equipment doors would open.Reduce time in preparing material bills. For example, each block will have the ability to determinematerial information with Meta data association.Create efficient designs with the ability to rotate 360 degrees, zoom in on the object to seephotorealistic images and quickly generate exploded views for technical illustrations.Integrate with other systems such as SAP and DM to avoid redundancy of data entry and increaseefficiency. E.g. Ability to associate the SAP numbers with material bills to allow users to print thematerial information required in Design Manager (DM).

By meeting these objectives, SCE will improve efficiencies and move towards a more dynamic and productivedesign process.F. Business Impact Assessment

The proposed solution will provide the business with new capability for visualization of project concepts. It willenable a rich content review with the executives and 3rd parties. This project will address the aforementionedissues that we identified in the Project Initiative Description section. While there are no anticipatedorganizational changes associated with this project, there will be some process changes associated with thisproject. These changes primarily will affect the tools and methodology for designing projects, projectcoordination and communication between SCE Senior Leadership, Substation Engineers, EngineeringContractors, and Field Personnel. It is expected these activities will be done by the current groups performingthem with no change in AORs among SCE organizations. Some anticipated business impacts include (not acomplete list):

For IT:o A new infrastructure may be requiredo Incremental cost/token in future years

For the Business Units (e.g. Substation Engineering)o Process change for Substation Engineers when creating new drawings/design for the new

substations and infrastructure replacement.o Impact the current business process of reviewing designs for Substation Engineering. For

example, Q&A review process of drawings received from a 3rd party engineering firm.

153



INVESTMENT MEMO

(3 of 3)

G. Technology/Automation Rationale

Technology will enable a broader realistic visualization and integration of tools to craft conceptual designs.Automating 2D manual paper drawing to a 3D drawing will provide a more dynamic view of the designs that canbe easily shared among all the stakeholders across the construction and design of the project lifecycle.

The solution set is expected to help with creating more efficient designs with a greater level of detail and getaway from paper drawings. The broader context of the visualization will allow engineers and managers toprovide a new perspective on progress.

H. Proposed Options

Three alternatives were considered for this project:

Alternative No.1: Do nothing and not move forward with a technology proposal. Continue with themanual work process and degradation of data quality. Currently, SC&M uses 2D designs with no Metadata stored in the drawings that provide valuable information such as features, attributes and nointegration to other systems. To not move forward with a new technology solution means missedopportunity to optimize the current work process and enable visualization of future substation projectconceptualization; and missed opportunity to enhance SCE’s modular design and align with commondesign for our substations to facilitate the communication of a design to senior leadership, regulatoryagencies and customers.

Alternative No.2: New COTS Expanding Portfolio, new COTS considered would likely be Bentley SystemsMicro station. Considered a more costly and complex option as this would require procuring newlicenses, creating a new maintenance support model, and build all new interfaces to incorporate a newtool.

Alternative No. 3: Leverage Existing Portfolio and Expand Capabilities (Recommended): Currently haveAutodesk in house. Develop integration with Autodesk InfraWorks with Autodesk Inventor. Considered alower cost, lower complexity model. This option is recommend to utilize existing Autodesk products as asolution for this project. The combination of Autodesk InfraWorks, Autodesk Inventor, and AutoCADElectrical will help generate all the electrical wiring drawings to create the engineering designs. Thisproject will be leveraging the enterprise licenses. SCE will continue the use of Autodesk design productsand functionalities to align with the existing tools currently in use including AutoCAD, AUD and Map 3D.

154



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2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

0

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0

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1,000



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,000


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Electronic WO Package Automation (e-WOP)

See Testimony.

See Testimony.

Electronic WO Package Automation (e-WOP

156



INVESTMENT MEMO

(0 of 3)


Electronic Work OrderPackage (EWOP)

157



INVESTMENT MEMO

(1 of 3)


Electronic Work Order Package (EWOP)B. Initiative Description

Electronic Work Order Package (EWOP) project will utilize a work management, a document managementsystem, and work flow allowing users to store, access, and update Capital Related Order (CRO) documentselectronically, utilizing new and existing systems. Phase 1 will move paper work order jackets to scannedimages stored in EDMRM and accessed through SAP to better track documents and reduce hold times. Phase 2will move work order jackets from scanned images to electronic formats from their source applications enablingreal or near real time status.C. Business Strategic Alignment

The EWOP project is in direct support of two OpX initiatives;Work Order Documentation RedesignT&D Work Order Management


EWOP will be delivered in two phases. Phase 1, delivered in 2015, reduced work order hold times byproviding a method to quickly recognize and reproduce missing work order jacket forms.Benefits included:Reducing the average number of work orders held in FAO with “Missing Requirements” status, indicating keydocumentation required to close the work order is missing or incomplete, by 50% from 1300 to 650 annuallyor lessReduce the average hold time of orders in the “Missing Requirements” category from 82 days to less than 40days thereby reducing closing times from an average of 3 months to 1.5 months thereby acceleratingunitization into account 101 and decreasing the risk of AFUDC ThrowbacksReduce the average monthly value of held orders (impact to be verified)Reduce annual cost associated with finding, copying, reproducing, missing work order jacket forms by anestimated to be as much as $300,000 per districtReduce annual vendor, scoping, and permitting costs associated with Structure Inventory Assessments by asmuch as 30% or 2 3 million per year. (Realization of benefits are in flight as new process matures)Phase 2 is expected to further accelerate work order unitization process and reduce costs associated withmissing forms. Extent of benefits from Phase 2 requires further analysis, however benefits will be gatheredaround the following areas:Reduce the time required to scan and save Work Order imagesReduce the costs associated with forms ordering, shipping, storingReduce risks associated with manual handling of boxed paperReducing the number of work order paper copies required to be held in district.Reduce the transport costs associated with offsite storageFurther improve our ability to track and manage WO information or details.

158



INVESTMENT MEMO

(2 of 3)


EWOP Phase 1 – Document Repository: The OU will have the capability to scan the WO Jacket throughoutits lifecycle to ensure completeness from beginning to end. Documents will be scanned into an electronicformat and accessible by various groups in SAP at the work order. Phase 1 includes

o Develop design folder structure in eDMRMo Design taxonomy and meta data as foundation for storage, scanning methodology, and Phase 2

integrated designo Develop SAP Business Work Space (BWS) functionality to intake scanned forms and load into

appropriate eDMRM folder(s)o BWS will allow existing documents to be stored electronically and linked to SAP Work Orders and

FLOCs providing a centralized searchable storage locationo Provide high speed scanners to quickly scan and store large work order jacket forms

EWOP Phase 2 – Electronic Formso Coordinate document consolidation and convert existing documents into a standardized file format;o Design electronic storage process to utilize eDMRM folder structure created in phase 1;o Existing and new systems will produce electronic documents to support the CRO work flow;o System interfaces will transfer documents according to designated work flows;o Key user groups will receive and provide electronic updates to documents;o Systems will be automatically updated based on user updates;o Leverage a fully functioning Document Management System (eDMRM);o CMS integration with Edison contractors; ando CMS enhancements to support a fully electronic CRO work flow.

Organizational – None

Processo EWOP Phase 1 was a foundational project to establish document repository and taxonomy to house

end state electronic Work Order Forms. Phase 01 provided immediate relief to the costly use ofcopying paper forms by allowing current forms to be scanned and stored in EDMRM through SAP’sBusiness Work Space (BWS) functionality. BWS will allow existing documents to be storedelectronically and linked to SAP Work Orders and FLOCs providing a centralized searchable storagelocation. Phase 01 will provide scan and store functionality with immediate benefits to bettermanage work order packages, structure designs, and right of way documents. The scan and storecapabilities included in phase 01 will improve the work order closure process by reducing workorder hold times and provide immediate cost reducing benefits by reducing SCE and contractor timespent tracking paper forms in the Work Management, Technical Planning and Land Management.

o EWOP Phase 2 – Electronic Forms: Planners will trigger electronic documents which willautomatically attach to an Electric Distribution Service Request (EDSR) work order. Thesedocuments may be read only or require updates by field personnel. Once field work is completeand field personnel update the documents using existing field tools, transmission of those updatesto back office systems should occur in near real time. In addition, by virtue of digitizing CRO relateddata field and utilizing work flow management, some CRO related documents may no longer berequired to support the work flow. Data would be passed and updated electronically.

o EWOP designed to support a critical process improvement needed under the Work OrderDocumentation Redesign OpEx initiatives

159



INVESTMENT MEMO

(3 of 3)


Phase 1: Ability for Districts to scan and store Work Order Jacket forms prior to and throughout theconstruction process to quickly identify and correct or replace missing documentation after workcompletionAbility for Technical Planning to scan and store Structure Inventory prior to and after work completion toavoid future vendor costsAbility for Land Management to scan Rights documents

Phase 2’s technology must achieve the ability to reduce the need to initiate work on a paper form.Must reduce the need to manually document information on paper forms, when the requiredinformation can be gathered and utilized electronically.Must enable work to flow to various participants in the work order process via electronic access, withoutrequiring information to be manually documented on paper to continue the workflow.Data must be stored for future access and reference to the specific work order that invoked the work.Needs to ensure customer, billing, asset, and location information are updated electronically accordingto the life cycle of the work order.

G. Proposed Options

Option 1 is to leverage existing SCE technology including SAP and EDRMR for Phase 1 and expand toinclude Design Manager, Consolidated Mobile Solution, and other applications in Phase 2Option2 would include an independent application to integrate with existing SCE technologyOption 3 Do Nothing

160



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5. CLOSE DATE: 12/1/2016


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0

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9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

630


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Fast Response Energy Storage

See Testimony.

See Testimony.

Fast Response Energy Storage

162



INVESTMENT MEMO

(0 of 2)


Fast Response EnergyStorage

163



(1 of 2)

I. Business Initiative DescriptionA. Initiative NameFast Response Energy StorageB. Initiative DescriptionIn October 2013, the CPUC adopted an energy storage procurement framework and established an energy storagetarget for utility companies including SCE. The decision requires SCE to procure energy storage by 2020, withinstallations required no later than the end of 2024. The drivers for this initiative to be implemented by June 2016are as follows

1. The Fast Response deployment will provide basic functionalities towards the long term goal to complywith the CPUC Energy Storage Mandate

2. This deployment will provide an opportunity to use energy storage to mitigate distribution circuit impactsbefore start of the 2016 Distribution Planning cycle.

This first wave deployment includes procurement and installation of Energy Storage Systems between 5 – 10locations.

This project will deploy an energy storage solution that mitigates short term circuit impacts due to variable loadsand distributed energy resources (DERs). The following are the high level requirements:

1. Providing Network Connectivity to monitor the Energy Storage System via EMS/DMS.2. Provide EMS/Display for Grid Operators to monitor the system.3. Providing remote access to the system for SCE personnel to monitor and to do routine maintenance.4. Provide data historian for data collection and archiving.5. Allow limited and controlled remote access to external party (vendor) for the purpose of maintenance,

troubleshooting and warranty. C. Business Capabilities MappedThe following Business Capabilities are mapped for this effort :

1. Load Flow Management2. Power/Load Forecasting Analytics3. Power Integration Analytics (Integration Capacity Analytics)4. Device Management5. Asset Management

D. Desired Business Outcomes

Proactively integrate and manage Energy Storage Systems into electric grid operations toenhance grid reliability by implementing network infrastructure and leveraging SCE’sDistribution management system to operate the Energy Storage System.Position SCE to adapt and thrive as the utility industry changes through the use of connected,advanced technologies that will enable System Operators to determine whether the EnergyStorage System is acting as a load or a generation asset on the grid.Meet energy policy objectives while growing customer and shareholder value by increasingdistribution network capabilities through capital investments that align Energy Storage owners’economic interests with reliability interests in a framework that is fair to all SCE stakeholders

164



(2 of 2)

E. Business Priorities & ConcernsThese are key priorities and concerns

Deploy an energy storage solution that mitigates short term circuit impacts due to variable loads anddistributed energy resources (DER’s)The desired outcome is that service reliability is maintained and that this is a cost effective mitigationstrategy.Deploy 5 – 10 systems on distribution circuits by June 1st, 2016 (before start of the 2016 DistributionPlanning cycle)The Energy storage solution should monitor and respond to circuit conditions, obey pre definedschedules and charge/discharge thresholds.

F. Business Strategic AlignmentAs renewable energy sources (Solar, Wind etc.) are finding higher penetration in the customer segments, SCEneeds to be prepared to have the electric grid respond to the sudden and frequent changes in distributedgeneration from these renewable sources. These are some long term alignment strategies

Fully integrated with SCE vision of the grid of the futureControl architecture and software application based on the Integrated Grid Project (IGP)Aligned with the current Grid Modernization effortFirst wave of Energy Storage deployment provides basic functionalities towards the long termgoal to comply with the Energy Storage Mandate

G. Identified Options There were three different options being explored:

Option 1

Implement the architecture currently being designed for IGP project. This architecture will not readyon time to deploy the Energy Storage system by June 2016.

Option 2 (Recommended)Integrate with existing IT infrastructure. This option leverages existing system infrastructure and willenable SCE to meet the proposed timeline.

Option 3Leverage System architecture that was implemented on the DESI 1 project. This is a pilot projectthat leverages a private Verizon Network and is not integrated with EMS/DMS thus providing nocapability for Grid Operations to monitor the Energy Storage System

165



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Year1,200

330

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8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,530


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Transient Devices (HW for TSFT)

The following Level 2 Business Capabilities are mapped for this effort : 1. Enterprise Asset Management – Asset Planning – Engineering Drawing 2. Compliance Management – Compliance Assurance – Regulation Management

T&D’s current transient cyber assets (test technician end of life laptops E6430) that connect to BESCyber Assets are not positioned to meet the upcoming NERC CIP-010-2 R4 standards. This can potentially create a risk to the reliability of the BES and a reportable noncompliance of the NERC CIP Reliability Standards. To meet NERC CIP compliance, SC&M Test Technicians require a transient device to be used as Test Only Device (TOD) and training in the use of the device prior to performing work on BES Cyber Assets at NERC Impacted Facilities.

Transient Devices (HW for TSFT)

167



INVESTMENT MEMO

(0 of 3)


Transient Device

168



(1 of 3)SCE and Accenture Confidential

I. Business Initiative DescriptionA. Initiative NameTransient Device – Secondary DeviceB. Initiative DescriptionOn July 1, 2016 NERC V5 CIP 007 6 R3.1 will be in effect imposing stringent requirements around MaliciousCode Prevention on BES (Bulk Electric System) Cyber Systems. This will bring into scope approximately 50 T&DNERC facilities and around 3,000 T&D managed Cyber Assets consisting mostly of protection relays.

On April 1, 2017 NERC CIP 010 2 R4 will be in effect imposing additional standards on transient cyber assets andremovable media as defined below:

Transient Cyber Asset:A Cyber Asset that (i) is capable of transmitting or transferring executable code, (ii) is notincluded in a BES Cyber System, (iii) is not a Protected Cyber Asset (PCA), and (iv) isdirectly connected (e.g., using Ethernet, serial, Universal Serial Bus, or wireless, includingnear field or Bluetooth communication) for 30 consecutive calendar days or less to a BESCyber Asset, a network within an ESP, or a PCA. Examples include, but are not limited to,Cyber Assets used for data transfer, vulnerability assessment, maintenance, or troubleshootingpurposes.

Removable Media:Storage media that (i) are not Cyber Assets, (ii) are capable of transferring executablecode, (iii) can be used to store, copy, move, or access data, and (iv) are directly connectedfor 30 consecutive calendar days or less to a BES Cyber Asset, a network within an ESP, ora Protected Cyber Asset. Examples include, but are not limited to, floppy disks, compactdisks, USB flash drives, external hard drives, and other flash memory cards/drives thatcontain nonvolatile memory.

To meet NERC CIP compliance, SCE’s approach is to provide SC&M Test Technicians a secondary device to beused as Test Only Device (TOD). Technicians will receive training in the use of the device prior to performingwork on BES Cyber Assets at NERC Impacted Facilities. These devices will be used during their daily jobresponsibilities of testing and maintaining substation assets.

T&D’s current transient cyber assets, Test Technician’s TOD, while recently deployed, are over three years oldand have reached end of life. These devices that connect to BES Cyber Assets are not positioned to meet theupcoming NERC CIP 010 2 R4 and pose an operation risk if not replaced. This can potentially create a risk to thereliability of the BES and a reportable noncompliance of the NERC CIP Reliability Standards.C. Business Strategic AlignmentThe following Level 2 Business Capabilities are mapped for this effort :

1. Enterprise Asset Management – Asset Planning – Engineering Drawing2. Compliance Management – Compliance Assurance – Regulation Management

The Transient Device would assist in achieving two business goals:Compliance:

Be compliant with no significant non compliance event.Be in compliance of the following CIP Reliability Standards:

169



INVESTMENT MEMO

(2 of 3)

While these are new compliance standards, non compliant events of a similar standards have resulted inpenalties ranging from 250k – 325K.

CIP 010 2 R4 Transient Cyber Asset Malicious Code April 1, 2017

CIP 010 2 Attachment 1 Section 1: Transient Cyber AssetManagement, Transient Cyber Asset Authorization,Software Vulnerability Mitigation, Introduction of MaliciousCode Mitigation, Unauthorized User Mitigation

April 1, 2017

CIP 010 2 Attachment 1 Section 3 : Removable MediaAuthorization, Malicious Code Mitigation April 1, 2017

Operational Excellence: ReliabilityProtecting our critical infrastructure with:

o No significant intrusion affecting critical infrastructure.o No malicious code introduction comprising critical infrastructure.

D. Anticipated Business Outcomes & BenefitsThe current short term solution utilizing existing Dell Laptops ensured compliance with mandated date of July1, 2016. As these laptops are over three years old, they need to be replaced in order to enable a long termsolution for operations and need to be deployed by mid Q1 2107 to ensure compliance with the April 1,2017 date and the reliability of our BES by mitigating the following risks;

Unauthorized access to BES Cyber System via Electronic Access Point by Transient DeviceExposure to Malicious Code on BES Cyber System/Assets by Transient DeviceUnauthorized users access to Transient DeviceDetection and prevention of malicious code propagation onto BES Cyber Systems

E. Business Impact AssessmentThe scope of this effort will impact nearly 200 users in the T&D Substation Construction & Maintenance (SC&M)Organization and IT Organization.

Test TechniciansTest SupervisorsTS&S (Technical Support & Strategy) Technical SpecialistTelecommPower Automation

The impacted users are required to utilized the transient devices to perform all work activities on over 3,000T&D managed BES Cyber Assets or associated Protected Cyber Assets (PCA):

InspectionsMaintenanceInstallationsRemovalsModifications

170



INVESTMENT MEMO

(3 of 3)

F. Technology/Automation RationaleSCE’s approach to ensure compliance is to deploy a device with primary and secondary technologicalcontrols as well as process and reporting controls. The device will be hardened with the followingattributes and policies set to deter, detect or prevent malicious code

All wireless is disabledAll Bluetooth is disabledAll USB ports are disabled for unauthorized mass storage devicesSet accounts for individual usersSet password policy per IT Cyber Security StandardAll non essential services are disabledSession logging enabled

o User/ Device informationo CRS (Clean Room Script) script execution timestampo Last connection time to a BCA,o Last connection to Admin network,o Anti virus/malware scan success/fail.

Email or internet capabilities are disabled.Only applications deemed necessary for test technician work process are installed.Device must never act as an Electronic Access Point (EAP) when connected to a BES Cyber Asset.Only one Ethernet connection is available on the device.Device can be connected to the SCE Admin network at any SCE location.Removal of Device before Clean Room Script is complete will make the Transient DeviceinoperableDevice is disabled and locked if detection of malware, virus or failure in cleaningLogs centrally stored to be analyzed by T&D personnelUsers can download and upload data and test results to appropriate systems (PSMP, TSFT, etc.)

G. Proposed OptionsThere are 3 options under considerations to fulfill the need for a Transient Device:

Option 1: Semi rugged Dell Laptops as secondary device with all required Test Technicianapplications and hardened to meet NERC CIP V5 and NERC CIP 010 2 R4.

Option 2: DUC (Doble Universal Controller) test data controller with all necessary Test Technicianapplications, hardened to NERC CIP standards ( CIP V5, CIP 010 2 R4), training and ongoing 24x7support

Option 3: Deploy a shared device(s) at the approximately 50 affected locations.

171



2016

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2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

0

0

1,000

SCE $

1,000



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,000


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

High-Z Impedance Fault Detection

See Testimony.

See Testimony.

High-Z Impedance Fault Detection

173



INVESTMENT MEMO

(0 of 2)


High Impedance FaultDetection Project

174



(1 of 2)


High Impedance Fault Detection ProjectB. Initiative Description

T&D is actively evaluating and piloting multiple high impedance fault detection technologies. Work in this spacebegan in June 2014, and is expected to conclude in December 2017.

One potential solution option is based on Spread Spectrum Time Domain Reflectometry (SSTDR) techniques.The SSTDR High Impedance Detector Project involves the development of an anomaly detection system. Thedetection system will have the ability to identify anomaly (high) impedances on electrical distribution lines andtheir corresponding location. In addition to refining the SSTDR techniques, this project includes thedevelopment of supporting subsystems and algorithms to bring a fully functional, stand alone, and fielddeployable detector to production.

By the end of 2017, T&D will be able to finalize their technology solution decision and proceed with systemwide implementation as a capital project.C. Anticipated Business Outcomes & Benefits

The system will provide:Reflection sequences of the circuit when it does not have any anomaly (high) impedancecondition and correlate that to a GIS map of the circuitRegularly send signals down the line and compare these reflections to the reflection map to lookfor anomalies

o Identification of a foreign object (e.g. tree branch, or Mylar balloon) contacting theconductor.

o Detection of failing conductor splices.o Detection of failing equipment.o Identification of a blown or failing primary fuse.o Detection of un authorized electrical tap.o Verification of conductor lengths and sizes.

DMS State Estimator future DER Integration improvements

D. Business Impact Assessment

Usability: LOW – The users will not be impacted by the change. The data needed will provide softwarealgorithms needed for the engineering departmentApplication: LOW The application will be low impact

175



(2 of 2)

E. Technology/Automation Rationale

To support the SSTDR technology, additional subsystems are required for pre and post data processing. Thedetector system utilizes SCE’s existing Geographical Information System (GIS) database to retrieve circuittopology and device information. The system’s Preparation Module (pre operation) converts SCE’s GIS data intoa workable data structure, and a predictive SSTDR waveform, used by the Operation Module for signalcorrelation.

The Operation Module sends and receives signals; matching the received reflections to a known “good”impedance model (established during system initialization); eliminates known impedance mismatches; and, ifpresent, identifies the existence of impedance anomalies. Upon detection of an anomaly, the Reporting Moduleis responsible for identifying the circuit branch containing the anomaly; identifying the upstream (last knowngood point) and downstream devices containing the anomaly; and, calculating the distance between theanomaly and the upstream device.

