STATE OF CALIFORNIA GAVIN NEWSOM, Governor PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3298 FILED 04/12/19 03:17 PM April 12, 2019 Agenda ID #17375 Ratesetting TO PARTIES OF RECORD IN APPLICATION 16-09-001: This is the proposed decision of Administrative Law Judges Roscow and Wildgrube. Until and unless the Commission hears the item and votes to approve it, the proposed decision has no legal effect. This item may be heard, at the earliest, at the Commission’s May 16, 2019, Business Meeting. To confirm when the item will be heard, please see the Business Meeting agenda, which is posted on the Commission’s website 10 days before each Business Meeting. Parties of record may file comments on the proposed decision as provided in Rule 14.3 of the Commission’s Rules of Practice and Procedure. The Commission may hold a Ratesetting Deliberative Meeting to consider this item in closed session in advance of the Business Meeting at which the item will be heard. In such event, notice of the Ratesetting Deliberative Meeting will appear in the Daily Calendar, which is posted on the Commission’s website. If a Ratesetting Deliberative Meeting is scheduled, ex parte communications are prohibited pursuant to Rule 8.2(c)(4)(B). /s/ MICHELLE COOKE for Anne E. Simon Chief Administrative Law Judge AES:jt2 Attachment 278065120 ALJ/SCR/EW2/jt2 PROPOSED DECISION Agenda ID #17375 Ratesetting Decision PROPOSED DECISION OF ALJs ROSCOW and WILDGRUBE (Mailed 4/12/2019) BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Application of Southern California Edison Company (U338E) for Authority to Increase its Authorized Revenues for Electric Service in 2018, among other things, and to Reflect that increase in Rates. Application 16-09-001 DECISION ON TEST YEAR 2018 GENERAL RATE CASE FOR SOUTHERN CALIFORNIA EDISON COMPANY 277268180 -1– PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents Title Page DECISION ON TEST YEAR 2018 GENERAL RATE CASE FOR SOUTHERN CALIFORNIA EDISON COMPANY ..................................................... 1  Summary ............................................................................................................................ 2  1.  Factual Background ................................................................................................. 3  1.1.  Procedural Background................................................................................ 4  1.2.  Settlements ..................................................................................................... 6  2.  Evidentiary Standards and the Burden of Proof ................................................. 6  3.  Affordability .............................................................................................................. 7  3.1.  Affordability and “Just and Reasonable” Rates ....................................... 9  3.2.  SCE’s Capital Expenditure Request ......................................................... 12  3.3.  Our Decision-Making Framework............................................................ 15  3.4.  Recent Statutes and Commission Rulemakings Regarding Affordability................................................................................................. 21  4.  Transmission and Distribution............................................................................. 24  4.1.  T&D – General ............................................................................................. 24  4.1.1.  Operational Overview .......................................................................... 26  4.1.2.  Risk-Informed Decision Making ......................................................... 27  4.1.3.  Safety and Reliability Investment Incentive Mechanism ................ 27  4.2.  T&D – Customer-Driven Programs .......................................................... 29  4.2.1.  New Service Connections ..................................................................... 30  4.2.1.1.  Residential Line Extensions ............................................................ 32  4.2.1.2.  Residential Tract Development ...................................................... 34  4.2.1.3.  Residential Backbone Development .............................................. 35  4.2.1.4.  Commercial/Industrial Service Connections and Tract Development ..................................................................................... 37 4.2.2.  Rule 20 Issues ......................................................................................... 38  4.2.3.  Distribution Transformers .................................................................... 41  4.3.  T&D – System Planning ............................................................................. 43  4.3.1.  Photovoltaic (PV) Dependability and Capacity-Driven Capital Expenditures........................................................................................... 46  4.3.2.  Distribution Circuit Upgrades ............................................................. 50  4.3.3.  New Distribution Circuits .................................................................... 51  4.3.4.  Substation Expansion Projects ............................................................. 52  4.3.5.  Substation Equipment Replacement Program .................................. 53  4.3.6.  Subtransmission Lines Plan ................................................................. 54  -i- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title Page 4 kV Programs ........................................................................................ 55  4.3.7.  4.3.7.1.  4 kV Cutover Program .................................................................... 56  4.3.7.2.  4 kV Substation Elimination Program .......................................... 58  4.3.8.  Grid Reliability Projects ........................................................................ 61  4.4.  T&D – Distribution Maintenance and Inspection .................................. 62  4.5.  T&D – Distribution Construction & Maintenance ................................. 63  4.6.  T&D – Substation Construction & Maintenance .................................... 66  4.7.  T&D – Transmission Construction & Maintenance ............................... 68  4.7.1.  Transmission Overhead and Underground Line Maintenance – FERC Account 571.150 (partial) ........................................................... 69  4.7.2.  Transmission Vegetation Management – FERC Account 571.150 (partial) .................................................................................................... 69  4.7.3.  Transmission Tools and Work Equipment ........................................ 70  4.8.  T&D – Infrastructure Replacement .......................................................... 72  4.8.1.  Worst Circuit Rehabilitation Program ................................................ 74  4.8.2.  Cable Life Extension Program ............................................................. 76  4.8.3.  Cable-In-Conduit Replacement Program .......................................... 76  4.8.4.  Overhead Conductor Program ............................................................ 77  4.8.5.  Underground Oil Switch Replacement Program.............................. 81  4.8.6.  Capacitor Bank Replacement Program .............................................. 82  4.8.7.  Automatic Recloser Program ............................................................... 83  4.8.8.  PCB Transformer Replacement Program ........................................... 