The high impedance detector leverages SCE’s existing management systems (e.g. DMS or OMS) to provide GridOperations with a visual feedback of detected anomalies; and, to receive notifications of circuit topologychanges. Upon the completion of the detector’s process flow, when an anomaly is detected, the system willsend the anomaly’s location information generated by the Reporting Module to SCE’s management system(s) viaSupervisory Control and Data Acquisition (SCADA) communication paths. The expected result is that thedetector system will be able to identify high impedance fault within .02% accuracy and will identify the distanceof the fault to the nearest equipment or pole.

F. Proposed Options

1. Equipment sensing techniques using voltage and current monitoring.

2. Spread Spectrum Time Domain Reflectometry (SSTDR) technology

a. Commonly found in the Telecommunications and Aerospace industries, Spread SpectrumTime Domain Reflectometry (SSTDR) technology is typically used to find discontinuity incommunication and control systems lines. For this demonstration project, the detector willintroduce a low power SSTDR signal operating at a frequency between 2 MHz – 40 MHz ontoan energized electrical distribution conductor. The signal will propagate through thedistribution system creating signal reflections back to the origin at points where animpedance mismatch exists. Ultimately, the detector’s hardware will process thereflections, using the signal’s elapsed time to calculate the traveled distance, and type ofimpedance mismatch.

176



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Pin #: 3896


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5. CLOSE DATE: 12/1/2019


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0

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8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Secure DNP Ver5 Support for EMS

See Testimony.

See Testimony.

Secure DNP Ver5 Support for EMS

178



INVESTMENT MEMO

(0 of 1)


Secure DNP Ver5 Supportfor EMS

179



(1 of 1)


Secure DNP Ver5 Support for EMSB. Initiative Description

Secure DNP ver5 provides application level security for SCADA traffic between the Energy Management System(EMS) and substation assets. Currently SCE's compliance for EMS SACDA traffic relies on the "Serial Exemption"loophole of NERC. It is widely expected that NERC will fix this exemption in the next version of their standards.Long term, though SCE plans on implementing the Common Substation Platform (CSP) to provide security forSCADA traffic, there are several RTU only substation’s that would require this capability.

This project is in support of the NERC CIP Standard applicable to High and Medium Impact Bulk ElectricSystem (“BES”) Cyber Systems.


o Operations Productivityo Use of Grid Datao Grid Infrastructureo IT Portfolio Optimization


Implementation of Secure DNP will enable to secure SCADA traffic as we migrate to an IP basedcommunication between substations and the control center.The BID will be in collaboration with Cyber Security to ensure this project is in compliance.

E. Proposed Options

1. Enable Secure DNP2. Continue with current Serial based communication.

180



2016

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0

500

1,000

1,500

2,000

2,500



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2017


Year0

2,000

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Grid Management Dashboards

See Testimony.

See Testimony.

Grid Management Dashboards

182



INVESTMENT MEMO

(0 of 2)


Grid Ops ManagementDashboard & Reporting

Phase 3

183



(1 of 2)


Grid Ops Management Dashboard & Reporting Phase 3B. Initiative Description

Phase 3 of the Grid Ops Management Reporting / Dashboard requirements will provide Grid Ops with theautomation and integration of key data elements for reporting and planning purposes. To implement theserequirements, data from various sources needs to be integrated in a single data warehouse platform. Primarily,there are needs for integrating OMS (Outage Management system) data with data from Telogis, GIS, SAP, ORL,and CMS. One of the key objectives of the project is to reduce the considerable manual effort for Grid Ops toproduce these reports on a frequent and timely basis.

The Grid Ops Phase 3 Reporting and Analytics requirements can be broadly categorized as below:

Resource Utilization view – To visualize the capacity utilization of resources in each sector along withthe work, to enable better resource planningEnd to end outage view – To visualize and measure trouble men and crew effectiveness by breakingdown trouble men dispatching, working and traveling times for outagesWork Management Reporting – Reporting and visualization to monitor planned Grid Ops work. This iscurrently being maintained in the SORL and ORL applicationsSector, Region and Substation Metrics – Automated reporting of metrics for Safety, compliancetrainings, overtime pay and financial metrics(capital versus O&M) by sector, region and substationsIntegrated work plan for MPO projects by sector– This is currently being done manually in the ScheduleCost Management(SCMT) tool

The earlier phases of Grid Ops Management reporting, Phase 1 and 2 are already implemented or in progress:Phase 1: Display Existing Reports (Manu matic dashboard) in Grid Ops Control Rooms & PIV3 monitor –ImplementedPhase 2 – Create new BOBJ dashboard using OMS data to replace the current iDashboard – In progress


Having the management reporting and visualization will help to enable long term efficiency through automationof manual work, and improved outage monitoring and management

Aligning the Grid Ops analytics needs with the SCE IT EBI (Enterprise Business Intelligence) framework,whose principles include:

Improve the accuracy, integrity, accessibility and security of information assetsEnsure current, complete and consistent information to enable fact based business decisionsIdentify information which improves operational efficiency, promotes transparency and enablesbusiness insight

184



INVESTMENT MEMO

(2 of 2)


Having the Grid Ops Management Reports automated and available will help T&D Grid Ops achieve:

Operational effectiveness Better decision making during emergency situations to enable fasterresponse timeResource planning – Moving resources from an area with additional resources to area whereresources are needed. Also the day to day monitoring and of resource allocation and resourceeffectiveness.Management strategies – To mitigate high level emergencies situation by being able to visualize andmonitor overall capacity utilization in each SCE sectorSingle integrated platform for OMS and related systems’ data – Will enable ease ofreporting/visualization and self service for Grid Ops businessEnd to End view of data for business These reports will provide metrics and visibility for all the workin the system as well as resource availability and how the resources are performing.


Since the requirements are around reporting and visualization and the reports are expected to use a datawarehousing platform, this implementation of this project will have a relatively low impact to day to dayoperational activities that Grid Ops users carry out.The users will likely need to be trained to use the new reporting tools to be able view the reports and beable to perform self service reporting using the data warehouse.


T&D Grid Ops currently performs a significant amount of manual work to meet their reporting and analyticsneeds, pulling in data from different systems and compiling it manually.There is a need to have a single platform which can integrate data from outage management and associatedsystems and make it available for reporting.This outage data warehouse will provide the foundational capability for future analytics needs within GridOps.IT will be able to better manage an integrated data warehouse using the proposed SCE Enterprise Analyticsplatform.

G. Proposed Options

Option 1: Use the OMS Oracle Exadata environment in combination with the SAP Business Objectsenvironment to enable these reporting and visualization needs.

Option 2 [RECOMMENDED]: Create an outage data warehouse on the new Enterprise AnalyticsHANA/Hadoop platform. Integrate related data from other applications with the OMS data, and make itavailable for reporting using SCE Enterprise reporting tools, such as Business Objects.

185



2016

2017

2018

2019

2020

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0

200

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year0

0

1,000

1,000

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0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

PSMP 2.0

See Testimony.

See Testimony.

PSMP 2.0

187



INVESTMENT MEMO

(0 of 3)


PSMP 2.0 Apparatus

188



(1 of 3)


PSMP 2.0 (Apparatus)B. Initiative Description

The PSMP (Protection System Maintenance Program) program for the maintenance of all Protection System, asrequired by NERC PRC 005 2, would need to incorporate Distribution Apparatus users and new asset type aspart of Grid Modernization (new assets expected to be mostly automatic re closers and remote interrupterswitches).

The current interfaces with PSMP solution (Doble Protection Suite and Protection Web), SAP and Aspen wouldbe modified to add the Apparatus users and asset type allowing use of test plans, capturing test results,documentation and reporting against those assets.C. Business Strategic Alignment

The following Level 1 Business Capabilities are mapped for this effort :1. Enterprise Asset Management – Asset Planning2. Compliance Management – Compliance Assurance – Regulation Management

The proposed solution would ensure reliability of our BES and mitigate the risk of non compliance torequirements of NERC PRC 005 2:

R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a Protection SystemMaintenance Program (PSMP) for its Protection Systems.

The PSMP shall:1.1. Identify which maintenance method (time based, performance based per PRC 005Attachment A, or a combination) is used to address each Protection System ComponentType. All batteries associated with the station dc supply Component Type of a ProtectionSystem shall be included in a time based program as described in Table 1 4 and Table 3.

1.2. Include the applicable monitored Component attributes applied to each Protection SystemComponent Type consistent with the maintenance intervals specified in Tables 1 1 through 1 5, Table 2,and Table 3 where monitoring is used to extend the maintenance intervals beyond those specified forunmonitored Protection System Components.

R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performance basedmaintenance intervals in its PSMP shall follow the procedure established in PRC 005 Attachment A to establishand maintain its performance based intervals.

R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes time basedmaintenance program(s) shall maintain its Protection System Components that are included within the timebased maintenance program in accordance with the minimum maintenance activities and maximummaintenance intervals prescribed.

189



INVESTMENT MEMO

(2 of 3)

R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes performance basedmaintenance program(s) in accordance with Requirement R2 shall implement and follow its PSMP for itsProtection System Components that are included within the performance based program(s).

R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate efforts to correctidentified Unresolved Maintenance Issues.D. Anticipated Business Outcomes & Benefits

The integration of Aspen, SAP, and PSMP solution systems with the Apparatus asset type will effectivelymanage the PSMP process from initiation to completion. This will ensure that Distribution Apparatus isprepared to be in compliance with NERC PRC 005 2.

PSMP 2.0 solution will ensure Distribution Apparatus will have available metrics to manage all BES and nonBES assets and produce the necessary documentation and traceability for auditing.


The solution set would impact the work management process for users in the T&D Apparatus Division:Distribution Apparatus ForemenDistribution Apparatus TechniciansTS&S (Technical Support & Strategy) Technical Specialist

The impacted users are required to utilized the solution set to perform all work activities on T&D managed BESCyber Assets or associated Protected Cyber Assets (PCA):

InspectionsMaintenanceInstallationsRemovalsModifications

190



INVESTMENT MEMO

(3 of 3)


• Improve accuracy, security, and ensure the entire process from initiation to completion can be viewed• Establish and/or verify that all required assets that need to be tested are contained in one of SCE’s asset

repositories.• Migrate existing Protest data to a solution set that supports PRC 005 2.• Application interface between Aspen, SAP, and Solution Set.• Results will be uploaded via the solution set, then specified data will be synced with SAP.• Verify the ability to proactively schedule all required testing within the required frequency of testing in order

to be in compliance.• Controlled centralized repository to place completed as left settings for NERC PRC 005 2 compliance audits;

retain all historical data for a minimum of 30 years.• Verify that a well documented maintenance program exists that performs all required testing of the

protection system components at the required intervals and frequencies specified in NERC and otherstandards.

• Establish and/or verify that in the case of failure of a test, corrective measures are initiated and tracked toreplace or repair the faulty components as needed.

• Establish the ability to generate reports to show that all required PSMP components are in compliance perthe required standards.

G. Proposed Options

The following options are under consideration for the solution set:• Option 1: Do nothing and continue use of legacy application, Protest. Does not support ETO initiative of

reducing footprint. Believe ProTest will not support all moving forward needs. Costs to modify and/orupgrade expected to be significant.

• Option 2: Pursue other 3rd party COTS solution with same functionalities as PSMP. Considered highest costand complexity option. Would require new licensing, new maintenance agreements, configuration ofapplications to integrate and new interfaces. This option not in alignment with ETO direction of reducingtechnology footprint.

• Option 3: Modify PSMP and interface with SAP, Aspen to accommodate Apparatus users and asset type.

Considered optimal approach as PSMP is an industry leader. Also, PSMP is already an in houseapplication.

191



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Power Supply Software Projects

193







2016 2017 2018 2019 2020

12,225 12,440 14,200 8,000 5,000 51,8651 Joanne Tran

SCE-04, Vol. 02 12,225 12,440 14,200 8,000 5,000 51,8651.1

2,185 0 0 0 0 2,185CIT-00-SD-PM-0001481.1.1

0 0 500 1,000 1,000 2,500CIT-00-DM-DM-0000791.1.2

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0 3,000 3,500 1,000 0 7,500CIT-00-DM-DM-0000421.1.4

0 0 1,200 0 0 1,200CIT-00-DM-DM-0000281.1.5

400 1,570 600 0 0 2,570CIT-00-SD-PM-0002301.1.6

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2,850 0 0 0 0 2,850CIT-00-SD-PM-0001121.1.12

194







2016 2017 2018 2019 2020

1,000 4,000 4,000 3,000 3,500 15,5001 Timothy Condit

SCE-04, Vol. 02 1,000 4,000 4,000 3,000 3,500 15,5001.1

0 1,000 2,000 1,500 1,000 5,500CIT-00-SD-PM-0002281.1.1

1,000 3,000 2,000 1,500 2,500 10,000CIT-00-SD-PM-0002271.1.2

195



Generation Automation Upgrade & Control Systems

Refresh

196



0

500

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1,500

2,000

2,500

3,000

3,500

1. WITNESS: Timothy Condit


Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: Specific Blanket


Year1,000

3,000

2,000

1,500

SCE $

2,500



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

10,000


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

The control systems at the Hydro facilities have historically been sourced from multiple vendors andlack of equipment standardization has caused problems with inter-operability between the different Hydro operating regions and maintainability as components approach the end of their life-cycle. SCE’s direction for future plant control systems is the standardization of equipment and software from a single vendor; part of which has already been completed.

This project continues the Automation standardization efforts which includes implementation of enhanced business capabilities and replacement of existing automation systems as they become obsolete. The automation project will deploy advanced data archiving, monitoring, reporting, and remote diagnostics with secure, NERC Critical Infrastructure Protection (CIP) compliant software and servers for viewing of Ovation screens, data trending and reporting on the administration network. This project is driven by three business needs: (1) standardization of equipment, (2) replacement of aged equipment in use, and (3) addition of new equipment to those areas not automated which will allow for remote monitoring and control of Hydro facilities.

Performing the Automation upgrade will add additional business capabilities to SCE’s Hydro facilities, which include: (1) Enhancing the responsiveness of the Big Creek plant to CAISO control signals by moving existing custom-developed code into the control systems. This will enable Big Creek to offer more capacity into the CAISO regulation market, which will benefit the integration of renewable generation into SCE’s grid, (2) Upgrading the control systems at Big Creek to avoid generator rough loading zones (i.e. output ranges where the mechanical construction of the generating unit causes excessive vibration) and (3) Providing a common test environment and enabling the interoperability of the control systems in the different hydro operating regions to facilitate data exchange and preparedness for enhanced disaster recovery capabilities between the regions. Upgrades to the existing Automation system will enable Hydro to meet mandates from

Generation Automation Upgrade & Control Systems Refresh

197



FERC and other governmental entities to monitor water release capabilities and also maintain dam surveillance. The overall benefit will be increased water control, system reliability, and regulatory compliance. The Dam sites are important because they are points of mandated FERC Instream Releases critical to FERC license compliance.

198



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199



Dam Monitoring and Surveillance

200



0

500

1,000

1,500

2,000

2,500

1. WITNESS: Timothy Condit


Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

1,000

2,000

1,500

SCE $

1,000



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

5,500


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Hydro operates and maintains 22 dams considered by FERC to be large and/or high-hazard dams, and many are in mountainous terrain at elevations over 7,000 feet above sea level. These locations are often remote and difficult places to work. SCE’s dams are under FERC jurisdiction and FERC has an ongoing effort to increase the safety of dams across the US by improving the monitoring of the dams and by improving the dams’ ability to withstand natural disasters, including seismic events (earthquakes) and severe storms. Several of our dams, especially in the Eastern Hydro region, are both high-risk and time-sensitive. Time-sensitive means there is not enough time to notify emergency services in case of a dam failure with sufficient lead time to evacuate downstream towns. SCE monitors its dams through remote sensors that measure water levels and water flows. When a sensor returns an unexpected or abnormal reading (which frequently occurs), an operator must travel to the dam to perform a visual inspect. Often the travel time required can exceed two hours, which in an emergency condition is not adequate.

This project captures the IT components of the Dam Monitoring and Surveillance (e.g. cameras andcommunications equipment) Project. The project scope at each dam will be similar and includes thepurchase and installation of cameras and communications infrastructure. Cameras require the ability to capture periodic still images (e.g. 5 frames per minute) and remotely capture a still image on demand (sometimes infrared vision will be required to capture images at night or in snowy conditions. Cameras and communications equipment must remain operable in remote areas and under harsh weather conditions. In addition, not all dams have electric power and necessary communications infrastructure so this will be provided via solar and/or wind generation and satellite and/or microwave communications. Installation will occur according to the risk priority assigned to each dam and some installations may span multiple years (i.e., project may commence in the fall ofthe first year and conclude in the second).

SCE’s dams are under FERC jurisdiction and FERC has an ongoing effort to increase the safety of

Dam Monitoring and Surveillance

201



dams across the US through improved monitoring and improvements to a dams’ ability to withstand natural disasters, including seismic events (earthquakes) and severe storms. The primary benefit for this project is improved response time to a pending or developing dam failure by adding visual surveillance capabilities to high-risk dams, and to remove the need to send operations personnel to perform visual inspections when abnormal sensor readings are received.

202



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203



CAISO Market Enhancements Program (IMEP)

204



0

50

100

150

200

250

1. WITNESS: Joanne Tran


Pin #: 7337


2. PROJECT DETAIL:






5. CLOSE DATE: 5/1/2016


Year200

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

200


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

IMEP CAISO Market Enhancements (2015)

See workpaper for details

See workpaper for details

IMEP CAISO Market Enhancements (2015)

205



3,6003,6503,7003,7503,8003,8503,9003,9504,0004,050



Pin #: 3896


2. PROJECT DETAIL:








Year3,750

4,000

4,000

4,000

SCE $

4,000



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

19,750


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

CAISO Market Enhancements (2016-2017)

The objective of the CAISO Market Enhancements 2016-2017 project is to enhance existing systems and processes to implement CAISO 2014-2017 market initiatives in order to meet SCE’s CAISO Scheduling Coordinator obligations. CAISO has several ongoing enhancement projects that are scheduled to be implemented during 2016-2017.

This project will allow SCE to be in compliance with CAISO MRTU market changes between 2016 through 2017.

CAISO Market Enhancements (2016-2017)

206



INVESTMENT MEMO

(0 of 3)


IMEP 2017 2020

207



(1 of 3)

I. Business Initiative DescriptionA. Initiative NameIMEP 2017 2020B. Initiative Description

IMEP 2017 2020 is the ISOMarket Enhancement Project from 2017 2020. IMEP 2017 2020will implementthe market changes required by CAISO during 2017 2020 timeframe. The objective of the IMEP 20172020 project is to enhance existing systems and processes to implement CAISO 2017 through 2020initiatives.

SCE is required to implement themarket design enhancements in order tomaintain regulatory complianceas part of our CAISO Scheduling Coordinator obligations. The California Independent System Operator(CAISO) is the entity that manages the California high voltage electricity grid. CAISO also operates variousmarkets for energy and ancillary services.

SCE is also required to bid all our generation into the CAISO markets and buy our entire load from theCAISO markets. SCE transacts in the CAISO market on a 24/7/365 basis. The CAISO process for marketenhancements starts with the policy change proposals and other proposed market enhancements. Theseproposals go through the CAISO market design process, in which SCE is a stakeholder. This processincludes the design of enhancements to the markets, including products and services provided by CAISO.

Once the CAISO board approves the policy change proposals, CAISO will finalize the external businessrequirements and the technical specifications for the market participants to implement the marketenhancement initiative. CAISO usually plans releases in spring, fall and independent releases.

Details on CAISO 2017 2020 initiatives listed in Section IV B.C. Business Strategic Alignment

The implementation of this CAISO market enhancement is to meet SCE’s CAISO Scheduling Coordinator’sobligations and maintain the regulatory compliance.The implementation of each of the market enhancement initiative is to meet CAISO’s tariff changes ornew tariff requirements.Continued ability to transact in the CAISO markets.Ability to comply with least cost dispatch.


SCE is required to bid all our generation into the CAISO markets and buy our entire load from the CAISOmarkets. SCE transacts in the CAISO market on a 24/7/365 basis. The objective of the IMEP 2017 2020project is to enhance existing systems and processes to implement CAISO 2017 2020 initiatives. SCE isrequired to implement the market design enhancements in order to maintain regulatory compliance aspart of our CAISO Scheduling Coordinator obligations.

Compliance with CAISO tariff.Continued ability to transact in the CAISO markets.

208



INVESTMENT MEMO

(2 of 3)

The CAISO market enhancement initiatives address specific business requirements and theneeds. The scope of each market enhancement initiative has been approved by theparticipants, and the CAISO governing board.No quantifiable hard benefits.


The impacted systems include PCI, CDS/PDR, SettleCore, CYCG, CASIO Price tool and internally developedUser Developed Applications (UDA).ON a high level the IMEP 2017 2020 initiatives will impact following business capabilities:

Meter Data Management Meter Data ManagementPortfolio Planning and Analysis Demand and Price ForecastingPortfolio Planning and Analysis Portfolio Development and ValuationPortfolio Planning and Analysis Fundamental Modeling and analysisPortfolio Planning and Analysis Portfolio ReportingEnergy Procurement andManagement

Resource and Water Optimization

Energy Procurement andManagement

Energy Gas and Emission trading


Energy Operations

Contracts Management Contract Origination andManagement

Contracts Management SettlementsOperation Services Business Process ServicesOperation Services Information and Data ManagementOperation Services Power Supply Administration

Each of the market enhancements brings changes to one or more of the following business areas:• Modeling of generation resources• Forecasting and planning load and generation assets• Managing generation outages• Self scheduled and economic bids and loads submitted to CAISO• Prices and awards received from CAISO• Settlement statements and invoices received from CAISO• Allocation of the invoices received.

209



INVESTMENT MEMO

(3 of 3)


The expectation is that IMEP 2017 2020 will leverage the existing Power Procurement technology andapplications which automate the following business functions:

Modeling of generation resourcesForecasting and planning load and generation assetsManaging generation outagesSelf scheduled and economic bids and loads submitted to CAISOPrices and awards received from CAISOSettlement statements and invoices received from CAISO

G. Proposed Options

The proposed solution is to enhance the existing Power Procurement applications.

As long as SCE remains a CAISO participant we cannot wholesale and opt out of the CAISO tariff andoperating procedures.

210



2016

2017

2018

2019

2020

Tota

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211



Energy Planning Platform Upgrade (EPP)

212



0

500

1,000

1,500

2,000

2,500



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year0

0

2,000

2,000

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

4,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Energy Planning Platform (EPP) Upgrade

Enhance the Energy Planning Platform (EPP) system to add additional analytical capabilities to be able to better optimize SCE’s portfolio of assets. EPP enables a range of forecasts and optimizationroutines to be performed based on SCE’s portfolio of assets. In addition, the platform will be used to forecast energy supply needs in future years, and will also include analytical applications to support Power Supply’s competitive solicitations for power and natural gas

As SCE’s portfolio continues to change, so does its reporting requirements. With the Distribution Resources Plan, SCE is expected to add dispatchable distributed energy resources (DERs) to its portfolio. DERs may include energy storage, electrical vehicle integration, various demand response products, distributed generation and energy efficiency. DERs can be dispatched based onnodal prices and/or circuits level requirements where their primary role will be system reliability and their secondary role is providing market services. DERs may also communicate with one to increase system efficiency through voltage support.

Energy Planning Platform (EPP) Upgrade

213



INVESTMENT MEMO

(0 of 3)


Energy Planning PlatformUpgrade

214



(1 of 3)


Energy Planning Platform UpgradeB. Initiative Description

• The Energy Planning Platform (EPP) was developed by SCE’s Energy Planning group to supportportfolio analysis, regulatory reporting and provide advanced analytics for SCEs hedgingprogram

• This tool is used to:– Measure Time to Expiry Value at Risk (TEVaR) for use in the monthly CPUC risk reports– Measure risk impacts of incremental hedges (i.e. energy transactions made to control or

reduce risk) on SCE’s portfolio– Support the development of short term and long term hedging strategies– Measure Procurement Cost at Risk (PC@R) for use in Risk Management Committee

(RMC) approved long term hedging strategy– Inform forward hedging product decisions by calculating hedge effectiveness/hedge

cost– Calculate optimal portfolio based gas volumes when executing forward spark spread

hedges (e.g. selling power and buying gas)– Perform Request For Offer (RFO) and bi lateral power contract valuations– Perform long term risk and portfolio analysis for Long Term Procurement Plan (LTPP)

filings– Compile monthly and yearly Resource Adequacy and Supply Plan filings– Compile long term capacity position forecasts for RFOs and Procurement Review Group

(PRG) quarterly reporting and ad hoc data requests– Compile the annual and ad hoc Energy Resources Recovery Account (ERRA) forecasts

and perform variance analysis– Assess SCE’s procurement related collateral obligations under stress case conditions– Evaluate gas transportation bid offers using a monthly spread option pricing model

• The platform is hosted in the SCE IT environment and leverages IT’s data access controls andtesting and release protocols and has grown from a single risk reporting module to severalcomplex analytical modules

– Reduces the need for custom User Developed Applications (UDAs)– Utilizes centralized database and servers including disaster recovery provisions– Utilizes grid computing technology


As SCE’s portfolio continues to change, so does its reporting requirements. With the DistributionResources Plan, SCE is expected to add dispatchable distributed energy resources (DERs) to its portfolio.DERs may include energy storage, electrical vehicle integration, various demand response products,distributed generation and energy efficiency. DERs can be dispatched based on nodal prices and/orcircuits level requirements where their primary role will be system reliability and their secondary role isproviding market services. DERs may also communicate with one to increase system efficiency throughvoltage support.

215



INVESTMENT MEMO

(2 of 3)

The aggregation small CAISO connected DERs adds to the complexity of SCE portfolio. To accuratelycapture the position, monitor the market sensitive financial exposure and be able to value all of the newDER types, SCE requires a refresh of its analytic platform.Furthermore, SCE is also seeking to retire some of its older applications such as its position reportingplatform, EPIC. This project will reduce the number of applications in Portfolio Planning and Analysis(PPA). This will create a more robust data management process and will also reduce PPA’s ITmaintenance need.D. Anticipated Business Outcomes & Benefits

The application will support all of SCE’s power procurement activities, including Request for Offer (RFO)solicitations, procurement strategy decision and trading activities. Potential decommissioning EnergyProcurement Information Center (EPIC).E. Business Impact Assessment

Below are the following business capability that will be impacted by the project:

Portfolio Planning and Analysis Demand and Price ForecastingPortfolio Planning and Analysis Portfolio Development and ValuationPortfolio Planning and Analysis Fundamental Modeling and analysisPortfolio Planning and Analysis Portfolio ReportingEnergy Procurement andManagement

Resource and Water Optimization


Energy, Gas and Emission trading


Energy Operations

Contracts Management Contract Origination andManagement

Operation Services Business Process ServicesOperation Services Information and Data Management


The proposed project will enable and support following business functions:Assessing Portfolio RiskEvaluate Gas ProposalsEvaluate Energy ContractsManage Hedging Strategy and Valuation FrameworkManage Portfolio Development ModelsForecast Commodity PricesForecast VolatilityForecast Ancillary Services PricesCongestion Revenue Rights (CRR )Procurement and Analysis

216



INVESTMENT MEMO

(3 of 3)

G. Proposed Options

Alternative 1: Don’t pursue the project. This will not address any of the current issues.

Alternative 2 (recommended): Enhance the existing Power Procurement applications. The proposedsolution is to upgrade the existing Power Procurement application using the current SCE technology andstandards, including but not limited to Oracle Exadata, .NET and SAS.

217



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218



PCI Replacement

219



0500

1,0001,5002,0002,5003,0003,5004,000



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year0

3,000

3,500

1,000

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

7,500


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Power Cost Inc (PCI Replacement)

A key objective of this project is to avoid over-customization of the new tools. This will be challenging and will require determination and discipline from both IT and the business unit. However, we have full agreement from the business unit leadership on this approach. As part of theimplementation project we will conduct in-depth analysis/design workshops with the selected vendor(s) to review not just what needs to be done (the requirements), but also how the requirement will be implemented (e.g. screen or report layout). We have established a priority order of how requirements can be met: 1. Standard system functionality 2. Simple system configuration 3. Business process changes 4. Significant system configuration (will require justification and business unit principal manager approval) 5. Customization (will require significant justification and business unit director approval)

The current PCI system is used for a number of functions1 on the trade floor and is very expensive to maintain, has insufficient performance and consistent quality issues, and the vendor struggles to keep the system up to date with CAISO changes. An analysis in 2014 showed that other vendors can provide similar or better functionality at a lower cost. We plan to select one or more 3rd party vendors to replace the parts of PCI that cannot be covered by OpenLink Endur functionality.

Power Cost Inc (PCI Replacement)

220



INVESTMENT MEMO

(0 of 2)


PCI ReplacementInvestment Memo

221



(1 of 2)

I. Business Initiative Description

PCI Replacement

The current PCI system is used for a number of functions1 on the trade floor and is very expensive to maintain,has insufficient performance and consistent quality issues, and the vendor struggles to keep the system up todate with CAISO changes. An analysis in 2014 showed that other vendors can provide similar or betterfunctionality at a lower cost. We plan to select one or more 3rd party vendors to replace the parts of PCI thatcannot be covered by OpenLink Endur functionality.

SCE’s strategy for our generation resources is to maximize their market value by participating in the CAISOmarket.

Reduce operating costs (primarily IT operating costs related to system maintenance and upkeep).Reduce the number of spreadsheets and manual workarounds.Enhance responsiveness to changes in CAISO markets.Enable single data entry at power plants for both CAISO and NERC generation outage reportingrequirements.

Capabilities: Power Supply – Power Procurement – Energy Procurement & Management – EnergyOperations will be matured with enhanced automation and less need to rely on manual workarounds.Organizational: Power Supply – Energy Procurement & Management will be the main users of the system.Process:

o Perform Power Trading will be impacted by moving the deal capture from PCI to Endur.o Manage Day Ahead Operations will be impacted by replacing the existing PCI system.o Manage Real Time Operations will be impacted by replacing the existing PCI system.o These are all critical business processes and will require redundant systems with immediate failover

mechanisms.

1 PCI functionality covers optimization, generation outage management, CAISO communication (bidding andscheduling) and position management for the real time desk.

222



INVESTMENT MEMO

(2 of 2)

1. Utilize OpenLink Endur to replace existing PCI functionality where possible.2. Identify solutions to PCI functionality areas that Endur doesn’t cover. These include:

a. CAISO interface (bidding and scheduling)b. Generation outage managementc. Optimization and bid generation

The solutions identified may be on site software or hosted services.

Alternative 1: Do nothing. This will cause SCE to incur higher ongoing costs.Alternative 2 (recommended): Replace PCI with a 3rd party system to be selected.

223



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224



Power Procurement Market Systems Front-Office (FO)

Capabilities Strategic Assessment

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236



Energy Trading and Risk Management

237



0

500

1,000

1,500

2,000

2,500

3,000

3,500



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2018


Year0

3,000

2,400

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

5,400


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Energy Trading and Risk Management (ETRM)

The ETRM System Replacement project will replace the Sungard Entegrate ETRM system which was put in place in 2008 and is used by Power Supply to capture and process all conventional bilateral contracts as well as physical and financial power and gas transactions. SCE requires a fully integrated, end-to-end commodity trading system to support its current and future trading of physical and financial energy commodities and bilateral contracts. The system must include front, middle and back office capability. The system must automate the entire trade to payment process and limit manual intervention and processing. This will reduce operational risk, minimize settlementrisk for trade execution, and help control operational costs. The Sungard Entegrate system is being phased out over time by Sungard in favor of their new Aligne platform

The ETRM System Replacement project will replace the Sungard Entegrate ETRM system and will be able to handle conventinal bilateral contracts and energy commodity products without extensive use of spreadsheets.

Energy Trading and Risk Management (ETRM

238



INVESTMENT MEMO

(0 of 2)


Energy Trading & RiskManagement (ETRM)System Replacement

239



(1 of 2)


Entegrate Replacement


This project replaces the aging Sungard Entegrate Energy Trading and Risk Management (ETRM) system with theOpenLink Endur system, which we initially purchased for the CMP project, but intend to use as a commonplatform for all of Power Supply’s wholesale trades and contracts. Entegrate is aging and while it’s stillsupported by Sungard it’s not their strategic product and new functionality (such ad Dodd Frank reporting) isnot being added. In addition, Power Supply has had to develop numerous spreadsheet workarounds to addressfunctional shortcomings in Entegrate.

The PCI and Entegrate systems are closely linked in that energy deals are entered into PCI and then transferredto Entegrate via a system interface. Also, PCI needs Entegrate deal information for data submission to CAISO.


SCE’s strategy is to procure the majority of the power to our customers through bilateral contracts of varioustypes and durations. These contracts are currently managed in two separate systems: WES (to be replaced byEndur as part of the CMP project) for renewable power and Entegrate for conventional power and financialcontracts.


Reduced number of spreadsheets and manual workarounds to address Entegrate functionalshortcomings.Streamlined process for invoice payments (automated interface to SAP rather than today’s manualinterface).Enhanced controls (less manual copy/paste between Entegrate and spreadsheets).Decommission computing environments that are no longer needed.


Capabilities:o Power Supply – Power Procurement – Energy Procurement & Management – Energy Contract

Management and Energy, Gas and Emissions Trading will be matured with enhanced automationand less reliance on manual workarounds.

o Risk Operations will be matured with less reliance on spreadsheets and manual workarounds.o Power Procurement Accounting will be matured with less reliance on spreadsheets and manual

workarounds.Organizational: This project impacts four major groups of users:

o Power Supply – Energy Procurement and Managemento Power Supply – Settlement & Operations Serviceso Finance – Risk Management – Risk Operations

240



INVESTMENT MEMO

(2 of 2)

o Controllers – Accounting – Regulatory Accounting and Analysis – Power Procurement AccountingProcess

o Manage Contract On Boarding, Manage Contracts, Manage Contract Compliance, SupportRegulatory and Cross Functional Organizations and Manage Contract Termination will all beimpacted by moving from Entegrate to Endur.

o Obtain OK To Trade Approval, Perform Power Trading, Perform Beyond Day Ahead (Forward) PowerTrading, Transmission Trading, Gas Trading, Emissions Trading and Support Power, Gas & EmissionTrading Activities will all be impacted by moving from Entegrate to Endur.

o Perform Contract Compliance and Analysis and Manage Contract Settlements Operations will all beimpacted by moving from Entegrate to Endur.

o Risk Operations processes will be impacted by moving from Entegrate to Endur.o Power Procurement Accounting processes will be impacted by moving from Entegrate to Endur.


1. Replace Sungard Entegrate with OpenLink Endur.2. Utilize Endur to replace existing PCI functionality where possible.

G. Proposed Options

Alternative 1: Keep existing system. This is not a viable approach since Entegrate is obsolete.Alternative 2: Upgrade Entegrate to Sungard Aligne. This will require a new implementation withsimilar costs as the Endur implementation and will leave us with two systems that managerenewable and conventional contacts.Alternative 3: Replace with new COTS package to be selected. This will require purchasing a newsystem (including license fees for the new system) with implementation with similar costs as theEndur implementation. It will leave us with two systems that manage renewable and conventionalcontacts.Alternative 4 (recommended): Replace with OpenLink Endur.

241



2016

2017

2018

2019

2020

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242



Aggregated Demand Response (ADR)

243



0

500

1,000

1,500

2,000

2,500

3,000



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 3/1/2017


Year2,590

870

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

3,460


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Aggregated Demand Response - Phase 2

The Aggregated Demand Response (ADR) system will integrate retail DR programs into CAISO’s markets. The ADR system will be used to translate the retail resources (demand response programs) into wholesale biddable elements just like supply side resources as required by the (California Public Utility Commission (CPUC).

The CPUC has encouraged the growth of Price-Responsive DR in order to “enhance electric system reliability, reduce power purchase and protect the environment.” In D.05-11-009, the CPUC developed a strategy and initial programs to promote DR. In proceeding A.05-05-006, the CPUC adopted 2006-2008 programs and goals for DR for SCE and the other California energy IOUs.

Aggregated Demand Response - Phase 2

244



INVESTMENT MEMO

(0 of 2)


Aggregated DemandResponse Phase 2

245



(1 of 2)


Aggregated Demand Response Phase 2B. Initiative Description

The Aggregated Demand Response (ADR) system will integrate retail DR programs into CAISO’s markets. TheADR system will be used to translate the retail resources (demand response programs) into wholesale biddableelements just like supply side resources as required by the CPUC. As a part of CPUC Rule 24, also known asDirect Participation in Wholesale Markets, the CPUC expects the IOUs will integrate some of the DemandResponse (DR) programs into California Independent System Operator (CAISO’s) markets. Additionally, CAISOrequires SCE to provide demand forecast information into its market to mimic generation resources. PowerSupply will require analytical tools to operate in the CAISO market with aggregate demand response as adispatchable resource.

ADR aggregates retail demand response programs into wholesale resources that can be bid into the CAISOwholesale markets. The aggregation is based on location and the specific parameters of the various demandresponse programs, where an aggregated wholesale resource typically would consist of similar customerprograms within a specific geographic area. After the CAISO markets run the awards are downloaded fromCAISO and allocated to the retail demand response programs that make up the wholesale resource.

ADR (Phase 1 scope) was implemented in 2015. ADR Phase 1 performs the following functions for Priceresponsive Demand Response (PDR) and Reliability Demand Response Resources (RDRR):

1. Define PDR/RDRR – Determines how the Demand Response resources will be physically defined for thewholesale markets2.Manage PDR/RDRR Capacity/Availability – Manages the DR resources to account for changes3. Aggregate Data (Daily) – Gathers and uses the available meter data for assessing the performance of the DRresources as well as for forecasting9. Calculate Performance – Reviews the performance of each DR resource against an Award10. Perform Settlement Support – Calculates DR resource performance and submitting meter data it to CAISO

The ADR system will need additional functional enhancement (Phase 2) for the longer term demand responseprograms. Phase 2, which is included in this current funding request, will perform the following functions:

4. Forecast Performance – Develop the resource plan for each DR resource. The DR resource will contain bothprice points and capacity amounts (MW)5. Update PDR Bids – Send the DR resource availability/capability to downstream systems to prepare forbidding into the market6. Translate Awards to Retail Instructions – Determine how DR resource awards are translated to specificinstructions for a service account7.Monitor DR Performance – Review actual meter data to ensure the DR resource is meeting the Award.Advanced analytic capability will be required to perform this function.8. Send Adjusted Instructions – Send additional instructions to CSOU to curtail additional load if the DRresource is not meeting the Award

246



INVESTMENT MEMO

(2 of 2)

These additional capabilities will facilitate the full functioning and usage of demand response resources byaggregating the demand resource attributes and providing them to Day Ahead and Real Time trading asavailable generic resources for the next wholesale market opportunity including the next increment of the hour,the next day (for the day ahead market), next week, next month, etc. Additional functionality is also required toautomate some manual processes and address some of the complexities that the CAISO has introduced into itsmarket design in the area of resource registration, baseline calculation and limitations around the discretedispatch of resources.C. Business Capabilities Mapped

Power PortfolioManagement

Power Analytics


Power Dispatch


Power Planning (Supply and Demand)


Power Trading


Demand Forecast

D. Desired Business Outcomes

The CPUC has encouraged the growth of Price Responsive DR in order to “enhance electric system reliability,reduce power purchase and protect the environment.” In D.05 11 009, the CPUC developed a strategy andinitial programs to promote DR. In proceeding A.05 05 006, the CPUC adopted 2006 2008 programs and goalsfor DR for SCE and the other California energy IOUs.

CPUC required that SCE includes in its 2009 2011 DR application, its plan for integrating demand response intothe CAISO’s wholesale markets. SCE is preparing to integrate demand response resources as both ProxyDemand Resources (PDR) and Reliability Demand Response Resources (RDRR). PDR can be bid into Day Aheadand Real Time Energy and Ancillary Services markets, and RDRR can be bid into Real Time Energy as acontingent resource.

SCE currently has nearly 1,000 MWs that will be biddable into CAISO markets. It is not inconceivable to expectthat eventually all demand response resources, approximately 1,500MW, will be bid into CAISO markets usingprice and or contingent triggers. In the current DR OIR proceeding, additional functionality to accommodate thebifurcation of DR is being contemplated that will require managing components of the DR programs outside ofthe market.

IT developed ADR (Phase 1) solution to integrate demand response into the procurement process with thefollowing functionality: define PDR/RDRR, manage PDR/RDRR capability/availability, aggregate data – daily,forecast performance, calculate performance, and perform settlement support. The ADR Phase 1 does notsatisfy required functions for the full SCE DR program integration in 2016. ADR Phase 2 will complete therequired functions needed.

247



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Commodity Management Platform (CMP)

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5. CLOSE DATE: 6/1/2016


Year2,850

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SCE $

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9. JUSTIFICATION:

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SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

CMP (Renewable Contract Mgmt System Replacement)

The Renewable Contract Management System project seeks to install a new system to manage renewable power contracts and replace the Wholesale Energy System (WES).

WES will be unable to handle the volume and complexity of the new renewable contracts that are currently online and those that are expected to come online in the next five years in growing numbers.

Commodity Management Platform (CMP)

250



(1 of 4)

Commodity Management Platform (CMP)A. Project Overview

The project will install and configure the OpenLink Endur system to manage renewable power contracts.The new system will replace the current system called Wholesale Energy System (WES), as WES is basedon obsolete technology and will be unable to handle the volume and complexity of new renewableenergy contracts that are currently on line and are expected to come online in the next 5 years withincreasing complexity.The number of renewable energy contracts has been increasing as SCE continues to sign contracts toreach the 33% renewable portfolio standard. The new contracts are significantly more complex than theexisting contracts. Contracts that have already been signed are coming into production as the variousgeneration projects go live and will need to be managed as well.The new system will provide much needed automation of processes that have to be done manuallyusing spreadsheets today. Since the WES system cannot handle hourly data, all contracts that requirehourly data (which included virtually all of the new contracts) are handled manually using spreadsheets,Access databases and user developed SAS tools today. The new system handles hourly (and sub hourly)data and has a formula editor that will enable advanced contracts to be configured in the system andautomate the processing of these contracts.OpenLink also brings an extensible system platform that we can use in the coming years as a basis onwhich to replace the existing and aging Entegrate deal capture system as well as handle future contracttypes.The project is dependent on the GMS Upgrade project for data to calculate the curtailment trackingprovisions in new renewable energy contracts.

B. Implementation Overview

System Integrator selection start in November 2013 following CRT approvalProject start in June 2014Go live in August 2016

C. Project Rationale

The main driver behind this project is the rise in the number and complexity of the renewable contractsmanaged by Power Supply. The graph below shows the projected number of contracts growing in thecoming years.

251



(2 of 4)

As can be seen above the number of contracts will actually level out after 2015. However, the number ofcomplex contracts will continue to increase significantly as old contracts roll of and are replaced by newer,more complex contracts. The graph below shows the number of contracts that will need to be settled eachyear:

The ‘High’ bar in the chart above illustrates the number of contracts that have a high complexity forsettlement. The number of these contracts will triple between 2013 and 2017.

Today, renewable energy contracts are handled in the existing WES. This system is old and lacksfunctionality to handle hourly data, which all high complexity contracts (and most other new contracts)require. The only way to handle contracts requiring hourly data today is to develop manual workaroundsusing spreadsheets, Access databases or user developed SAS programs as illustrated below:

The required results are calculated using these tools and manually fed into the existing WES system. Thisapproach introduces significant risk and requires incremental staffing to keep up with the rising number ofcontacts.

A solution is needed in the short term. As new renewable energy contracts have increased rapidly innumber and will continue to do so in the next 5 years, it will become increasingly difficult for WES to handlethe increased complexity. Any delay in the project will cause the number of spreadsheets required to handlethe new contracts to increase.

D. Project Benefits

Avoided financial losses associated with mishandling or inaccurately managing and/or settling contractReduce future head count increases needed to meet business growth

Current process for settling renewable and CHP contracts

252



(3 of 4)

Improved risk management and controls. Although incremental personnel and manual controls can beadded around spreadsheet based solutions to substantially reduce risks there is a residual set of risksthat cannot be eliminated due to the nature of spreadsheets. These risks are related to lack ofautomated audit logs, enforced data integrity, automated workflow and centralized implementation ofchangesReduced risk of missing data due to a high number of disparate data sources and a complex manualprocess. More spreadsheets invariably means more sources of data (often copy/paste from otherspreadsheets) and more handoffs between people and groups, all of which increase the risk of misseddata

E. Alternatives

After the project was paused in 2011, four alternatives were studied as part of the CMP reassessmenteffort in Fall 2011:

o Implement OpenLink Enduro Develop OpenLink Endur like capabilities in houseo Update the current WES system to current technology but keep the same functionality and

manual workaroundso Do nothing and keep the current WES system built on obsolete, non supported technologies

Alternative 1– Continue implementation of Openlink Endur WES replacement and enhancementso Implement a solution (Openlink Endur) for WES replacement and renewable energy contract

settlementso Continue to utilize Entegrate as deal capture system until needed functionality requires

replacement, and use OpenLink to replace Entegrate with at that timeAlternative 2– In house development was discarded for the following reasons:

o High costs (close to those of an OpenLink solution)o High implementation risk since we would essentially be building a copy of a vendor package in

houseo No expandable platform since we would develop a point solution with few options to expand

the system footprint

253



(4 of 4)

Alternative 3– Spreadsheet solution: Upgrade WES technologies and leverage existing systemso Upgrade the existing technology platform of WESo Continue to utilize Entegrate as deal capture system until needed functionality requires

replacemento Internally create new systems or purchase one off solutions, UDAs and manual processes as

required to meet business requirementsAlternative 4 (do nothing) was discarded since the current system is obsolete and built on nonsupported technologies, including Sybase database and Microsoft Visual Basic 6, which is no longersupported by Microsoft.In 2013 a 3rd party consultant (Structure Group) was engaged to perform an assessment of the projectincluding:

o How peer companies manage and settle bilateral contractso What vendors are capable of meeting the SCE business needso Provide a recommendation on how SCE should move forward

Structure’s findings were as follows:o There is no single universal solution that peer companies use to settle bilateral contracts.

Energy Trading & Risk Management (ETRM) systems, point vendor software solutions, and inhouse developed systems are all used by various companies

o Recommend implementing OpenLink because (1) it is unlikely that another vendor will provide asignificantly cheaper solution, and (2) OpenLink is the leading vendor to provide thefunctionality required by SCE.

Following the 2013 reassessment the overall recommendation is to proceed with OpenLink for thefollowing reasons:

o Doing nothing was analyzed and is not an optiono Immaterial cost differences between vendorso OpenLink has the capabilities to meet SCE needs and fits the technology footprint

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255



Generation Management System (GMS) Upgrade

256



0

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2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2016


Year250

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

250


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

GMS Upgrade

The Generation Management System (GMS) was developed and implemented in 2003 to enable SCE’s Trading and Energy Operations personnel to more accurately determine SCE’s net energy position throughout each operating day, thereby improving the opportunity to lower energy costs to its customers.

The GMS system has upgraded its software as new versions have become available, one software version was a major upgrade and the system been operating reliably. However, the current softwareversion is not compatible with the current versions of Windows and Windows Server, which causes maintenance issues.

GMS Upgrade

257



1 | P a g e

GMS Upgrade EXECUTIVE SUMMARY (1 of 2)

PROJECT OVERVIEW_

Buy or build: [Buy]Leverage current capabilities / Fit with existing roadmap: [Yes]

Description

The Generation Management System (GMS) was developed and implemented by Power Procurement in 2002. GMS enables SCE’s Energy Supply and Management personnel to more accurately determine SCE’s net energy position throughout each operating day, thereby lowering energy costs. GMS provides real time information for renewable, conventional and qualified facility power plants and enables SCE to update hour-ahead schedules as needed for generation deviations from planned schedules. GMS provides compliance data and monitoring for reporting as required by various agencies.

The GMS upgrade project will upgrade the existing system to the latest platform of the vendor software.

The GMS system is classified as a NERC Critical Cyber Asset and is subject to NERC CIP regulations.

Status

The GMS upgrade project was implemented in 2016

Ease of implementation

Medium: GMS is based on a vendor software package from Invensys PLC.

PROJECT RATIONALE_

Business needs

The GMS system upgraded its software as new versions became available, one software version was a major upgrade and the system been operating reliably. However, the current software version is not compatible with the current versions of Windows and Windows Server, which causes maintenance issues.

The system was designed and warranted by the vendor for 25 connections to power plants. A software upgrade in 2005 enabled the system to handle 50 connections, but this is insufficient to handle SCE’s current 105 connections and projected future portfolio as more renewable generation resources comes on-line. (An average of 60 new connections is expected each year with 225 total connections by the end of 2018).

The new software version brings a number of enhancements in data integration, alarming and screen development.

PROJECT RATIONALE (Continued)_

The original scope of the project in 2013 was to upgrade the existing GMS software and address the 2 WECC findings on dual factor authentication and comply with NERC CIP version 3 The scope of the project has been significantly expanded to include the following:

Implementation of a brand new window Active Directory forest (NSCE.com) and all of the servers and services needed to support the new domain Re-defining Catalogues system for NSCE infrastructure, which included NPSI too Address the NERC CIP v5 Requirements Implementation of the new Qualys Vulnerability tool Implementation of the complex Intrusion Detection System (IDS) Evidence collection for the entire NSCE infrastructure along with the NGMS infrastructure

The following Milestones will be completed in 2016 Milestone

NERC CIP compliant Infrastructure Site Acceptance Testing Implementation - Cutover Production Implementation Post Implementation Tasks:

Stabilization Decommission of old infrastructure

Urgency

A solution is needed in the short-term since the number of data connections to power plant is currently above what the original system was designed for, and new connections are continuously being added to support more renewable power plants as they come online. Also, the current version of GMS in not compatible with the current versions of Windows and Windows Server.

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1 | P a g e

GMS Upgrade

A. Project Overview

Purpose

Same basic functionality with enhancements

No sub-projects

Technicalaspects

Provides data to other tools

The purpose of the project is to upgrade the current Invensys software platform (which was installed in 2002) with the current version of the software (called Wonderware ArchestrA).

The basic functionality of the software remains unchanged, but the new platform brings a number of enhancements:

Better data integration – easier to bring real-time data out of the GMS system to share with other systems. This will lower the development cost of future projects that require data from GMS. Alarming – easier to configure various types of alarms, e.g. when a renewable generating unit is operating outside the expected forecast Screen development – easier to add screens to provide overview information for multiple generating units or details of the operations of a specific generating unit.

There are no sub-projects identified.

GMS is a real-time control system that collects data about the operation of SCE’s power plants up to every 4 seconds. GMS receives operating instructions from CAISO and translates these instructions into commands that are sent to the plants’ control systems for execution. For example, CAISO may instruct the Mountain View 3 unit to increase output by 20 MW. GMS receives the instruction from CAISO, alerts the operator, validates the instruction against the Mountain View capabilities and forwards the instruction to the generating plant.

Currently the existing GMS system provides data on an ad-hoc basis for various analysis purposes. This ad-hoc data is manually exported. Going forward data is required on a consistent recurring basis for several new purposes:

Multi-Stage Generators (MSG). SCE has 3 new generators under contract that will require detailed real-time data in order to validate the counterparty invoices. Curtailment tracking. Detailed real-time data is needed to validate counterparty invoices for economic curtailment (where SCE instructs the generator to reduce output due to economic, rather than reliability, reasons). We currently have one active resource where the value or economic curtailments is approx. $1 million per year. We have over 20 resources coming on line over the next few years that will have similar requirements. CAISO pay for performance initiative. Detailed real-time data from GMS is required in order to validate CAISO settlement charges related to the Pay for performance market initiative. The pay for performance initiative is implemented by the IMEP3 project but GMS is the source for data needed for validation.

The current system would require extensive ongoing manual efforts to export the data required to support these initiatives on an ongoing basis. The upgraded system will enable automated data exports.

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2 | P a g e

B. Project Rationale

Compatibility with current Windows versions

Increase number of data connectionsto power plants

Software enhancements

The GMS system has not changed platforms since it was installed in 2002 and has been operating reliably since then. However, the current version is not compatible with the current versions of Windows and Windows Server, which causes maintenance issues. The new version is compatible with SCE’s current versions of Windows and Windows Server. This issue is urgent since the previous Windows versions will become unsupported both internally and externally over the next year.

The system was designed and warranted by the vendor for 25 connections to power plants. A software upgrade in 2005 enabled the system to handle 50 connections, but this is insufficient to handle SCE’s current 105 connections and projected future portfolio as more renewable generation resources comes on-line. (An average of 60 new connections is expected each year with 225 total connections by the end of 2018).

The new platform brings a number of software enhancements in data integration, alarming and screen development, which will make it easier to configure and customize the system to support a growing portfolio of generating units.

C. Key Benefits

Moreconnectionsto power plants

Compatible with current Windows

Software enhancements

Better data integration

Most importantly, the new software version provides more capacity for data connections to power plants. We are currently operating above the number of connections that the system was designed for (25) and new renewable power plants come online as we sign new contracts to meet the state’s 33% renewable portfolio goal. Connections to power plants are required to manage, monitor and collect real-time data from those plants.

The current version of In Touch software cannot run on the current versions of Windows and Windows Server. The new version will reduce maintenance issues since it is compatible with the current versions of Windows and Windows Server.

Software enhancements in data integration, alarming and screen development will make it easier to configure and customize the system without adding staff even as the size of the renewable portfolio grows.

The current version has limited data export capability and the upgrade will enable GMS to provide data to the right people at the right time to make the right decisions including needed curtailment tracking functionality in the CMP project.

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3 | P a g e

D. Alternatives

Upgrade existing system

Upgrade the existing GMS system as described in this document. This is the recommended alternative.

Do nothing This is not a viable alternative long-term since the current system is already operating above the original design specifications and is only able to handle the current number of connections thorough mitigation efforts that are not sustainable will eventually fail as we keep adding connections to renewable power plants.

Delayimplementation

This shifts the costs, but does not reduce them. A delay will require increased mitigation efforts to keep the system operating and will impact the timing of information availability to the real-time operators.

Reduce scope Since this is an upgrade of the software platform reducing scope is difficult since we cannot upgrade part of the platform.

261



2012

2013

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2019

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Power Supply Projects less than $3M

263



0

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800

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

0

1,200

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,200


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Usage Measurement System (UMS)

The Usage Measurement System project will replace the current UMS system, which is based on obsolete technology and is unable to support the use of the new SmartConnect® meter interval data. The availability of retail interval meter data from SCE’s SmartConnect® program requires significant changes to Power Supply’s usage aggregation and reporting processes. The current technology and design of UMS will not support the demands of the new SmartConnect® meter interval data. The SCE requirement to submit Settlement Quality Meter Data (SQMD) to the CAISOfor the cumulative and interval metered services for each hour of every trade day cannot be supported with the existing UMS system.

The replacement of SCE’s UMS will provide the ability to handle retail customer interval meter data from SCE’s SmartConnect® program and the replacement of obsolete technology with current technology that can be supported going forward.

Usage Measurement System (UMS)

264



INVESTMENT MEMO

(0 of 2)


Usage MeasurementSystem

265



(1 of 2)

I. Business Initiative DescriptionA. Initiative NameUsage Management System (UMS) ReplacementB. Initiative Description

The project will update existing tools to accommodate Smart Connect meter data for submission to theCalifornia Independent System Operator (CAISO).

Current tools take monthly cumulative billing files from CSBU systems; the proposed solution would usehourly meter data instead of monthly meter data.

The current Usage Measurement Aggregation (UMA) system was designed and developed in the late1990s and was updated in the early 2000s. The technology is over 10 years old. The system currentlyconverts monthly meter data to hourly values using statistical load profiles The proposed system wouldutilize hourly meter data from the Smart Connect data warehouse.

The project is planned to begin in 2018 and is expected to take less than one year to complete.

There are no dependencies on other projects.


Replacement of the current Usage Measurement Aggregation system by a new system that can accommodateSmart Connect interval meter data will result in a more accurate Settlement Quality Meter Data (SQMD)submission to the CAISO. More accurate meter data will reduce the size of the CAISO uplift charges that arecaused by less accurate meter data submissions.

Utilizing the Smart Connect meter data to support the CAISO SQMD submission will improve the utilization ofthe Smart Connect assets. SCE is the only major utility in California not to use retail customer interval meterdata in its SQMD submission. Replacing UMA with a system that can accommodate interval meter data willmitigate the reputational risk that SCE faces by using cumulative meter data when interval meter data isavailable.


The Usage Measurement Aggregation system is over 15 years old. While it continues to function, wehave deferred replacement of this system until the completion of the Smart Connect project. Now thatthe Smart Connect project has been completed we believe that we are obligated to use the moreaccurate hourly data instead of the monthly data with load profiling.

This project will replace the existing UMA system with the current SCE standard tools and methods. Thisproject will utilize the hourly meter data to report to the CAISO rather than the load profiled monthlymeter data.

266



INVESTMENT MEMO

(2 of 2)


The UMS Replacement initiative will impact following business capabilities:

Agreement Management Agreement Billing and PaymentManagement

Usage Data Collection

Analytics Operational Analytics Operational AnalyticsAsset Management Asset Maintenance Meter ServicingData Management Meter Data Management Meter Data ManagementData Management Asset Data Management Asset Data ManagementPower PortfolioManagement

Contracts Management Settlements

Current system was designed and developed in the late 1990s. The technology (PowerBuilder) is over 10years old. This project will upgrade the technology to current SCE standards, thereby improving userexperience as well as maintainability.The current application retrieves monthly cumulative billing files from CSBU systems. The files are thenconverted to hourly data using statistical load profiles. Then for submission to CAISO the profiled usagedata is aggregated based on rate class and voltage level. The current application is not flexible enoughand requires a lot manual work in case of system failure


G. Proposed Options

The proposed solution is to retrieve usage from the Smart Connect data and aggregate it with thecustomer’s usage who have opted from Smart Metering. Since the current UMA has been developedmore than 15 years in Power Builder, that is obsolete technology, it should be upgrade to the currentSCE technology and standards.

267



2016

2017

2018

2019

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Tota

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0

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 1/1/2017


Year2,185

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,185


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

PPD Control Systems Hardware Refresh

Upgrade aging control/monitoring systems. Coordinate individual upgrade efforts according to dependency on resources, operational impact and outage windows, etc. Assess upgrade options to leverage investment opportunities for convergence to a standard platform if feasible.

A number of existing control systems are at or beyond their useful life, are not under maintenance contract, or require operating upgrades (e.g. Microsoft Windows) to maintain a stable environment. Running this equipment to failure is not an option, as the loss of control of generating assets can result in increased operating costs, loss of revenue and increased unplanned outages.

PPD Control Systems Hardware Refresh

269



INVESTMENT MEMO

(0 of 1)


PPD Control SystemsHardware Refresh

270



(1 of 1)

I. Business Initiative DescriptionA. Initiative NamePPD Control Systems Infrastructure RefreshB. Initiative DescriptionRefresh of end of life, out of support equipment that was centralized into IT in 2013/14C. Business Capabilities Mapped

D. Desired Business OutcomesEvaluation of the systems has revealed that many systems are at or beyond their useful life, are notunder maintenance contract, or require operating software upgrades to maintain a stable environment.Additionally, many of these systems will be out of standard support and will require SCE to purchaseextended support agreements. Running this equipment to failure is not an option, as the loss of controlof generating assets can result in increased operating costs, loss of revenue and increased unplannedoutages.E. Business Priorities & ConcernsCoordination of refresh with scheduled outages will be critical to the success of this refresh program. Sinceplant outages are scheduled months in advance, there is little room for schedule variance and the refresh of thesystems must work flawlessly. Efforts to perform these refreshes were halted due to the Control Systemsmanagement moving to IT. Business leadership and operations is concerned that delaying these upgrades willresult in unplanned outages and higher replacement costs.F. Business Strategic Alignment

Refreshing PPD’s core Control System Hardware is foundational to support their goals and objectives for eithersustained or improved Generation Reliability Index (GRI). With a trend of reduced staff and the need for greateroperational flexibility, Process Automation and the supportive Distributed Control Systems (DCS) are vitalcomponents of their various Plant Site Operations. The need for DCS to be current, modern, flexible, andsupportable is foundational to a reliable operation today and in the future. Allowing these vital components tofall into obsolescence introduces unwanted risk and allows for consequence contrary to the goals and objectivesof Generation for sustained or improved GRI.

271



2015

2016

2017

2018

2019

2020

Tota

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272



0200400600800

1,0001,2001,4001,6001,800



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 6/1/2018


Year400

1,570

600

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,570


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Gas Solar Control Systems Refresh

This effort will refresh aging control system infrastructure which includes PLCs and Fire Protection System at Mountain View (MV) and Peakers PLCs Upgrade.

Without this effort the IT asset will continue to be at risk and can potentially impact MV and Peakersplants generation in case of failure.

Gas Solar Control Systems Refresh

273



INVESTMENT MEMO

(0 of 1)


Gas/Solar Control SystemRefresh

274



(1 of 1)

I. Business Initiative DescriptionA. Initiative NamePower Production – Part of “PPD HW Refresh program” for “Gas/Solar Control System Refresh”B. Initiative DescriptionRefresh of end of life, out of support equipment that was centralized into IT in 2013/14.Gas Solar control systems will be focus of refresh starting in 2016 through 2018.

C. Business Strategic AlignmentEvaluation of the systems has revealed that many systems are at or beyond their useful life, are not undermaintenance contract, or require operating upgrades (Windows) to maintain a stable environment.Additionally, many of these systems will be out of standard support and will require SCE to purchase extendedsupport agreements. Running this equipment to failure is not an option, as the loss of control of generatingassets can result in increased operating costs, loss of revenue and increased unplanned outages.D. Anticipated Business Outcomes & Benefits

This effort will refresh aging control system infrastructure which includes PLCs and FireProtection System at Mountain View (MV) and Peakers PLCs Upgrade. Without this effort theIT asset will continue to be at risk and can potentially impact MV and Peakers plantsgeneration in case of failure.The associate operations and IT effort in recovering the plant to normal operations will beresource intensive and challenging.MV plant will be subjected to generation risk of 1000MW in case of system failure; Pearkersplant failure will be subjected to NERC CIP compliance risk

E. Business Impact AssessmentThe refresh effort will require both IT and Power Supply resources for the planning, construction andcommissioning for the new assets and system even vendor resources will handle majority of the core workwith IT resource assisting.

The refresh will also need to be coordinated with plant operations to have advance notice for outage window.

F. Technology/Automation RationaleThe refresh effort will upgrade aging assets and control systems with latest technology andcomponents to sustain normal operations. Routine IT support will be restored to handle regularmaintenance based on yearly pre plan refresh/maintenance schedule moving forwardG. Proposed Options

The following options are under consideration:Option 1: Complete a like for like system refresh which offers the same functions using the sametechnology platform

Option 2: Re platform where applicable to maintain same monitoring/control functions but allow fortrending standard across gas/solar portfolio to enable future growth with added capabilities, functionsand potential opportunities for resource optimization.

275



2016

2017

2018

2019

2020

Tota

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5. CLOSE DATE: 12/1/2020


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8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,500


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SCE-04, Vol. 02IT


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2017

2018

2019

2020

Total

Work Mgt and Reliability-Centered Maint

The purpose of this project is twofold: (1) replace mostly paper-based work management routines inSCE’s Generation department and (2) introduce Reliability-Centered Maintenance (RCM) in generation. Work management covers how work crews and scheduled and dispatched to the various PPD field locations. RCM uses measurements and data analytics to service and/or replace plant components before they are likely to fail rather than replacing them at predefined time intervals.

Work management will improve and streamline the crew scheduling process in Generation. RCM will help control the ongoing maintenance expenses without sacrificing plant reliability or availability.

Work Mgt and Reliability-Centered Maint

277



INVESTMENT MEMO

(0 of 2)


Work Management andReliability Centered

Maintenance

278



(1 of 2)


Work Management and Reliability Centered Maintenance


The purpose of this project is to replace paper based work management routines in SCE’s Power Productiondepartment (PPD) and to introduce Reliability Centered Maintenance (RCM) in PPD.

Work management determines how work crews and scheduled and dispatched to the various PPD fieldlocations.

RCM uses measurements and data analytics to service and/or replace plant components before they are likelyto fail rather than replacing them at predefined time intervals.


PPD is looking for ways to streamline their maintenance operations to more effectively manage generatormaintenance. This project supports this initiative.


Work management will improve and streamline the crew scheduling process in PPD.RCM will reduce the ongoing maintenance expenses without sacrificing plant reliability or availability.


Capabilities: Asset Management, Asset Operations, and Generation Operations will be enhanced to betterperform crew scheduling and to perform maintenance when it’s needed rather than on a fixed schedule.Process Impacts:

o Power Production, Power Generation, Plant Operation, Manage Generation Plant Operation will beimpacted from improved crew scheduling and implement reliability based maintenance


Implement work management system.Implement data acquisition and analytics to support reliability centered maintenance.

279



INVESTMENT MEMO

(2 of 2)

G. Proposed Options

We are currently evaluating the following options.

The PPD work management functionality desired is similar to Transmission & Distribution (T&D)’s workmanagement work crew processes. The operation of the field crews in T&D and PPD are similar – crews arescheduled and dispatched to perform maintenance and repair work in various field locations. We plan toevaluate existing T&D solutions such as Consolidated Mobile Solution (CMS), to determine if we can applythem to PPD business needs.

RCM uses measurements and data analytics to service and/or replace plant components before they arelikely to fail rather than replacing them at predefined time intervals. Asset data is stored in SAP today, butmay need to be enhanced for this effort. Also, data needs to be collected and stored in SAP to indicate thehealth of each asset. The health data may include existing measurements collected by the control systems(e.g. output levels and run time), data collected by other existing software tools (e.g. vibration analysis) anddata collected manually (e.g. lubricant analysis). This data will need to be imported into and stored in SAP tocreate a historical record of asset health and to the used for asset analysis. Data analytics will need to beprovided to use the asset and health data in SAP to analyze asset health, predict the likelihood of futurefailures and schedule preventive inspection and maintenance work before the asset fails.

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285



Enterprise Content Management

286



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1. WITNESS: J.P Shotwell


Pin #: 3896


2. PROJECT DETAIL:








Year0

3,400

5,200

5,400

SCE $

5,400



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

19,400


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total


See Testimony

See Testimony


287



INVESTMENT MEMO

(0 of 3)


Enterprise ContentManagement

288



(1 of 3)

I. Business Initiative DescriptionA. Initiative NameEnterprise Content Management (ECM)

B. Initiative DescriptionThe Enterprise Content Management program is focused on improving SCE’s capabilities to manage a diverseand complex set of business records. SCE has been in business for more than 125 years, which has created alarge volume of business information that supports the Company’s operations. The vast majority of thisinformation exists in a variety of electronic formats, such as electronic spreadsheets and PDF files, as well as“structured” IT supported database systems used across the enterprise. This initiative will implement solutionsto minimize the risks associated with management of SCE business records, and deploy tools and controls toensure employees are able to fulfill their records management compliance responsibilities.

The volume, frequency of change, and variety of this information is ever increasing, as are the regulations. Theoperations of SCE are highly dependent on the accessibility, accuracy, and compliance of this information.This increasingly complex information landscape and growing pace of change in technology continues tochallenge the information governance and record keeping capabilities implemented in SCE. The initiativesidentified below are needed to support the evolving information governance needs required to mitigate therisks and challenges.

C. Business Strategic AlignmentThe Enterprise Content Management program will support Information Governance’s strategy of ensuringcompany records are accurate, accessible, and compliant. D. Anticipated Business Outcomes & BenefitsAnticipated benefits from the ECM program:

Improve employee culture and awareness of the risks associated with mismanagement of Company’sinformationEnhance safety, reliability and compliance by improving the quality of Company’s critical informationMinimize efforts required by employees for performing routine information governance activitiesAvoid fines and penalties resulting from non compliance

E. Business Impact AssessmentThe following business capabilities will be matured through this program:

1. Records Quality2. Information Management3. Records Management4. Information Protection

289



INVESTMENT MEMO

(2 of 3)

G. Proposed OptionsIn order to enhance the business capabilities to achieve Information Governance’s desired goals / outcomes,the following technology initiatives are being proposed:

1. Digital Signaturesa. Currently, the document needs to be printed, signed, and then scanned to create the

finalized business recordb. In the existing process, it may be hard to confirm the integrity, reliability, and trustworthiness

of the signature processc. Expand the rollout of Digital Signatures (CoSign) and eSignatures (DocuSign) across SCE

2. Centralization of Critical Recordsa. A significant portion of SCE's critical records (defined by being critical to operations, safety,

or compliance) are contained in unmanaged repositories, which lack the necessary controlsto perform records management

b. Complete migration of critical records into SCE’s standard records repositories3. Automated Record Keeping

a. Currently, the method for declaring, classifying, and dispositioning records is manual, whichis vulnerable to human error and judgement

b. Enable the management of records based on pre defined “rules” and automating these rulesin SCE’s standard record repositories

4. Email Records Managementa. Content would be developed by IT Cybersecurity and manually distributed to each location

when new content is made availableb. These records need to be retained per the Company’s record retention schedule and

provided the same records management protections and controls as document basedrecords

5. Enterprise Searcha. Today, users have no way to search all repositories (enterprise content systems, emails, file

shares, and cloud services), making it difficult to find the appropriate recordb. Make business information accessible and retrievable from multiple enterprise type sources

to create a single results interface, providing a comprehensive view of available information6. Structured Data Lifecycle Management

a. Provide the capabilities to enable records management, archiving, and legal disposition ofthe data residing within the SCE’s structured data transactional systems (i.e. SAP)

7. In Place Records Managementa. Allow users to manage content across SCE’s multiple content repositories

8. Digital Records Preservationa. Provide long term preservation of records in the face of changes in technological electronic

format and media standards, technological obsolescence, and degradability of technologicalmedia

Due to technological advancements, the ease and frequency of creating electronic records is exponentiallyincreasing, as are the compliance, safety, and operational needs. The risks associated with managing thiscomplex information landscape is significantly higher than the past. One of the alternatives to this ECMprogram is managing content manually, which will require a large dedicated staff. This team will need tocompliment operational, safety, and compliance organizations, who will continue to spend time to executeroutine tasks associated with searching, declaring, classifying, and disposing of SCE's records.

290



INVESTMENT MEMO

(3 of 3)

This manual alternative could result in high costs over a long period of time. Ultimately, the consequences ofmanual processes may include the following:

Reliability of company operationsRegulatory or legal compliance mattersUnsafe conditions for employees and customersFinancial or reputational damage

291



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Electronic Document Management / Records Management (eDMRM)

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0

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1. WITNESS: J.P Shotwell


Pin #: 7847


2. PROJECT DETAIL:






5. CLOSE DATE: 11/1/2016


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SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

eDMRM - 2015 Rollout

eDMRM is currently the SCE electronic solution for enterprise document and record management.

An enterprise solution, eDMRM is the System of Record for all of SCE.

eDMRM -2015 Rollout

294



INVESTMENT MEMO

(0 of 3)


Electronic DocumentManagement / RecordsManagement (eDMRM)

295



(1 of 3)

I. Business Initiative DescriptionA. Initiative NameElectronic Document Management / Records Management (eDMRM) – 2015

B. Initiative DescriptionThe eDMRM project expands and increases the capabilities and usability of the existing eDMRM solution byincluding:

o ENGINEERING DRAWING MANAGEMENT – Engineering drawings are being migrated into eDMRM. Thecontent in Corporate Drawing Management solution is being migrated to the eDMRM DrawingManagement module. The plan is to bring the remaining 4 engineering libraries into the same module,as well as to implement additional enhancements to the solution.

o RECORDS RETROFIT AND DISPOSITIONING – A series of changes need to be made to approximately 50libraries in eDMRM in order to meet compliance and audit requirements. These libraries have noRetention Class Codes applied, and this needs to be corrected. When the codes are applied, a RecordSeries Indicator (RSI) needs to be added to each record to control specified retention events. Finally, arecord disposition process needs to be configured and applied.

o HIGH RISK RECORDS – Information Governance has identified 33 Record Class Codes that areconsidered to be high risk based on criticality and complexity. These records need to be migrated toeDMRM to mitigate risk and increase accessibility. Today, many of these records exist on shared drives.

o OPENTEXT HEALTH CHECK – The eDMRM solution has grown from managing 2 TB of content in 2013 toover 19 TB in early 2015. As a result, less than acceptable performance often occurs. OpenText hasagreed to perform a Health Check, providing 3 4 SMEs to perform an end to end performance analysis.The expected result is a series of technical recommendations to improve performance that will need tobe implemented as part of this project.

C. Business Strategic Alignmento Improve the reliability of operations and safety of personnel and publico Avoid unnecessary engineering construction costso Improve speed and accuracy of emergency responseo Ensure integrity, protection and availability of high risk business records across the Companyo Significantly improve compliance controls surrounding unstructured datao Improve e Discovery and Legal Hold operationso Improve eDMRM system performance for end users D. Anticipated Business Outcomes & Benefits

E. Business Impact Assessmento eDMRM Engineering Drawing Management solution, will implement several critical features

including:Grouping of engineering assets and related sub components, to enable bulk checkin/check out, a key requirement for engineering drawing operations. This will preventan inaccurate version of a drawing being issued for construction.

296



INVESTMENT MEMO

(2 of 3)

Enable powerful search using Drawing number range, to expedite quick and accurateretrieval of drawings.Integration with AutoCAD to significantly reduce the time for analyzing drawings.

These features will improve:Construction and M&I operations thereby improve reliability, safety and reduceavoidable construction costsAvailability of drawings critical for quick Emergency response operations

o Migrating unmanaged High Risk records from file shares and document libraries into eDMRMwill improve protection, integrity and accessibility of these types of records. This will result in:

Significant enhancement of compliance controls around unstructured data.Minimizing the possibility of privacy breaches, significant monetary penalties andreputational damage by keeping records in a highly controlled environment.

These features bring:Providing quick Emergency response of critical contentContent integrity that will deliver reliability, safety, and availabilityHigh levels of security to the recordsEnsures the high risk records are protected, available, and findable throughout thecompany.

o Records retrofitting adds a set of global metadata to all libraries in eDMRM. Global metadataapplies Information Governance document types, compliance security requirements, andrecords management retention and dispositions processes resulting in:

Significant enhancement of compliance controls around unstructured data.Strong enforcement of records retention and disposition of content.

These features bring:Improves compliance controls (FERC, NERC, etc.) surrounding unstructured dataIdentifies records for e Discovery and Legal Hold operationsEnsures the availability and findability of records throughout the company.

o The implementation of the OpenText Health Check recommendations will improveperformance and reliability for all users.

Engineering drawings will be processed faster, leading to more accurate and saferdelivery of drawing for outages, construction, and repairs.Documents being processed for T&D, Ethics and Compliance, and other enterprisewide applications will be delivered faster and more reliably.Overall response to all users will be enhanced, assuring improvements in productivityand higher satisfaction with the eDMRM solution.

297



INVESTMENT MEMO

(3 of 3)

The eDMRM application is the SCE architectural standard for unstructured content management and theadditional components of the entire program are included on the IT roadmap.

o Domain: Information Managemento Technology: OpenText Content Server v10.5


G. Proposed Options

Manual work around optiono Record migration, classification, and disposition can be solved with manual processes

performed by the content owners (users). However, high levels of risk exists when theindividuals do not follow company policy for records management and do not observerequirements to migrate content to a centralized location.

o Additional manual processes will be cost prohibitive.

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299



Plant Ledger Upgrade and Tax Module Installation

300



0500

1,0001,5002,0002,5003,0003,5004,0004,500

1. WITNESS: David R Pierce


Pin #: 7467


2. PROJECT DETAIL:






5. CLOSE DATE: 7/1/2016


Year4,200

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

4,200


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Plant Ledger Upgrade and Tax Module Installation

Upgrade of the PowerPlan suite of capital accounting software to the latest commercially available version (2015.1.3.0) and the implementation of the PowerPlan Tax Repairs module, which automates the determination as to whether a capital expenditure is deemed a repair for tax purposes.

PowerPlan is the software application that manages the sub-ledger for SCE’s fixed asset accounting, property tax, and income taxes. However, the application has not been upgraded for the past eight years as necessary to remain technically supported and address changes in SCE’s business needs for managing capital asset accounting and IRS tax regulations. The upgrade reduces application failures from outdated vendor technology, greatly decreases costly SCE-specific customizations, and eliminates business process inefficiencies. The version upgrade is also necessary in order to implement the Tax Repairs module which enables SCE to continue to provide customers with the flow-through tax benefit associated with the tax-repair deduction in a systematic and auditable manner adhering to IRS guidelines.

Plant Ledger System Upgrade

301



INVESTMENT MEMO

(0 of 2)


Plant Ledger Upgrade andTax Module Installation

302



(1 of 2)

I. Business Initiative DescriptionA. Initiative NamePlant Ledger Upgrade and Tax Module InstallationB. Initiative DescriptionThis project has two primary components:

1. The upgrade of PowePlan software and activation of the Tax Repairs module within PowerPlan. This willeliminate code customizations, spreadsheets, and existing pain points and provide new functionalityreducing manual labor through automation and new system integration. This effort, which will includethe necessary information for the tax repairs calculations in 2016. The upgrade effort will involvereplacing the current version of the Powerplan software modules and implementing version 2015.1.3.0of the software. With the upgrade will come the removal of 442 (Approximately ¾ are removals forcustom reporting fields; the remainders are business function and technical customizations) of the 566customizations within the current version of PowerPlan. Utilizing the standard features in version2015.1.3.0 will allow for automation, transparency of data and full integration between the modules.

2. The Tax Repairs portion of this project involves developing business process changes and implementingsystem modifications in order to properly quantify capital projects that can be immediately expensedfor tax purposes as a repair in accordance with Internal Revenue Service (IRS) guidelines. This effort willresult in significant benefits to SCE’s financial earnings. As an interim solution, upstream SAP, GIS, andDesign Manager (DM) changes allow SCE to comply with IRS guidelines while the upgrade portion of thisproject will deliver a long term IT compliant and SAP integrated solution reducing risk.

C. Business Strategic AlignmentThe Tax Repairs project will define business process and procedural changes to associate work orders and assetquantity to each circuit. The project will also perform the necessary data conversion and implementation ofsystem changes to capture circuit and asset quantity data and calculate repairs deduction on eligible orders.This project will also address business process changes in Capital Asset Accounting and Tax Department that aremeant to deliver process efficiencies and transparency in the data.D. Anticipated Business Outcomes & BenefitsIRS Compliance Effective January 1, 2016, the Revenue Procedures mandate the 10% replacement test onper circuit basis instead of average circuit basis. To meet this requirement, Tax Repair Project was launched todevelop business process changes and implement the Tax Repairs module of PowerPlan that will enable therepairs calculations per the IRS requirements.

Software Support Compliance The PowerPlan modules must be upgraded from version 10.2.1.2 to version2015.1.3.0 as the vendor will no longer support the older 10.2.1.2 version after 2014.

SCE IT Compliance – Solution should reside within SCE’s Data Center in a supported software solution.E. Business Impact Assessment

The Tax Repairs project will define business process and procedural changes to associate work ordersand asset quantity to each circuit. The project will also perform the necessary data conversion andimplementation of system changes to capture circuit and asset quantity data and calculate repairsdeduction on eligible orders. This project will also address business process changes in Capital AssetAccounting and Tax Department that are meant to deliver process efficiencies and transparency inthe data.

303



INVESTMENT MEMO

(2 of 2)


The PowerPlan solution is an existing technology within the SCE IT footprint. An evaluation was performed tounderstand SAP’s current capabilities. The result was a finding that SAP’s Asset Lifecycle Accounting (ALA)product was not ready to address the capabilities needed, thus PowerPlan was the selected option.G. Proposed OptionsAlternative #1 Continue with PowerPlan Upgrade / Tax Repairs

Functionality

IRS and SCE IT Data Center ComplianceElimination of Custom CodeData Accuracy and efficiency gains in transparency & reportingTax Repairs ModuleGreater integration with SAP and within PowerPlan SuiteSoftware Support Compliant (PowerPlan and Windows Server)

Drawback None

Alternative #2

Address compliance functionality needs through with current version (continuewith current version of PowerPlan)Provide Fix Issues & OU desired capabilities on O&M

Functionality Depends on O&M approved funding

Drawback

SCE IT Data Center Non CompliantNo gains in Transparency & ReportingLimited tax deduction calculations - Tax Repairs calculation conducted on non-supported applicationContinue with integration issues within PowerPlan Suite as well as with SAPSoftware Compliance (PowerPlan and Windows Server)Continue with manual spreadsheets due to lack of integrated system

Alternative #3Continue with current version of PowerPlanProvide Fix Issues O&M

Functionality Depends on O&M approved funding but limited to data issue;

Drawback

SCE IT Data Center Non CompliantNo gains in Transparency & ReportingLimited tax deduction calculations - Tax Repairs calculation conducted on non-supported applicationContinue with integration issues within PowerPlan Suite as well as with SAPSoftware Compliance (PowerPlan and Windows Server)Continue with manual spreadsheets due to lack of integrated system

304



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PowerPlan Tax Repairs

306



WHITE PAPER

PowerPlan Tax RepairsPractical Steps for Implementing the Tangible Property Regulations

307



1

INTRODUCTION

Asset intensive companies are struggling with adopting the recent tangible property

regulations and safe harbor guidance in a way that minimizes manual manipulation, eliminates

system customization and provides necessary transparency. Any company anticipating

large capital expenditures over time should leverage the tangible property regulations to

deploy a robust tax strategy and optimize cash ow.

Historically, determining what is capital versus current expense for expenditures associated

with tangible property has been a long-standing, contentious issue for both business

taxpayers and the . ith the issuance of the nal tangible property regulations and

industry-speci c safe harbor guidance, the expectation is that much of the contention will be

replaced with more clarity instead of relying on the courts.

ow that regulations are nalized, the challenge shifts to how to implement the new rules.

However it’s not as easy as it appears. Why? In part, because the data necessary to automate

the process is generally found in different systems or solutions. Adding to the complexity

is the challenge of what the accounting, operations and IT groups need or are responsible

for when it comes to expenditures. “Who would have ever known how many systems and

processes a task like replacing a utility pole could touch? We spent a great deal of time just

tracking through the spider web.” – Tax Director – Regulated Utility

Despite the complexity and challenges, compliance with the regulations is required. This

means businesses need to implement sustainable processes that are ef cient, provide

greater visibility and insight, and are exible enough to allow for future guidance or audit

adjustments.

While meeting the compliance requirements taxpaying companies now have the opportunity

to take advantage of the clearer de nitions around the issue of capital versus repair to

maximize the deduction and minimize the cash tax liability, resulting in annual savings

anywhere from $10 million for smaller companies to more than $300 million for larger

companies.

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2

Companies who have successfully implemented the new tangible property tax rules have

incorporated key stakeholders across the organizations in the discussion, developed a

detailed implementation plan and modi ed business processes before incorporating the

necessary changes. “The key success to our automation project was getting all of the

stakeholders on board early with the bene ts to our company and our customers.” – Tax

Director

This paper discusses the challenges of implementing the new regulations, the bene ts of

automating tax repairs, and the critical steps needed to de ne your implementation process.

I. HISTORY OF REGULATIONS AND OTHER GUIDANCE

In 2006 the IRS issued the original regulations concerning the treatment of capital

expenditures which were withdrawn in 2008 and reissued after receiving a not-so-welcome

reception. Then in 2011, the IRS withdrew the 2008 regulations and issued new regulations

in temporary and proposed form. Are you confused yet? inally in September 2013, nal

regulations were issued with an effective date of January 1, 2014. The original regulations left

a great deal of uncertainty and prompted various capital intensive industries to approach the

IRS about issuing speci c guidance. As a result the Industry Issue Resolution IIR program

issued speci c safe harbor guidance for

1. Transmission and distribution network assets in the utilities industry Rev. rocedure

2011-43 ,

2. Repair versus capitalization in the cable industry Rev. rocedure 2011-2 ,

3. ower generation assets in the utilities industry Rev. roc. 2013-24 ,

4. Repair versus capitalization in the natural gas industry Rev. roc. 2014-1 , and,

. Unit of property for network assets in the telecommunications industry Rev. roc.

2011-22, 2011-2 and 2011-28 .

“Who knew all the integrated systems that are involved in the repair of a single power line?”

~ Tax Director of Regulated Utility

309



II. KEY CHALLENGES FOR LEVERAGING TANGIBLE PROPERTY REGULATIONS AND

SAFE HARBOR GUIDANCE

The key challenge in implementing the tangible property regulations and leveraging tax

repairs safe harbors is understanding the complexity of their application by industry. In order

to follow the guidelines, the rst hurdle is de ning a “unit of property” for tax purposes.

After de ning the unit of property, companies must then determine if the work performed on

that unit of property is a betterment, restoration, or adaption to a new or different use.

Inherent in de ning a unit of property and then making determinations as to the result of the

work performed is having the necessary data available. For instance, how are assets created

for book purposes? Do the book accountants track assets at the level necessary for tax or

for example do they consider everything at high, generic levels? In addition, the tangible

property regulations interact with other book tax differences associated with self-constructed

property particularly the U ICA provisions. Avoiding “double counting” and reconciling

these interactions is a must to ensure compliance and integrity of the deduction. Finally,

manual or customized solutions to complete these tasks are time and resource intensive and

make controls and reconciliations dif cult at best.

3

310



4

III. DEFINING UNIT OF PROPERTY AND APPLYING STANDARDS WITHIN SPECIFIC

INDUSTRIES

Understanding how units of property are classi ed can be helpful in making accounting

method determinations. For example, the unit of property differs by industry for track

structures, wireline telecommunications, wireless telecommunications, electric power

transmission, distribution and generation, and oil & gas distribution, midstream, transmission

and downstream assets. The nal regulations included the following examples

a. Electric Power Transmission and Distribution Network Property

De ned broadly, electric transmission and distribution property includes “real and

personal property that is used to conduct and control electricity at any point between

an electrical generating station and the location of consumption of the electricity

by the consumer,” such as wires conductors , towers, poles, structures and ttings

mounted on towers and poles, electrical interrupters such as circuit breakers, fuses

and other switches , transformers, capacitors, instrumentation, security structures, and

pad on which equipment is mounted. It also includes street lighting and traf c and

similar signal systems.

311



b. Generation property

xamples of generation property include coal- red, natural gas- red, oil- red,

hydroelectric, and nuclear-powered power stations. The safe harbor identi es the tax

unit of property by the functional interdependence of how the plant operates. For

example, a coal red plant’s boiler system is the tax unit of property but further broken

down into a boiler’s major components – steam drum, economizer, etc. The safe harbor

does not include renewable energy such as wind or solar.

c. Oil & Gas Property

For midstream pipeline transportation the unit of property may be the section of

pipeline between two compressor stations. When the Gas Distribution Industry Issue

Resolution IIR is released, it is expected the non-linear unit of property de nition will

be more speci c for compressor stations, processing plants, etc.

For downstream property re neries and chemical plants the tangible property

regulations guidance on unit of property should be referenced. Some potential units

of property are the re nery or plant in its entirety, including crude distillation units,

catalytic cracking units, hydrogen units, Amine treating and regeneration units,

Dimersol units, and catalytic reforming units chemicals created during the re ning

process; terminals and storage facilities.

We recommend consulting your tax professional as it relates to your speci c circumstances.

5

312



6

IV. AUTOMATION IS KEY TO YOUR TAX STRATEGY AND IN MAXIMIZING THE BENEFITS

OF THE NEW REGULATIONS

A company’s tax strategy historically includes information, people, processes and technology.

Information is key to your strategy and leveraging technology should enable the access of

information and not be a barrier to success. Companies should not rely on manual systems,

customizations or the infamous Excel spreadsheet to manage the process. By automating the

repair regulations and eliminating these barriers, companies can achieve following objectives

and bene ts

1. Creating a Sustainable Process – Allows you to synchronize your book asset records with

your tax asset records and easily keep track of your additions, disposals and transfers.

This provides the ability to support multiple books, users and companies.

2. Enabling Compliance – Enables the proper tracking of retirements and the proper

ordering and management of all tax basis adjustments including 263a interest and

overheads. The ability to incorporate and comply with future legislation is also facilitated

through automation.

a. Meeting SOX and Other Audit Standards – Helps ensure that the standards of

completeness, validity, and accuracy are met and provides 1 a system audit trail that

tracks who made changes when, and 2 a nancial audit trail with the ability to drill

down to work orders and invoices to support calculations.

3. Accommodating Business Changes – Facilitates forecasting and budgeting efforts,

allowing companies to quickly project cash ow considerations and provides data quickly

and more reliably for estimated tax and tax planning purposes.

. Maximi ing Financial Bene t – Enables the ability to assess large quantities of different

projects by type to quickly apply multiple scenarios before choosing which scenario is

best suited for your business. This also provides control of the overall process.

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7

“When we began the process to implement the new regulations,

automation and compliance were our key priorities.”

~ Tax VP

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8

V. TAKING PRACTICAL STEPS TO IMPLEMENT THE REGULATIONS

With more clarity around the issue of capital vs repair for tax, best-in-class companies who

automate their tangible property regulations can maximize the deductions and minimize that

cash tax liability, resulting in annual savings anywhere from $10 million for smaller companies

to more than $300 million for larger companies.

Once the barrier of interpreting and determining the appropriate application of the regulations and

safe harbor by industry is overcome, the key to success is applying the new standards successfully

and automating to maximize the bene ts. Best-in-class companies who automate their tangible

property regulations can achieve compliance, integrate their tax strategy and potentially maximize

the deductions and minimize that cash tax liability, resulting in annual savings.

Here are steps to take to ensure that your adoption and automation goals are met

1. Assess Your Current State - To determine where to start implementing your automated

solution, ask these questions

What methods and elections are currently in place?

What are your current book capitalization policies?

What will be the impact on other tax areas? 263 a , 1 , state income, earnings, etc.

2. Engage All Stakeholders – The level of detail required for automation may impact your

supply chain, enterprise asset management EA , operations and nancial systems.

Therefore, it is critical to engage other departments and functions across your business,

for example, engineering, operations, accounting and IT, in order to document gaps and

make plans.

3. Determine Your Requirements – Critical to the automation of tax repairs is developing

a road map of information ow across your entire business in order to determine your

ultimate requirements. Once you have your team assembled, de ne the requirements

of each of your stakeholders and use these as the guidelines for decision-making as you

identify changes needed for compliance and automation.

4. Identify the Changes Needed for Compliance – After you have de ned the

requirements of each of your stakeholders, take your previous review of your current

accounting process and policies and identify the changes that need to be made for

compliance. In addition, analyze the opportunities that exist for adopting new methods.

315



9

5. Identify the Gaps in Automation – Because there are so many departments and so many

implications with tax repairs, build a design map to identify system gaps and areas of

improvement needed to take full advantage of the tax repairs and be in compliance. For

example, the questions you need to ask are

What systems feed into your current ledger process?

Does your work management system allow for determination of categories of projects?

What planning tools are needed to run various scenarios?

6. Put It All Together – The nal step in developing an implementation plan for your

automated solution is developing roadmaps for your compliance and system changes and

establishing checklists for actions needed to close automation gaps.

7. Implement Your Plan – Implementing a sustainable and automated solution requires a

coordinated approach across the tax, accounting, and IT departments. The right partners

and products will make your tax repairs automation implementation a success.

VI. CONCLUSION

With the nal tangible property regulations in place, these new regulations present an

opportunity to deploy a more advanced tax strategy, maximize current deductions and

minimize cash tax liability for capital intensive businesses. Now companies can more easily

classify an asset as a repair or capital improvement. However, to take advantage and save

potentially millions in tax liabilities, you must eliminate manual assessments within your

processes.

By automating the entire tax repairs process, companies save time and the team can focus

on analyzing the data to make better business decisions, which ultimately helps maintain

compliance and manage a signi cant deduction on the return. Creating a successful

implementation plan for implementing the new tangible property regulations requires

assessing the current state of your compliance processes, including stakeholders across the

various businesses, and de ning requirements for each. Once an implementation plan has

been developed and successfully executed, tax departments will be quick to respond to the

demands of CFOs and the marketplace with accurate and up-to-date cash ow analysis. A

tax department with these regulations now automated will be able to interact strategically

with overall strategies of the company.

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10

ABOUT THE AUTHORS

Jim Dahlby – Vice President

Jim brings more than 13 years of experience at ower lan in a wide variety roles including

program management, product management, solution architecture and implementation.

He was the key architect of the ower lan Tax Repairs, roject anagement and Capital

Budgeting odules. He also designed and authored the Regulatory CWI , Tax Repairs, Asset

Retirement Obligation FAS 143 and Reimbursable rojects modules.

Jim graduated with highest honors from the Georgia Institute of Technology where he

received a Bachelor of Science degree in Industrial and Systems Engineering with a minor in

Economics.

Tim Price - Director, Professional Services

Tim rice is an experienced consultant with extensive systems integration and management

consulting experience. His expertise resides in the process design and implementation of

accounting and work management applications. rior to joining ower lan, Tim worked as

a anager at Accenture, in the nance and performance practice where alongside project

work developed and documented best practice work management and nance O s for the

utilities industry.

r. rice graduated from The University of Georgia where he received a Bachelor of Business

Administration in Finance.

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11

ABOUT POWERPLAN

ower lan is an enterprise software company devoted to helping asset-centric businesses

optimize their nancial performance. ower lan combines purpose-built software for asset

centric accounting, tax and budgeting/analytics with domain expertise to help executives

generate cash, mitigate compliance risk and enable a culture of cost management. The

world’s most demanding asset-intensive companies trust ower lan to manage more than

$2.3 trillion in assets today. ower lan is a privately held company based in Atlanta, GA.

For more information, call us at 1 6 8.223.2800 email us at info pwrplan.com, or visit us at

www.powerplan.com.

300 Galleria arkwaySuite 2100Atlanta, Georgia 3033

tel 1 6 8.223.2800

www. ower lan.com

Unlocking the Power of Fixed Assets.

All content is Copyright 2014 ower lan, Inc. All rights reserved.No portion of the content may be reproduced, stored or transmitted in any form, or by any means, without prior written permission from ower lan. roduct functionality is subject to change without notice.

318



Corporate Projects less than $3M

319







2016 2017 2018 2019 2020

7,670 4,140 2,370 1,110 3,970 19,2601 Jay Castleberry

SCE-04, Vol. 02 7,670 4,140 2,370 1,110 3,970 19,2601.1

0 0 0 0 1,000 1,000CIT-00-DM-DM-0000751.1.1

1,700 1,000 0 0 0 2,700CIT-00-DM-DM-0000741.1.2

0 2,200 0 0 0 2,200CIT-00-DM-DM-0000711.1.3

0 0 2,000 0 0 2,000CIT-00-DM-DM-0000661.1.4

0 0 0 0 2,600 2,600CIT-00-DM-DM-0000651.1.5

0 940 370 370 370 2,050CIT-00-DM-DM-0000621.1.6

350 0 0 0 0 350CIT-00-DM-DM-0000591.1.7

2,200 0 0 0 0 2,200CIT-00-SD-PM-0002161.1.8

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0 0 0 740 0 740CIT-00-OP-SM-0000261.1.11

320



0

500

1,000

1,500

2,000

2,500

1. WITNESS: Jay Castleberry


Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2017


Year0

2,200

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,200


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Legal Re-platform

Upgrade from SharePoint 2010 to SharePoint 2013 on-prem to support highly integrated legal platform (LIMS) with custom SharePoint applications

Keep version current with the latest system updates from vendor

Legal Re-platform

321



INVESTMENT MEMO

(0 of 2)


Legal PlatformModernization

322



(1 of 2)


Legal Platform Modernization


The objective of this program is to take a holistic view of the entire Legal portfolio and make improvements,reduce redundancies and customization, and streamline and develop efficiencies of the Legal applications andinfrastructure. This initiative will align with the strategic direction and objectives of Legal and IT. This programinitiative will be made up of multiple projects and enhancements that will be multi phased and will span overmultiple years.

SCE is planning to re platform the current core technical environment. The plan is to upgrade the current LegalSharePoint environment with a platform to address the existing technical obsolescence and gap infunctionalities. This upgrade will resolve gaps in functionality not met by the current platform, provide agilityand flexibility to meet changing business needs, improve interface with new systems, and streamline datasharing. The process improvements achieved will improve processing of Claims against SCE (bodily injury,damage to electrical appliances, accidents involving SCE vehicles, and property damage), the handling of legalmatters (comprehensive management system for legal matters), and regulatory proceedings. This will enableLegal to be more responsive to change such as data requests, lawsuits, court rule changes and compliance.


This initiative will enable the Legal organization to operate in an efficient manner leveraging proven enterprisetechnology solutions.


Address the technical obsolescence of existing applicationsReduce customizationAddress/close gaps in current functionalityProvide flexibility to meet changing business needsImprove interfaces with new systemsStreamline data sharingImprove reporting capabilitiesMobile capabilities


This program will impact all the major legal applications and business processes:o Legal Information Management Systemo Claims Information Management Systemo Regulatory Information Management Systemo Regulatory Claims Management System

323



INVESTMENT MEMO

(2 of 2)

o Workers Compensationo Legal Matters Management Systemo eDiscovery


Address the technical obsolescence of existing applicationsReduce customizationAddress/close gaps in current functionalityProvide flexibility to meet changing business needsImprove interfaces with new systemsStreamline data sharingImprove reporting capabilitiesMobile capabilities

G. Proposed Options

Option 1 (Recommended)Integrate and upgrade the Legal applications and capabilities into the current enterprise applications andplatforms.

Option 2Upgrade the existing applications separately to address existing gaps and functionality.

324



2016

2017

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2019

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0

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400

600

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

0

0

0

SCE $

1,000



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

1,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Reg Affairs - TM2 Replacement

Requesting a new database system to manage regulatory filings and tariffs that has similar functionality to the current system; however has web-based front-end, task reporting, review/approval workflows, and quicker processing capabilities.

Require a new application that will manage tariffs and advice letters and accommodate the unique requirements of the California Public Utilities Commission for cancellation, editing, composition, and publication of submitted filings and documents on the Internet.

Reg Affairs - TM2 Replacement

326



INVESTMENT MEMO

(0 of 3)


Reg Affairs TM2Replacement

327



(1 of 3)


Tariff Manager System (TM2) Replacement/Upgrade Project


Tariff Manager 2 (TM2) supports the State Regulatory Operations (SRO) department(s) in the preparation,management, and retention of California Public Utilities Commission (CPUC) advice filings. TM2 pays particularattention to the management of tariffs, providing tools that support the unique CPUC requirements forcancellation, editing, composition, and publication of these complex documents. TM2 also automates thepublication of submitted filings, the currently effective tariff books and historical tariffs to SCE websites, savingsignificant personnel resources while helping to ensure that SCE remains in compliance with CPUC postingrequirements.

An update to or replacement of TM2 is requested due to system age (15+ years) and company reliance on a solecontractor to maintain the system. If a replacement system is procured or built, SRO requests that thereplacement system have similar functionality to the current system, with expanded reporting, search,review/approval workflows capabilities and a web based front end for broadened accessibility.


TM2 functionality is in alignment with company and department goals.


SRO relies on TM2 to produce, manage, and retain all of SCE’s California Public Utilities Commission (CPUC)tariffs and advice letters. TM2 is compatible with Microsoft Office software, able to maintain up to date webpages and acrobat files providing a complete presentation of the filing history and currently effective tariffs.Successor system or upgraded TM2 version is expected to be web based for expanded user accessibility.

TM2 is a custom built data base system that manages tariffs and advice letters and accommodates the uniquerequirements of the CPUC for cancellation, editing, composition, and publication of submitted filings anddocuments to the internet. This system is support by IT; however, program changes are dependent on oneindependent contractor. The system is antiquated with several functionalities, such as expanded search andrate synching/population capabilities, not built into the system. These missing functionalities would increaseproductivity while limiting risk of error and noncompliance.

The new TM2 solution will provide the following benefits to the company and SRO organization:

Compliance with General Order (GO) 96 BBusiness records retentionCustomer service – Advice filing and historical and current tariff information is published and availableto both SCE personnel and the public at sce.comCloud base solution will provide easier, increased access for SRO staff

328



INVESTMENT MEMO

(2 of 3)


TM2 is currently being utilized by the Investor Own Utilities (IOUs), such as SoCal Gas, PG&E, SDG&E, and SCE,therefore the solution functionality impacts all IOUs. The application has remained in largely the same state,with few changes made since it was implemented more than 15 years ago. Worries over application lifespanand system maintenance/enhancement have been raised due to the dependence on dated technology and thesingle, external contractor. These issues raise challenges in making enhancements that interact with newtechnology. Therefore, if TM2 is not replaced or upgraded with new technology, then SCE will have to manuallymanage the thousands of tariffs and filings. This would lead to the following impacts:

Out of compliance from the GO 96BO&M labor increaseFinancial impacts

In addition to the impacts listed above, internal SCE and other utilities audits have suggested the need for a toolwith newer technology to ensure compliance with CPUC and risk avoidance of vendor obsolescence.


The solution will manage and retain tariffs and advice letters in addition to enabling SRO to remain incompliance with CPUC requirements in regards to the following tariffs specific activities:

CompositionPublicationEditingCancellationRetention

Moreover, the solution will handle task reporting, review/approval workflows, have improved search andquicker processing capabilities.

G. Proposed Options

Option1 – Do not replace or upgrade TM2:As stated in section E of this document, if TM2 is not replaced or upgraded with new technology, then SCEwill have to manually manage tariffs when the existing system becomes obsolete. This would lead to thefollowing impacts:

Out of compliance from the General Order GO96 BPotential increase of RMICompany reputation damageO&M labor increaseFinancial impacts

329



INVESTMENT MEMO

(3 of 3)

Option2 – Upgrade TM2:TM2 can be upgraded with newer technology by the same independent contractor that is an expert onspecific CPUC requirements for tariff management. While this option would seem optimal, the independentcontractor has become a single point of failure and high risk to SCE. If the vendor is out of business, there willbe no updates to the system, leaving SCE with the potential risk to resort to manual processes or assess othertools. The reliance on this vendor is a primary driver in upgrading the current TM2 system.

Option3 – Replace TM2:SCE and other Utilities have looked for other technologies that can fulfill the tariff management processrequirements under the CPUC regulations, but could not find anything off the shelf that meets the uniquerequirements of the CPUC and the numerous filing load that SCE is responsible for. This leads option 3 toeither perform a research for better technology solutions to be built by a third party or in house.

Procure a COTS Solution:The advantages of procuring a COTS solution includes the following:

Eliminates the high risk of having one single developer for software enhancements and bug fixesReplaces antiquated technology with newer technologyKeeps SCE in compliance with CPUC requirements

While there are several advantages of procuring a COTS solution, other Utilities, including SCE, were not ableto find any technology solution which can fulfill Utility Regulatory CPUC requirements under GO 96B.

Build the solution In House:The advantages of building a solution in house includes the following:

Eliminates the high risk of having one single developer for software enhancements and bug fixesThe solution can be developed based on SCE standards and policiesThe technology remains in SCE enabling the business to perform changes require by CPUCregulations or to perform changes require by SRO organizational needs

The execution of complete Software Development Life Cycle (SDLC) may result in more expense than thepurchase of a new system. Additionally, the development costs are born strictly by SCE, instead of sharedamongst SCE and the other IOUs.

330



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Program: SERVICE MANAGEMENT

Pin #: 7849

WBS Element: CIT-00-OP-SM-000025

2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2016


Year2,800

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,800


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

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Total

Integrated Financial Planning

This project aims to improve the effectiveness of the forecast and planning processes across Finance.

Deliverables will enhance financial and operational decision making capability supported by more accurate, integrated, transparent and timely enterprise data.

Integrated Financial Planning

332



INVESTMENT MEMO

(0 of 2)


Integrated Budget Planning

333



(1 of 2)


Integrated Budget Planning Project will enhance the financial planning processes and will integrate the shortterm and long term planning processes into one standardized methodology.B. Initiative Description

This project aims to improve the effectiveness of the forecast and planning processes across Finance.Specifically, we aim to:

Integrate planning processes across short term and long term planning to allow use of common toolsEstablish consistent planning methodologies and policies based on leading practicesIntegrate data and planning assumptions across Treasurer’s, Capital Asset Analytics, Income Tax, andRegulatory AffairsDesign, configure and test an integrated short term financial planning model to align stakeholders forfinancial planning purposesCreate data repository for all financial planning activities required to develop short term financialstatements and increase data availability and transparencyProduce automated financial statements – Balance Sheet, Income Statement, Cash Flow Statement forbudget and long term forecast

C. Business Capabilities Mapped

The following Business Capabilities are identified as being a part of the Integrated Budget and Long TermPlanning project:

Financial PlanningD. Desired Business Outcomes

o Provide a single platform to easily produce an integrated set of pro forma financial statementsassociated with our budgeting process, short term planning and long term planning processesthat are consistent, accurate and transparent

o Automate recurring financial planning tasks so that finance can focus on scenario modeling andcomparative analyses for improved decision making. Ability to save scenario results for futureuse will aid with comparative analysis

o Support monthly financial reforecasts. Improvement in turnaround time via the platform willfacilitate monthly reforecasts of key planning items

o Minimize variances arising from methodology differences and time spent reconciling. Platformwill utilize the same methodologies and input sources to produce results for both short termand long term financial planning

334



INVESTMENT MEMO

(2 of 2)

o Provide a set of deep variance commentary functionality that can easily allow the finance teamto drill down into the key drivers and help establish cause effect relationships. Currently thiscapability is handicapped as the relevant information ( data, assumptions and calculations) isprocessed and stored across disparate systems within departments in corporate finance andregulatory planning

o Provide automation to generate control and summary reports to facilitate regular review forCurrent/Deferred Income Tax accruals, Income Tax payments and to verify book/tax differencestie to related Plant and Balancing Account forecasts. Model will also add greater data detailsthat could potentially improve tax repair forecasts

o Establish a platform that is stable, repeatable and secure that can guide users through definedprocesses, guard against inadvertent data deletion and provide flexibility to the business tomake modeling changes without incremental support from IT

o Ability to execute a financial forecast more often in a calendar year.

E. Business Priorities & Concerns

The business priorities and concerns identified and associated key challenges to achieving the businessinitiatives are listed below:

Provide integrated Pro Forma Financial Statements.Reduce cycle times to produce monthly updates to earnings per share and cash forecasts for thecurrent year outlook, budget, and long term plan – Efficient data integrations, calculations andapproval controls will be required to provide timely and accurate resultsAlign financial planning modeling assumptions across Finance and Treasury – Harmonizing twoseparate processes today will require a common understanding of both methodologies and purpose ofprocessesCreate new data repository and building a stable platform for planning calculations to increasetransparency – Complex, offline calculations may be required due to complexity, flexibility orcompliance with FERC or CPUC requirements. A single platform that includes both the data andcalculations across all planning workstreams will improve drilldown and variance driver analysisIncorporate leading practices into the planning process framework – Change impacts to incorporateleading practices into the broader user group may require further analysis or preparation for futurephases

F. Strategic Business Alignment

The Integrated Financial Planning project will improve our pro forma financial statements and alignswith the following 2016 SCE interface goals:

Core earnings targetCost effective financingsCash management to maximize AFUDCAdvance a High Performance Organization culture

335



2015

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Pin #: 7826


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2016


Year2,200

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,200


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Union Negotiations

As a result of the agreement entered into between SCE and IBEW, Local 47, how we accrue, use, and earn sick leave and other paid time off benefits have changed significantly. These changes willrequire a restructure of the existing SAP Time Management and Payroll schemas, configuration and enhancement of timekeeping and pay programs, interfaces, reports and forms.

The project is being delivered in two phases. Phase 1 specifies work to be delivered in 2015 with an effective date of January 1, 2016. Phase 1 focuses on restructure of SAP Time Management and Payroll schemas and configuration. Additionally and until Phase 2 work is completed and released into production, the implementation of interim processes are required to monitor and make adjustments to ensure employees timekeeping and pay are accurate.

Union Negotiations

337



INVESTMENT MEMO

(0 of 3)


Union Negotiations

338



(1 of 3)


Initiative name: Union NegotiationsB. Initiative Description

As a result of the agreement entered into between SCE and IBEW, Local 47, how we accrue, use, and earn sickleave and other paid time off benefits have changed significantly. These changes will require a restructure ofthe existing SAP Time Management and Payroll schemas, configuration and enhancement of timekeeping andpay programs, interfaces, reports and forms.

The project is being delivered in two phases. Phase 1 work was delivered in 2015 with an effective date ofJanuary 1, 2016. Phase 1 focused on restructure of SAP Time Management and Payroll schemas andconfiguration. Additionally and until Phase 2 work is completed and released into production, theimplementation of interim processes are required to monitor and make adjustments to ensure employeestimekeeping and pay are accurate.

This document provides the business case for Phase 2 of the Union Negotiations Project. Phase 2 addresses the“technical” (back end) impact requiring SAP programming changes to existing 3rd party interfaces, reports,enhancements, and forms. There will also be a need for additional configuration and automation or eliminationof the interim processes set up in Phase 1. Phase 2 completes the delivery of system changes required to meetthe Disability and other paid time off benefits plans changes collectively bargained and entered into anagreement between the company and the unions.

Phase 2 will also address the resolution of outstanding defects impacting disability related time and pay throughprocess improvements. Phase 2 allows the company to fully comply with the recently implemented CaliforniaPaid Sick Leave Assembly Bill (AB1522).

If Phase 2 is not completed in a timely manner, increased operational support will be required by both HRDisability Management and Corporate Payroll to continue managing the interim processes that resulted fromPhase 1. Both HR Disability Management and Corporate Payroll will assume the additional operational supportwith existing staffing levels with the understanding that Phase 2 will be delivered in 3rd QTR 2016.C. Business Strategic Alignment

1. Benefits union negotiations (with IBEW and UWUA) and resulting significant changes contribute to thecompany’s overall goal to achieve top quartile performance in cost and satisfaction. Changes resultingfrom benefits union negotiations enabled the company to more closely align with industrywidebenchmarks while still offering competitive wages and benefits to its employees.

2. Benefits Union Negotiations Phase 2 project also enables the automation of manual work processesaround timekeeping and payroll for employees on extended disability leaves. These processimprovements, through automation, enable the company to further achieve O&M cost reductions.

339



INVESTMENT MEMO

(2 of 3)


In order to meet the negotiated January 1, 2016 effective date of the disability benefits plan changes agreed betweenthe company and the union, it was necessary to split the project up into two phases.

Phase 1 delivered the configuration or “front end” changes that provide the employee with the necessaryinformation and tools to report disability and other paid time off benefits per the new plan.

Phase 2 was planned to deliver the “back end” changes, consisting primarily of program coding changes toprograms, interfaces, reports, and forms.

And until these “back end” program coding changes were delivered, Phase 1 introduced manualprocesses that would be necessary to carry out until Phase 2 changes were completed andimplemented in production.

These manual processes will impact both the HR Disability Management team and ControllersTimekeeping & Payroll Operations Support group who will be responsible for ensuring the newdisability and paid time off benefits are used according to the collective bargaining agreements,company disability benefits plan and policies.

Additional operational support will be required to create and generate every pay period (or morefrequently) reports around disability related timekeeping and pay, reviewed and adjustmentsidentified and made to ensure impacted employees time and pay are accurate and processed timely.

Both HR and Corporate Payroll have determined to take on the additional work during the deliveryPhase 2 without increasing current staffing levels in 2016. If, however, Phase 2 project is not deliveredin 2016, HR will need additional staffing.

Phase 2 will also complete the remaining changes required to be fully compliant with Assembly Bill 1522 (AB1522),California Paid Sick Leave law. By completing the changes required by AB1522 along with the program changesidentified in scope for Phase 2, we will be able to leverage development and testing efforts and costs and be fullycompliant with all requirements set forth by AB1522.

If Phase 2 is implemented in 2016:

Risk is mitigated through automation of changes and ensure accurate and timely pay to employees.

Compliance to mandates and required local, state, and federal reporting agencies around disability leaves(FMLA, AB1522, Wage & Hour laws) will be accomplished and manual efforts automating increasing accuracy ofand timeliness in 3rd party reporting requirements and employees pay.


CapabilitiesOrganizationalProcess

o Indicate which processes this initiative will impact and how they will be impactedo Indicate if this impacts a critical business process, and if so, indicate any Business

Continuity/Disaster Recovery implications (e.g. immediate recovery, etc.)

340



INVESTMENT MEMO

(3 of 3)

Capabilities, Organizational and Process impacts:o Phase 2 will automate many of the manual, interim processes deliberately introduced in Phase 1 to

meet the January 1, 2016 effective date. HR Disability and Corporate Payroll will carry out manualprocesses to ensure reporting and payroll requirements are met within specified time frames untilthe back end changes are implemented.

o Phase 2 automates the tedious manual entry of timekeeping and pay for employees out ondisability.


Deliverables implemented as part of Phase 2 will automate/eliminate the manual, interim processes introducedin Phase 1 as well as other labor intensive processes to process time and pay for employees on disability leave.Through automation, legal reporting requirements to third parties, including local, state and federal agencieswill be met as well as legislative requirements such as CA Paid Sick Leave (AB1522) ensuring timely and accuratereporting.G. Proposed Options

Option 1:The recommendation is to continue with Phase 2 which will automate/eliminate the manual, interimprocesses introduced in Phase 1 as well as other labor intensive processes to process time and pay foremployees on disability leave. Through automation, legal reporting requirements to third parties, includinglocal, state and federal agencies will be met as well as ensuring accurate and timely pay to employees. Thebusiness sponsors are willing to assume the additional work as a result of the manual, interim processes in2016 but will not be able to sustain without additional O&M labor budget beyond 2016.

Option 2:Do not implement phase 2. This will require extensive manual querying and extracting of large amounts ofemployees detailed timekeeping and payroll data that need to be analyzed and adjustments identified toensure accurate and timely reporting and pay. This involves having a thorough understanding of disabilityrelated time off laws that require certain types of disability leave to be taken before other types and tounderstand eligibility and waiting period rules outlined by the company’s disability and other paid time offbenefits plans and policies. If Phase 2 isn’t pursued, the business will have to seek additional O&M laborbudget to support the additional work introduced as a result of Phase 1 on an ongoing basis.

341



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342



Operation Services Projects

343



C-CURE 9000

344



0100200300400500600700800

1. WITNESS: Doug Bauder


Pin #: 7430


2. PROJECT DETAIL:






5. CLOSE DATE: 7/1/2016


Year700

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

700


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

CCURE 9000

Many SCE facilities, including all major buildings, control centers, and generation facilities, are protected by a centrally-controlled alarm and event management system. This physical access control system (PACS) logs all access and attempted access to SCE facilities in connection with the Corporate Security ID badging system.

The PACS upgrade project is to address the above-described limitations of the current version and to meet the projected growth of SCE’s physical security system needs.

CCURE 9000

345



INVESTMENT MEMO

(0 of 2)


C CURE 9000

346



(1 of 2)

I. Business Initiative DescriptionA. Initiative NameC CURE 9000B. Initiative DescriptionUpgrade the C CURE 8000 application to C CURE 9000. The existing PACS application, C CURE 8000, was installedin 1998. It was designed to integrate up to 150 alarm panels to maintain a high reliability of operations. Thereare currently 340 alarm panels connected to PACS and it is now well beyond its reliable capacity. It is unable toreliably accommodate additional facilities or secured areas within facilities. Other significant challenges includetechnical limitations that prevent integration with other security and compliance systems. These limitationsinclude reliance on a non standard database format, non scalable architecture, 32 bit operating environment,and performance issues. Additionally for NERC CIP v5 the following elements are required; Create a scalableenvironment that meets 99.9% reliability and meet the 15 minutes response time required by. Migrate 122 sitesfrom the existing system to the new system. Deploy independent Satellite Application Servers (SAS) to ensuresegregation of NERC and non NERC alarm groups. Implement a new architectural solution to allow for unlimitedexpansion of alarms; Include multiple levels of resiliency using multiple database & application servers; andSynchronize all database servers automatically.C. Business Strategic AlignmentThe upgraded system will enable Corporate Security to expand security operations monitoring, maintaincompliance with NERC CIP v5 requirements and the secondary site for Disaster Recovery will enable applicationredundancy for Corporate Security when data center could be down.D. Anticipated Business Outcomes & BenefitsThe upgraded system will enable Corporate Security to expand security operations monitoring, maintain compliancewith NERC CIP v5 requirements and the secondary site for Disaster Recovery will enable application redundancy forCorporate Security when data center could be down.


Capabilities (Note: Enterprise capability map can be used to help understand capabilities to be matured.)OrganizationalProcesses

o Indicate which processes this initiative will impact and how they will be impacted.o Indicate if this impacts a critical business process, and if so, indicate any Business

Continuity/Disaster Recovery implications (e.g., immediate recovery, etc.).

Upgrade to C CURE 9000 from C CURE 8000. The C CURE 9000 Upgrade includes:1. Migration of the existing 122 sites programmed in C CURE 8000 over to C CURE 9000;2. Implementation of a scalable and high availability C CURE 9000 environment to support future NERC

and Non NERC sites;Physical Access Control System (PACS) upgrade scope into NERC CIP compliance:

1. Create a scalable environment that meets 99.9% reliability and meet the 15 minutes response timerequired by NERC CIP v5;

2. Migrate 122 sites from the existing system to the new system;3. Deploy independent Satellite Application Servers (SAS) to ensure segregation of NERC and non NERC

alarm groups;4. Implement a new architectural solution to allow for unlimited expansion of alarms;

347



INVESTMENT MEMO

(2 of 2)


At the direction of Corporate Security, IT Cybersecurity and Enterprise Architecture, in collaboration withSiemens, reviewed SCE’s Physical Security Infrastructure (PSI) and made recommendations to expand the scopeof the C CURE 9000 project. As a result, PSI is now the umbrella term that now describes this project that isaimed to strengthen SCE’s cybersecurity posture in accordance with Enterprise Security Architecture’s design.Additionally, three key strategic functions within SCE’s physical security technology were added to the scope:

1. Build an effective support model between Corporate Security and IT2. Expand the NERC scope to include all C CURE servers and other PSI components, except non NERCmonitoring and video surveillance3. Enhance SCE’s geographic disaster recovery capability by creating a Disaster Recovery (DR) site tosignificantly reduce the time to return to normal operational level

G. Proposed OptionsTwo other options were considered in connection with the PACS upgrade project:

1. Complete replacement of PACS;2. Create a secondary, independent PACS environment.

The first option would require SCE to replace all alarm panels at current alarmed facilities. This isbased on the design and deployment of the current alarm system solution, where all the currentalarm system panels are unique to the PACS software. This option was rejected because it wouldnot be cost effective to replace all alarm system components when compared to upgrading theexisting application.

The second option would create operational challenges in maintaining two access control systems.Implementing this option would require the IT and Corporate Security departments to increase staffto operate multiple application environments. Additionally, security personnel would need to usetwo different computing environments to monitor security alarms, increasing operational risks andchallenges. This solution was not considered viable because of the operating challenges incoordination, communication, and response management.

348



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349



Operational Services Projects less than $3 Million

350



0100200300400500600700800


Program: SERVICE MANAGEMENT

Pin #: 3896

WBS Element: CIT-00-OP-SM-000026

2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2019


Year0

0

0

740

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

740


2016 2017 2018 2019 2020





PROJECT DETAIL WORKSHEET: MOBILE RADIOS


SCE-04, Vol. 02IT

Capitalized SoftwareCapitalized SoftwareMobile Radios723

2016

2017

2018

2019

2020

Total

Mobile Field Response

The mobile command center therefore needs to adequately support operational communication needs for SCE employees and those working with SCE in a support capacity.

This effort directly supports the goal for responding and recovering from catastrophic disasters and business disruptions.

Mobile Field Response

351



INVESTMENT MEMO

(0 of 4)


MOBILE FIELD RESPONSE

352



(1 of 4)

I. Business Initiative DescriptionA. Initiative NameThe current mobile field response capability is satisfied by 2 mobile command centers (MCC). They arelarge RV type vehicles outfitted with communications and operational support systems to help thoseSCE employees out in the field supporting an incident or emergency where existing brick and mortarfacilities are not sufficient or too distant to be efficient enough to run various operations.

Operations and activities include field work related to restoration as well as work in support of suchefforts. The mobile command center therefore needs to adequately support operationalcommunication needs for SCE employees and those working with SCE in a support capacity. The MCCscommunications infrastructure is currently difficult to set up and does not have enough bandwidthcapabilities to support operations when the MCC has been deployed. For example, when T&D requiresthe use of the OMS application from the MCC, OMS users have reported extreme slowness andresponse of application, hindering their ability to perform their duties.

Through actual deployments such as the French Fire it has become clear that the MCC is onecomponent of field response. There is a need to deploy other types of response environments such asDRASH tents. Consequently, there is a significant need for communications support for any type of fieldresponse environment. The MCC is a viable option to support short term deployments and in locationswhere heavy vehicles can gain access. Other situations call for long term deployments of mobileresponse facilities. In cases such as this, the current communications system cannot be utilized as itcannot be decoupled from the large RV type MCC.

Finally, mobile field response require communications must also be resilient to deal with adverseenvironmental conditions that may impact land based communications systems such as cellularnetworks and the loss of land based facilities such as the Alhambra Data Center.

The current state of MCC’s resilient network capabilities

Single built in satellite system.

Several challenges have been observed

The satellite antenna is difficult to set up on the older MCC.The single built in antenna is a single point of failure.The satellite system cannot be removed from the MCC and used for other temporarycommand/support facilities.Bandwidth is limited as it is as single system.SCE network downlink is only available through Alhambra. If Alhambra facility is unavailable,SCE connectivity is lost. There is currently no satellite redundancySlowness as a result of outdated technology (current solution is point to point and does nothave TCP acceleration).

B. Initiative DescriptionSCE is requesting to have four mobile response units with a combination of 2 RV units and 2 portablecommunication devices (e.g. satellite). Both of these units will need network capabilities, local printing and

353



INVESTMENT MEMO

(2 of 4)

internet access. This will include increased network bandwidth capabilities for RVs and two newindependent satellites. In addition, the current satellite infrastructure relies on a satellite hub located atAlhambra. This is a point of failure in the event the Alhambra facility is inoperable, therefore a backup hubis required at a separate location.C. Business Strategic Alignment

By providing a backup satellite hub at IOC, this will provide redundancy for SCE groups in the event thatthe ADC is not operating. This backup will serve as a disaster recovery site for all of SCE’s satellitecommunications using SCE’s Admin iDirect Hub. These applications include NERC CIP Security monitoring,NetComm over Satellite (NetCOS) backhaul, Hydro EHAS SCADA communication, and MRP Radio backhaul.All of these applications support business recovery in the event of a disaster. In addition to T&D, thefollowing SCE groups would be supported by this backup satellite hub at IOC: Security, IT, and NorthernHydro.D. Anticipated Business Outcomes & Benefits

The overall objective of updating the MCC is increase the overall operational communications capabilities

1. Improve ease of setup of the satellite system for satellite communications. Currently, an FTE isrequired to setup and be onsite to manage the satellite system. An independentcommunication solution should not require an FTE to setup and maintain it.

2. Allow for independent use of a satellite system from the MCC in the case a mobile tent solutionis used instead of the RV. This will provide SCE options on how to respond to specific incidentsbased on location and duration.

3. Allow for multiple systems to be established to increase bandwidth. Current technology in theMCC is outdated and needs to be updated.

4. Maintain the ability to use SCE internal networking systems (phone, SCE network applicationssuch as OMS) on a robust and resilient solution. Currently, the MCC has limitations due toavailable bandwidth available for use by first responders.

5. Provide adequate computing and network performance for devices connecting to the MCC.

Increased network capabilities will improve operations performance by allowing first responders timelyaccess to the necessary systems to coordinate the incident. The more people that can connect andcoordinate work through a networked mobile response facility allowing for the quicker the deployment ofresources and work assignments.

E. Business Impact AssessmentThis effort will allow SCE to respond in the event of emergency impacting our business operations. Byproviding the multiple configurations (RV, Satellite trailer) SCE will have greater flexibility to addressmultiple emergencies at the same time as well as tailor the solution to the terrain/environment of thespecific situation.

By providing a variety of configurations for mobile response, SCE will be able to provide the appropriatesolution based on the terrain of the incident. An independent satellite system will allow a command centerto be setup in areas where the MCC cannot be deployed. Additionally, by having an independent systemwhere a FTE is not required to setup and maintain the satellite, SCE resources can be redirected to assistingwith incident management.

354



INVESTMENT MEMO

(3 of 4)

To address the slowness of the current MCCs, additional hardware will be purchased to increase thebandwidth to prevent impacts to the first responders during an incident. Some of the bandwidth andcurrent challenges are due to the older hardware components of the MCC therefore upgrading thehardware will address these issues and address the speed.


The technologies included in this effort leverage existing SCE technology and provide a backup or disasterrecovery hub for all satellite communications for the entire SCE organization.G. Proposed Options

Option #1: Upgrade existing MCC, Add new satellite trailers and backup hub1. Update bandwidth capabilities on the two existing MCC RVs by putting them on SCE’s existing

iDirect SatCom system.2. Obtain two independent satellite trailers. Includes one button setup and portability3. Implement a backup satellite hub at IOC for disaster recovery purposes.

355



INVESTMENT MEMO

(4 of 4)

356



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0

500

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

0

0

0

SCE $

2,600



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,600


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Crisis Information Management System




358



(0 of 2)


Crisis InformationManagement System

359



(1 of 2)


Crisis Management Information SystemB. Initiative Description

SCE has transformed the way the company responds to business disruptions. The introduction ofIncident Management Teams has provided a new mechanism to strategically and cohesively respond tonatural and man made incidents such as significant weather events or fires that cause customeroutages. These recent changes introduce new challenges to existing operations. Protocols and processesfor managing people have had great success however there is still a gap in providing process automatingtools to manage the information and communication used to create a common operating model.

In a To Be environment, the desired solution would be a centralized technology which promotes realtime situational awareness, data and information management and collection, and a digitization ofprocess and protocols related to incident management. Such a solution should facilitate the aggregationof incident and emergency information critical for efficient and effective emergency response. Key valuewould come from the reduction of duplicative efforts, quicker dissemination of real time information,centralized management of documentation and information to be used throughout the company.Members from various OUs acting as part of an Incident Management Team (IMT) would use this singlesystem to develop a single picture using centralized information.

In extreme events or events that require external coordination, a to be system can integrateinformation exchanges seamlessly without added software with the first responder community. Thisproject request is for the On Premise implementation of WebEOC software:

WebEOC will be installed on premise, using SCE infrastructure and will be maintained by SCE ITteamExternal integration with other WebEOC systems at federal, state, county, and city level will beperformed by Intermedix Professional ServicesInternal integration with other SCE systems will be supported and managed by SCE IT teamBusiness Readiness and Organizational Change Management activities will be supported byBusiness Resiliency, Corporate Communication, and IT CommunicationTraining will be provided by vendor and SCE HR team

C. Business Strategic AlignmentThis project contributes to response and recovery capabilities from catastrophic disasters and businessdisruptions. The Crisis Information Management System will provide reporting and oversight toincidents across the enterprise.D. Anticipated Business Outcomes & Benefits

Allow Incident Management Teams to access critical applications in a timely manner, conduct business,and manage the incident from anywhere within SCE territory. Provide consolidated solution fordisplaying incident management information to various users including executives, IMT teams and BR.

360



INVESTMENT MEMO

(2 of 2)

E. Business Impact AssessmentThis effort will continue to support the business restoration and incident management capabilities within SCE byexpanding the use of the technology currently in place, WebEOC. This will have an impact across the enterprisewithin the various operating units with a limited number of users.


This effort of the Crisis Management Program will bring the WebEOC application on premise to beadministered by SCE MSP personnel within IT. Connectivity to the external entities will also beestablished and interfaces to internal SCE applications such as T&D work management.

SCE selected WebEOC based on recommendations from the following agencies:

At the federal level of the U.S. government, WebEOC is used by FEMA, the Environmental ProtectionAgency, the Government Accountability Office, the National Aeronautics and Space Administration,the Nuclear Regulatory Commission, the TVA, the U.S. Senate and the U.S. Departments ofAgriculture, Commerce, Defense, Energy, Health and Human Services, Interior, Transportation, andVeterans Affairs, as well as other federal agencies.

WebEOC is also used by more than 60 state level agencies in 40 states and U.S. territories.Nationwide, WebEOC is used by thousands of first responders and emergency managers working atthe county or city level in 48 of 50 states, representing hundreds of jurisdictions.

Within SCE territory, WebEOC is being used by CA State, LA City, LA Fire Department, OrangeCounty, Riverside County, Ventura County and many more.

G. Proposed OptionsOption #1: (Recommended) Leverage current Crisis Management System by bringing application onpremise and expand the interfaces to internal SCE applications along with external reporting agencies.Option #2: Continue to use Crisis Management System as a SaaS application with no integration to SCEinternal applications.

361



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2019

2020

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0

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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2018


Year0

0

2,000

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,000


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


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2017

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2019

2020

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Seismic Risk Assessment




363



(0 of 2)



364



(1 of 2)


Seismic Risk AssessmentB. Initiative DescriptionSCE has committed to implementing an Enterprise Seismic and Mitigation Program. The effort is to span acrossall types of SCE assets and infrastructure to include non electric, generation and electrical assets. In order tomanage this effort a system is needed to monitor, track and report on SCE assets before and after a seismicevent.C. Business Strategic Alignment

Currently limited analytical capabilities exist to understand the impact of seismic events on servicereliability and restoration at SCE.

This project aligns with the SCE Goal of Reliability by contributing to the ongoing support and restorationof the grid. By using the predictive analysis for Seismic events, SCE could proactively plan to minimizethe impact of seismic events on SCE assets impacting the grid. In addition, by identifying thevulnerabilities immediately following a seismic event, SCE will be able to pinpoint it’s resources toinspect and determine sustained damage as a result of the seismic event. This will shorten therestoration time for outages by focusing on the vulnerable assets. It also directly supports T&D’s goal ofimproving the Customer Outage Experience.

This project is designed to improve operational efficiency and reduce the costs associated with seismicrelated outages through improved data analytics and forecasting capabilities to improve:

1. Resource utilization efficiency and planning in T&D Operations and Corporate IncidentManagement Teams during seismic events,

2. Identify vulnerabilities to seismic events prior to actual event,3. Post event customer messaging and engagement,4. Corporate wide situational awareness during seismic events.

The primary objective of this project would be to standardize on one enterprise wide Seismic tool.Currently, there are two Seismic application implemented within SCE. They are:

ShakeCast is being used by Generation for some Generation assets andSERA is being used by T&D as a stand alone application to analyze substation assets.

D. Anticipated Business Outcomes & BenefitsThe expected outcomes for this project are:

Standardize on an enterprise wide seismic tool to predict impacts and assess damage to SCEassets including but not limited to substation, dams and facilities.Improve Corporate wide situational awareness of potential damage areas immediately followinga seismic event by being able to:

o Provide visibility by district or city.o Identify impacts to SCE assets.o Provide early identification of impacted equipment following a seismic event in order to

focus necessary resources (personnel and equipment) on restoration efforts.

365



INVESTMENT MEMO

(2 of 2)

Develop appropriate business continuity plans are in place for assets/facilities identified withhigh vulnerabilities to seismic events to ensure personnel safety.Improved intelligence for enhanced decision making by: Incident Management Teams,Corporate Communications, Government Affairs, and Customer Service.Develop SCE expertise in predictive analytics and begin development of an all hazards modelingapproach.

E. Business Impact AssessmentCapabilities impacted for this project is:

1. Work Lifecycle Management including: Work Initiation, Work Scheduling and Work Closure.2. Work Execution including: Work assignments, Work Dispatch and Work Execution.3. Work Planning including: Work Forecasting and Resource Plan Development.4. People Management: Health and Safety Management.5. Security Management: Protective Services.


Efficiently dealing with seismic related outages has long been an operational challenge for SCE. In thepast, Operations has not been very proactive in dealing with outages. This has made it difficult todispatch field crew quickly and efficiently, further extending outage interruption times.

This effort would continue to expand the Hazard Modeling Program for Seismic events. By standardizingon an enterprise wide tool that can be used to provide predictive analysis as well as assessment postseismic event, SCE will expand its capabilities to identify hazards to the grid as well as facilities andpersonnel. This will allow SCE to proactively defend against these hazards and minimize the outages andimpacts resulting from these events.G. Proposed Options

1. Recommended Standardize on one enterprise seismic tool and use against all SCE assets andfacilities.

2. Add additional personnel to track and assess seismic hazards and then estimate the impact toSCE assets by reviewing GIS maps and evaluating required resources for restoration.

366



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2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2020


Year0

940

370

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SCE $

370



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,050


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

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Total

EHSync Environmental Clearance Phase 2

Provide two way integration with enterprise-wide SAP-based Work Management systems including Design Manager. This type of integration would reduce errors in form entry, improve accuracy for compliance assurance and provide seamless data integration without redundant manual entries in multiple systems used across T&D and CEHS to directly improve project cycle time and automationfor real-time workflow management. · Create greater integration between Change Request and Activity Levels data fields for advanced personal object worklist (POWL) queries to improve project tracking capabilities to minimize redundant reporting and ensure critical dues dates and project data is visible for real-time decision-making. · Incorporate additional CEHS business processes (change requests in EHSync) and workflows including CRE, Power Production, GO131Dand coastal act permitting for environmental clearances to provide compliance assurance and automation on a growing commodity of projects and agency permits impacting clients. · Enhance GIS and questionnaire screening to increase auto-clearance and automation of project analysis which would improve environmental cycle time to deliver approved projects to clients for execution. · Greater functionality in search capabilities, form settings, and tasking to improve ease of use for end users and improve user productivity. * Add 50 additional GIS layers with geoprocessing. (10 layers will be addressed in 2016 and another 10 each year until 2020.) * Develop 3 additional reports for Environmental Clearance and enhance 3 existing reports.

Managing environmental health and safety issues is a top priority at SCE, and it is one of our corporate goals for 2015. We are committed to strengthening our environmental and safety culture. We are creating and sustaining a working environment that is built around the following objectives: * Prevent environmental, health, and safety (EHS) incidents from occurring, * Control environmental factors and provide the opportunity for hazards to be abated, * Have every

EHSync Environmental Clearance Phase 2

368



employee leave the workplace unhurt, * Minimize environmental impacts and disturbances to wildlife, * Ensure compliance with US Fish and Wildlife Service (USFWS) permit, and * Stop work anytime unsafe conditions or behaviors are observed until the job can be completed safely.

369



(0 of 4)


EHSync EnvironmentalClearance Phase 2

370



(1 of 4)


EHSync Environmental Clearance Phase 2B. Initiative Description

Managing environmental, health, and safety issues is a top priority at SCE. We are committed tostrengthening our environmental and safety culture. We are creating and sustaining a workingenvironment that is built around the following objectives:

Prevent environmental, health, and safety (EHS) incidents from occurring,Control environmental factors and provide the opportunity for hazards to be abated,Have every employee leave the workplace unhurt,Minimize environmental impacts and disturbances to wildlife,Maintain compliance with US Fish and Wildlife Service (USFWS) permit, andStop work anytime unsafe conditions or behaviors are observed until the job can be completedsafely.

This project will improve SCE’s environmental compliance performance for two functional areas: Avianand Work Clearance.

1. In the area of avian protection, the following leading indicators are used to measure theprogress and help improve EHS performance:

Frequency of avian injury/mortality incidents,Frequency of avian nest disturbancesCount of Reported incidentsFrequency of corrective actions, andTracking of reactive retrofitting activity completion by due date

SCE has a permit with the USFWS which requires the tracking and reporting of all avian injuriesand mortalities, with the exception of a few non native species. The permit also requires thetracking and reporting of all instances where SCE must move an active bird nest, defined as anest containing eggs or chicks. However, sometimes avian incident forms are submitted whenan inactive nest must be moved. This information is documented but is not reported. The reporton avian incidents is due annually to the USFWS.

2. SCE’s Environmental Clearance program is driven by the need to only construct in legallyallowed locations using methods which minimize environmental impacts. Having an accurateand robust system for managing environmental clearance processes will improve the efficiencyand accuracy of the auto clearance process, which will decrease the time required to assessprojects. Expediting the clearance process will allow T&D to begin construction projects morequickly. This will allow SCE to realize the financial gains from these projects sooner since theseconstruction projects are associated with SCE’s consumer product (electricity).

371



INVESTMENT MEMO

(2 of 4)

Other benefits of a robust, consolidated, and efficient environmental clearance system include:

Reduced time required to complete the clearance formIncreased data accuracyReduced data redundancyIncreased data visibilityEnhanced system usabilityEnhanced data extraction and reporting capabilities

C. Business Strategic AlignmentIt is required that all incidents specified in the permit conditions be reported annually to the USFWS.Failure to report all incidents would result in non compliance with the permit conditions and couldresult in additional conditions for future permit renewals and jeopardize the issuance of future permits.Additionally, this could have financial repercussions for SCE and could negatively impact the relationshipSCE has built with the USFWS. It is expected that fines for unreported incidents could be approximately$10,000 per incident. However, other repercussions can add additional financial burden.

The USFWS has recently revised the national permit requirements (Jan 2016) requiring reporting of 25data fields compared to previous permits that required 6 fields. The collection, analysis and reporting ofthese additional fields requires extensive effort.

Automated reporting and visibility into avian incidents will allow SCE’s internal avian experts to identifytrends and areas for improvement to reduce avian incidents. Incidents involving protected species canlead to fines and other penalties. For example, in 1999, Moon Lake, an electric utility in Roosevelt, UT,was fined $100,000 and placed on probation for three years after 17 hawks and eagles wereelectrocuted on Moon Lake’s power lines. Moon Lake’s penalty also included retrofitting its utility linesto make them safe for birds, which created a significant additional financial burden.1 In 2009,PacificCorp, another large electric utility, was fined $510,000, in addition to $900,000 in restitution, afterkilling 232 eagles on power lines. PacificCorp was also placed on probation for five years.2

SCE’s company wide Avian Protection Plan (APP) requires reporting of all bird mortality and nest issuesto the avian protection specialist or an SCE biologist. This plan has been shared with USFWS and so theyare aware of SCE’s internal policies regarding avian mortality. Tracking of these incidents throughEHSync would maintain compliance with SCE’s APP and provides a compliance process to share withUSFWS demonstrating how we comply with our own policy.

This project will also support SCE’s ability to comply with General Order 131D (GO131D) in anautomated manner. CPUC requires SCE to comply with GO 131 regulations for all work 50kV and above.The Corporate Environmental department is responsible to evaluate and process project work requestsfor GO131D projects and manually manages approximately 130 GO131D projects per year, affectingabout 200 potential users and 15 touchpoints/handoffs across multiple organizations.

GO131D projects are equal to or greater than 50kV and involve these types of activities but not limitedto:

1 US Department of Justice. “Electric Utility Sentenced for Killing Eagles and Hawks: Criminal Case is First of its KindUnder Federal Wildlife Law.” (August 12, 1999).2 “Electrocuting Eagles Costs PacificCorp $10.5 Million.” Environment News Service (July 14, 2009).

372



INVESTMENT MEMO

(3 of 4)

1. Replacement of existing power line facilities or supporting structures with equivalent facilities orstructures

2. Minor relocation of existing power line facilities up to 2,000 feet in length, or the intersetting ofadditional support structures between existing support structures

3. Conversion of existing overhead lines to underground4. Placing of new or additional conductors, insulators, or their accessories on existing structures,

power lines, or substations to be relocated or constructed which have undergone environmentalreview pursuant to California Environmental Quality Act (CEQA) as part of a larger project, andfor which the final CEQA document finds no significant, unavoidable environmental impactscaused by the proposed line or substation

5. Power line facilities or substations to be located in an existing franchise, road widening setbackeasement, or public utility easement; or in a utility corridor designated, precisely mapped andofficially adopted pursuant to law by federal, state or local agencies for which a final NegativeDeclaration or EIR finds no significant, unavoidable environmental impacts

Incorporation of GO131D would provide digital automation of processes to provide transparency to theoperating units, improve accuracy and reliability of project information, and enhance efficiencies withproject handoffs and tracking.

Additional information is also required by The California Coastal Act of 1976 for activities within thecoastal zone under the jurisdiction of CA Coastal Commission or other local jurisdictions (i.e. City orCounty) with an adopted Local Coastal Plan. The coastal zone area affects several T&D Regions andDistricts and could affect over 3,000 projects annually.

The enhancements for GO131D and coastal zone processes are interdependent. Coastal zone processesare also applicable to non GO131D projects currently using Environmental Clearance.

The current process poses the following challenges:1. Lack of systematic process and approvals for projects in the coastal zone may result in project

delays to perform work activities providing system reliability and safety.2. Auto clearance function requires enhancement to improve accuracy of business rules to

mitigate risk.3. Lack of automated system to consistently track and efficiently manage GO131D projects to

reduce manual and redundant project tracking and improve operational performance andaccountability.

4. Redundant automated and manual environmental processes inside and outside of EHSync thatare not fully integrated with other OU project tracking systems.

5. Limited GIS information to support enhancements to provide improved accuracy of screeningand associated workflow logic.

6. Current data visibility and reporting is limited and will need to improve to demonstratecompliance assurance with system controls and data assessment of enhancements.

D. Anticipated Business Outcomes & BenefitsThe overall objective of this project is to automate the process of tracking/reporting avian incidents andimprove the efficiency and accuracy of the current implementation of the environmental clearanceprocess by incorporating other compliance processes with the Environmental Screening Form.

373



INVESTMENT MEMO

(4 of 4)

The Avian incident type would provide the ability to generate electronic guided activity forms (GAFs)containing questions relevant to the specific type of incident being reported. The information will beavailable in EHSync and in ArcGIS. It is expected that an average of 400 incident forms will be submittedeach year by users in the field. An additional 100 incidents are expected to be submitted by AvianAdministrators.

The automation of the additional work clearances will improve efficiency and accuracy, minimizecompliance risk, and provide automated handoffs in a centralized system for a more complete range ofOU client planned projects (Transmission, Distribution, Substation, and Carrier Solutions). This includesstreamlining the steps for when and how client OUs complete the required forms, optimizing the autoclearance process, improving data accuracy, reducing data redundancy, improving data visibility, andimproving usability.E. Business Impact AssessmentThis effort impacts the following strategic business capabilities:

1. Environmental Compliance Management – Regulatory Incident Management,2. Environmental Compliance Management – Regulatory Environmental Clearance, and3. Asset Management – Grid Operations.


This effort will leverage the existing capabilities within EHSync including:

1. New incident type for Avian;2. Mobile application for capturing incidents in field;3. BI extractor/reports/dashboards for reporting purposes;4. Interface to GIS for plotting avian incidents;5. New change request types for coastal and G131D; and6. BI extractor/reports/dashboards for reporting purposes.

This project will leverage the existing EHSync capabilities toward the purpose of creating an enterprisewide tool for all Safety/Compliance incidents and Environmental Clearances. This option supportsarchitecture’s strategic approach for EHSync, BI and GIS technologies.G. Proposed Options

The options evaluated were:1. Incorporate avian into EHSync as a new incident type and additional work clearances. Update BI

extractors, reports and dashboards to include new incident type along with an interface to GISto plot the incident locations for reporting purposes. (Recommended Option)

2. Develop custom application for tracking avian incidents and corrective actions.3. Add additional personnel to track Avian and Work Clearances.

374



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Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 6/1/2016


Year350

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

350


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

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2020

Total

Facilities Management System

The initial scope of the FMS project was to integrate and leverage: 1. Core SAP functionality; 2. Space Planning and Move Management functionality from Archibus;

This business initiative will enable OpX goal for Corporate Real estate to move to Managed service provider for Facilities management and reduce CRE operating cost by 21% over 5 years (approximately $42 million)

Facilities Management System

376



INVESTMENT MEMO

(0 of 2)


Facilities ManagementSystem

377



(1 of 2)

I. Business Initiative DescriptionA. Initiative NameFacility Management Solution (FMS)B. Initiative DescriptionCRE intends to select and contract with an Integrated Facilities Management provider to provide FacilitiesManagement Services throughout their portfolio of owned and occupied sites

Historically, CRE has relied upon both external suppliers and internal staff to manage and coordinate its facilitiesmanagement activities. Edison believes that experienced, facilities management integrators may offer theopportunity to leverage existing resources and implement improved operating practices so as to deliver theServices more efficiently and effectively, and to facilitate the transformation of Edison’s current deliverymanagement model to a more efficient, cost effective and responsive model.C. Business Strategic AlignmentCorporate Real Estate is looking at opportunities to shift facilities management and janitorial servicesmanagement to a third party vendor to gain operational efficiencies and reduce cost. In order to enable this theManaged services provider will be providing SCE with a portal to log incidents and view performing metrics andalso mobile app capabilities to simplify incident reporting. SCE is expected to exchange necessary data like nonsensitive HR information, GL accounts, user ids, space management, facility condition index, buildingmanagement to enable this integration. The Service Provider’s technology solution will be used as a commonplatform to house data and manage processes for the Services.

Current State: The Facility Management RFP agreement identifies Space Management (Archibus)as being out of scope for the MSP and retained by SCE

ProblemStatement:

The existing Archibus solution is outdated, has data quality issues, and is on anunsupported version.

Key Assumptions: • Technical development work will commence no later than 12/1/2015• Upgraded cloud hosted Archibus will be enabled as part of this project to gain

Efficiencies in Space management and better integration with SAP.• The original FMS had a site survey component, which is not being addressed

within this scope

D. Anticipated Business Outcomes & BenefitsListed below are the outcomes expected with this collaboration.a) Reduce technology landscape by leveraging MSP systems b) Leverage MSP tools and technology to enable predictive maintenance c) Support goal for Corporate Real estate to move to Managed service provider d) Support solution that will evolve to remain current with industry best practices throughout the term of

the Agreement e) Leverage upgraded Archibus system for space management efficiencies and better integration with SAP.

378



INVESTMENT MEMO

(2 of 2)

E. Business Impact AssessmentThis initiative supports Business need to shift facilities management and janitorial services management to athird party vendor to gain operational efficiencies.


The high level integration requirements are as follows:1. HR data to and from SAP HR to Archibus

Non sensitive contact information like PAX, cell, email etc.location information such as building and cubeSpace/ position status

2. Financial Data (Requirement 10)Chart of Accounts, Cost center and work order

3. Onboarding and off boarding from SAP to ArchibusPosition information and status

4. SCE Portal to MSP Portal and Archibus single sign on5. SAP ECC enhancements to improve space accuracy quality from 70% to 100%

Functional location update based on statusPosition and notification update on closing a service request

G. Proposed OptionsOption 1: Take FMS off hold and complete the necessary remaining work.Option 2: Adopt the third party (FMP) hosted Archibus solution (Recommended implementation option)

379



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Pin #: 7821


2. PROJECT DETAIL:






5. CLOSE DATE: 6/1/2016


Year620

0

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

620


2016 2017 2018 2019 2020






SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Safety Observations

SCE’s safety program includes capturing and recording safety observations and identifying corrective actions through a consistent process across the entire organization.

Decommisioning six disparate Operating Unit (OU) specific Safety Observation programs/systems and consolidating into one system.

Safety Observations

381



INVESTMENT MEMO

(0 of 2)


Safety Observations

382



(1 of 2)

I. Business Initiative DescriptionA. Initiative NameEnterprise Wide Safety ObservationsB. Initiative DescriptionSafety is a top priority at SCE. We are committed to strengthening our safety culture to achieve an injury freeworkplace. We are creating and sustaining a working environment that is built around the following objectives:

Having every employee leave the workplace unhurtUsing work behaviors and practices that uncompromisingly protect the safety of everyoneCaring for the safety of everyone, andStopping work anytime unsafe conditions or behaviors are observed until the job can be completedsafely.

To support these corporate strategic objectives, CEHS is committed to improving SCE's environmental, healthand safety performance. The following leading indicators are used to measure the progress of the company andhelp reduce safety incidents:

1. Close Calls2. Safety Observations3. Percentage of Corrective Measures Completed on Time4. Vehicle Incidents5. Switching/Testing/Operating Incidents6. Equipment Failure7. Wire/Conductor Incidents

C. Business Capabilities MappedSafety Incident ManagementD. Desired Business OutcomesIn support of the second and third leading indicators, SCE’s safety program includes capturing and recordingsafety observations and identifying corrective actions through a consistent process across the entireorganization. The benefits of a consistent safety observation process include:

Identifying unsafe behaviors to prevent accidents from occurring.Promoting the identification of corrective actions (physical controls, procedures, training, OCM,education).Reinforcing SCE’s safety culture.Implementation of enterprise wide Safety Observation program defining a standard single processfor capturing and monitor observations and related corrective actions. Resulting in a reduction ofresources maintaining multiple observation applications across the operating units.Ability to identify and report on Corrective Actions to ensure timely completion and perform trendanalysis for implementation of preventative measures.

383



INVESTMENT MEMO

(2 of 2)

Creation of dashboard for Safety Observations and Corrective Actions across enterprise forreporting to Senior Safety Council on the observations/corrective actions across operating unitsalong with trend analysis.Retirement of the six disparate Operating Unit (OU) specific Safety Observation programs/systemsto reduce applications being used across the operating units for observations using a phasedapproach.Ability for OU personnel to re direct time currently spent support OU Safety programs/systems toother meaningful work for personnel supporting RSE and LETS.Increase close calls by reporting on observations/corrective actions and leading indicators.

E. Business Priorities & ConcernsToday, SCE uses the following platforms to capture and record safety observations within multiple OperatingUnits (OUs):

LETS (SONGS)RSE (PPD)Access Database with Java Entry Module (T&D)Offline form with batch upload capabilities (T&D)SharePoint (HR)Microsoft Excel Templates (T&D)Corporate Observation Cards (all OUs)Safety Observations using Build SharePoint InfoPath Form (T&D)

This situation poses the following challenges across the enterprise:No enterprise wide method to track occurrences of observations.Lack of company wide reporting and trending analysis to identify process improvements.Inconsistent processes limiting our ability to measure safety observations across the enterprise andimplement lessons learned.Lack of visibility to safety performance.Inability to consistently record corrective actions and ensure their completion.Redundant use of resources maintaining multiple safety observation processes and systems.Not an efficient safety observation platform that covers all types of work.

384



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385



0200400600800

1,0001,2001,4001,6001,800



Pin #: 3896


2. PROJECT DETAIL:






5. CLOSE DATE: 12/1/2018


Year1,700

1,000

0

0

SCE $

0



8. SCOPE:

9. JUSTIFICATION:

Various (See Below)


6. RIIM ELIGIBLE:

2,700


2016 2017 2018 2019 2020







SCE-04, Vol. 02IT


2016

2017

2018

2019

2020

Total

Ariba Deployment and Supplier Portal Dec

This initiative is intended to support decommissioning of Supplier Portal systems currently used in SCE’s Plan to Pay process with a standard set of SAP solutions (including ARIBA,Fieldglass etc) todeliver equivalent core functionality to support Enterprise Technology Optimization goals.

Realize ETO gains by moving out of a highly customized Supplier Portal to standardized technologyplatform where bulk of the capabilities is in the Cloud.

Ariba Deployment and Supplier Portal Dec

386



INVESTMENT MEMO

(0 of 4)


Ariba Deployment andSupplier PortalDecommission

387



(1 of 4)

I. Business Initiative DescriptionA. Initiative NameSupplier Portal DecommissioningB. Initiative DescriptionThis initiative is intended to support decommissioning of Supplier Portal systems currently used in SCE’s Plan toPay process with a standard set of SAP solutions specifically ARIBA and Fieldglass. We would also be enablingnew vendors in ARIBA module to bring certain supplier portal vendors into ARIBA. In addition we would enablethe foundational elements of Supplemental Workforce onboarding leveraging standard Fieldglass functionality.

Ariba provides a robust on line market place connecting buyers and suppliers, as well as leading Procure to Payfunctionality that integrates SAP with the market place. Fieldglass provides capabilities in the areas of serviceprocurement including timesheets as well support Supplemental workers onboarding processes. In addition wewould be enabling work management related capabilities to support the planning collaboration processes withthe vendors.

The scope of the project named “Supplier Portal Decommissioning” would include the following Keydeliverables:

1) Transition key Supplier Portal business capabilities into a standard SAP suite of solutions by deployingcapabilities in Fieldglass, ARIBA and Fiori.

2) Deliver Onboarding Capabilities as part of the Fieldglass solution deployment.3) Change Management to help rollout deployed ARIBA Capability across operating unit at an enterprise

level thereby leverage savings and efficiencies of adopting a cloud based procurement solution.

This request for Capital funding to deliver on capabilities 1) and 2) to be delivered across 2016 and 2017 and tohelp support Change Management (capability 3) ) to enable additional SCE suppliers in Ariba as per thedeployment roadmap.

The Key Drivers behind this initiative is to drive outcomes ona) Align the complex services environment in standard & integrated SAP driven approach.b) Address gaps that currently existing in SAP & ARIBA as it relates to complex services procurement.c) Address gaps with the Supplemental Workforce Onboarding processes leveraging Fieldglass technology.d) Rollout ARIBA Capabilities per ARIBA Business case 2013 to leverage savings on sourcing, compliance &

cash management. C. Business Strategic AlignmentThe goal of this project is to generate additional savings for SCE across the Plan to Pay process by adopting theAriba Solution Set and enabling Fieldglass with additional technologies to support Supplier Portaldecommissioning. The Ariba and Fieldglass platform brings strong sourcing and Procure to Pay capabilities forboth materials and services. The implementation of the Ariba platform will allow SCE to adopt more commonand efficient processes across Operating Units and a majority of spend.

Ariba provides an extensive 3rd party on line marketplace in which both buyers and suppliers participate. Byadopting the Ariba platform, SCE will more easily integrate with a majority of its suppliers, expanding its levelautomation / integration with its supply base.

388



INVESTMENT MEMO

(2 of 4)

Implementation of a centralized Complex services management system) aligns with the Management & controlof services and would increase efficiencies across work management, service procurement & accounts payableprocesses. The solution automates many processes and eliminates manual work ensures better control ofquality, costs, efficiency and risk. In addition implementation of Fieldglass enables capabilities in SupplementalWorkers onboarding.

Strategically, implementing the Ariba and Fieldglass platform aligns with IT’s long term strategy to optimize itsportfolio by reducing the size, complexity and cost. Ariba’s Network is projected to be the single SAP businessplatform for collaborative commerce for procurement and finance. Additionally, SAP plans to add Supply Chain,Transportation Management, Information Interchange functionality, bi directional integration from Master DataGovernance for Suppliers (MDG S), and key Supplier Self Service capabilities to the Ariba Network. Theseenhancements by SAP are seen as enablers of IT’s long term strategy to consolidate the solution it offers onfewer systems.D. Anticipated Business Outcomes & BenefitsContinued operational Savings on using ARIBA (Capability 3)

1. Reduced pricing through use of improved sourcing capabilities2. Improved user and vendor compliance and use of optimized pricing3. Cash Management savings through increased vendor discount capture

Benefits from Supplier Portal Decommissioning (Capability 1 and 2)a) Hardware Cost savings by decommissioning of 160 Servers (33% of SAP Landscape).b) Core Refresh Cost Avoidance periodically (once in 5 years).c) Improvements within the SCE Procure to pay processes through increased automation. Actual

value to be determined through process design within the project.d) Long term alignment with SAP strategic development, and reduced reliance on in house

solutions, simplifying the IT infrastructure / portfolio.E. Business Impact Assessment

This initiative fundamentally changes the solution from Supplier Portal to a Future state that aims to providesimilar capabilities along with operational improvements with the current process.Organizational change management (OCM) effort is required to migrate SAP process to Cloud basedstandard process within standard capabilities of the Future state solutions. Many of the current process aredeeply ingrained, and assumed within organizational structural design and procedures.Supplier willingness to participate in the Ariba on line market place as well as Fieldglass is critical. Whilethe Ariba market place is large, the percentage of SCE's suppliers already participating is not yet known.Enrollment and subscription fees may be a consideration for some suppliers. In addition, a significant effortis required to onboard suppliers to SCE’s Ariba solution. Delays or obstacles in the onboarding process willslow benefits realization.Depending on the deployment approach, enablement of the new capability in Fieldglass and ARIBA may gohand in hand with decommissioning of Supplier portal leading to an overlap for a short period of time.OCM changes with the HR organization to align their process with standard capabilities offered by theFieldglass solutions.

389



INVESTMENT MEMO

(3 of 4)

F. Technology/Automation RationaleOnboarding efficiency – Moving away from current manual onboarding process for Supplemental workerswould improve the cycle time from X days to Y thereby improving efficiencies across the board by ensuringtimely availability of resources for initiatives & projects.

Plan to pay and Work Management initiatives As the various businesses are charted to reduce costs, theyare increasingly seeking to increase the level of integration with suppliers. Within material P2P processes,the business is seeking stronger reliance on supplier capabilities, resulting in a greater need for tools tointegrate SCE and suppliers (e.g. EDI and XML). Additionally, many organizations examine the work currentlyperformed internally; many are seeking to move this work to external service providers, increasing the needand for external integration to suppliers. The Ariba and Fieldglass platform provides a much more robustplatform for integrating with suppliers and supporting these initiatives.

IT Portfolio Simplification IT has commitments to reduce the complexity of the portfolio, which currentlyincludes multiple solutions, and a growing demand from other initiatives within the P2P scope. In order toaccomplish this goal, IT needed a stronger common solution set to concurrently accommodate the businessneed for greater efficiency, while reducing the number of solutions it supports. Adopting Ariba andFieldglass's industry leading solutions provides a much more robust common platform and easier integrationacross the external partners. As a result of this project, IT is expected to have a stronger common platformfor accommodating business need for greater efficiencies, while decommissioning existing solutions whereviable. Because IT will be aligned with SAP investment strategy, continued investment will allow furtherdecommissioning, as well as SCE to adopt new capabilities as they are developed.

G. Proposed OptionsThe scope of the project named “Supplier Portal Decommissioning” would include the following Keydeliverables,

1) Transition key Supplier Portal business capabilities into a standard SAP suite of solutions bydeploying capabilities in Fieldglass, ARIBA, SAP and Fiori.

2) Deliver Onboarding Capabilities as part of the Fieldglass solution deployment.3) Change Management to help rollout deployed ARIBA Capability across OU’s at an enterprise

level thereby leverage savings and efficiencies of adopting a cloud based procurement solution. The first deliverable would be completed by:

a) Adopting Fieldglass for Service & Time Management capabilities.b) Enabling Key Capabilties in SAP ECC, ARIBA, Fieldglass and FIORI.c) Deploying Plan to pay capabilities including Work management by leveraging standard capability

of SAP products as well as some customization to connect work management objects like TaskOrder Fieldglass with a combination Fiori technologies with SAP.

d) Enabling supporting capabilities such as Vendor/Internal user administration, attachments,catalogs & reporting.

e) Transition related capabilities like Vehicle Ordering into the new future state solution.f) Rollout the capabilities across the targeted OU’s.g) Decommission Hardware supporting these capabilities.

The second deliverable would be completed by:a) Adopting Onboarding capabilities within Fieldglass for Supplemental workforce (including

Contingent workers, independent contracts, SOW workers as well as Badge only).

390



INVESTMENT MEMO

(4 of 4)

b) Enable requirements related to Onboarding. This includes leverage existing capabilities withinFieldglass and ARIBA with new capabilities enabled by Onboarding.

a. Create and track record of supplemental workers and assignments in Fieldglass by laborcategory type: SOW Consultant, Contractor, Independent Consultant, Badge Only

b. Enable the onboarding and off boarding process and track status in system.c. Visibility to vendor profiles and contact information.d. Ability to track the workers rehire eligibility status, history of all projects and

assignments. (active & historical), training (current/past training records)e. Ability to edit records and audit trail of edits, trigger notifications & reminders and

handle exceptions.f. Store supporting documents like Statement of work, resumes, Non disclosure

agreement.g. Streamlined Intake process to determine SW type and labor classification and kicking off

the appropriate requisition process including approval processes.h. Trigger space & asset management requestsi. Reporting

Enablement of deliverables 1 and 2 is expected to ensure the Contingent Worker onboarding,maintenance & tracking various statuses would span across business process cycles starting fromrequisitioning process, identification of resources & assignments as well trigger requests to BMCRemedy tools for provisioning of assets and Invoicing.

Deliverable 3 (Change Management for ARIBA) would be completed by:Continuing the effort initiated in 2015 to rollout the ARIBA capability across multiple OUs.

391



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