83  4.8.9.  Substation Infrastructure Replacement Program ............................. 83  4.8.10.  Conclusion: Adopted Infrastructure Replacement Program Capital Expenditures............................................................................. 85  4.9.  T&D – Poles .................................................................................................. 85  4.9.1.  O&M Expenses ....................................................................................... 86  4.9.2.  Capital Expenditures............................................................................. 90  4.9.3.  Pole Loading and Deteriorated Pole Programs Balancing Account ................................................................................................... 91  4.10.  T&D – Grid Modernization ....................................................................... 91  4.10.1.  Grid Modernization Capital Expenditures ........................................ 96  4.10.1.1.  Distribution Automation Programs .............................................. 96  4.10.1.2.  Communications ............................................................................ 103  4.10.1.3.  Tools for Data Analysis and Decision-Making .......................... 105  - ii - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title 5.  Page System Modeling Tool (SMT) ................................................. 106  4.10.1.3.1.  4.10.1.3.2.  DRP External Portal ................................................................. 106  4.10.1.3.3.  Grid Management System ....................................................... 106  4.10.2.  Grid Modernization O&M Expenses ................................................ 107  4.10.2.1.  Intervenors’ Positions .................................................................... 107  4.10.2.2.  SCE’s Rebuttal to Intervenors’ Positions .................................... 107  4.11.  T&D – Grid Technology ........................................................................... 108  4.11.1.  Distribution Volt VAR Control .......................................................... 108  4.11.2.  Equipment Demonstration & Evaluation Facility .......................... 109  4.11.3.  Energy Storage Pilots .......................................................................... 109  4.12.  T&D – Safety Training & Environmental Programs ............................ 112  4.12.1.  Environmental Program – Transmission (Acct. 565.281)............... 113  4.12.2.  Hazardous Waste Management & Disposal – Distribution (Acct. 598.250)....................................................................................... 113  4.13.  T&D – Other Costs, Other Operating Revenues .................................. 115  Customer Service .................................................................................................. 119  5.1.  Customer Service – O&M ........................................................................ 119  5.1.1.  The Impact of Customer Growth ...................................................... 119  5.1.2.  Metering Services................................................................................. 120  5.1.2.1.  Meter Reading Operations – FERC Account 902 ...................... 120  5.1.2.2.  Test, Inspect, and Repair Meters – FERC Account 586.400 .............................................................................................. 120  5.1.2.3.  Turn-On and Turn-Off Services – FERC Account 586.100 .............................................................................. 121  5.1.2.4.  Customer Installation and Energy Theft Expense – FERC Account 587 ..................................................................................... 121  5.1.2.5.  Meter Services Operations and Management – FERC Account 580 122  5.1.3.  Revenue Services Organization ......................................................... 123  5.1.3.1.  Billing Services – FERC Account 903.500 ................................... 123  5.1.3.2.  Credit and Payment Services – FERC Account 903.200 ........... 126  5.1.3.3.  Postage – FERC Account 903.100 ................................................. 126  5.1.3.4.  Uncollectable Expenses – FERC Account 904 ............................ 127  5.1.4.  Customer Contact Center – FERC Account 903.800 ....................... 128  5.1.5.  Business Customer Division – FERC Account 908.600 .................. 128  - iii - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title Page Customer Programs and Services – FERC Account 905.900 ......... 129  Operating Unit Management and Support – FERC Accounts 901 and 907.600 ........................................................................................... 130  5.2.  Customer Service – Capital ...................................................................... 131  5.3.  Customer Service – Other Operating Revenue ..................................... 132  5.4.  Customer Service – Additional Issues ................................................... 132  Information Technology ...................................................................................... 136  6.1.  Information Technology – O&M and Hardware.................................. 137  6.1.1.  Hardware/Software Licenses & Maintenance ................................ 137  6.1.2.  Business Integration & Delivery ........................................................ 137  6.1.3.  Grid Services......................................................................................... 139  6.2.  Information Technology – Capitalized Software ................................. 140  6.2.1.  Contingency Amounts in Capitalized Software Forecasts ............ 140  6.2.2.  Cybersecurity and Compliance ......................................................... 144  6.2.3.  Grid Modernization Cybersecurity ................................................... 145  6.2.4.  Other Capitalized Software ................................................................ 145  6.2.4.1.  Vegetation Management Project .................................................. 145  6.2.4.2.  Comprehensive Situational Awareness for Transmission ...... 146  6.2.4.3.  Grid Planning & Analytics Software ........................................... 147  6.2.4.4.  Enterprise Content Management Project.................................... 148  6.2.5.  Operating System Software................................................................ 149  6.3.  Information Technology – Customer Service Re-Platform ................. 150  6.4.  Information Technology – SCE’s Use of Managed Services Providers ...................................................................................................................... 152  Generation ............................................................................................................. 153  7.1.  Generation – Nuclear Generation (Palo Verde) .................................... 153  7.2.  Generation – Energy Procurement ......................................................... 154  7.3.  Generation – Hydro Generation ............................................................. 154  7.4.  Generation – Catalina ............................................................................... 154  7.4.1.  Catalina – O&M ................................................................................... 154  7.4.2.  Catalina- Pebbly beach Generating Station Automation ............... 154  7.4.3.  Catalina – Other Capital Projects Under $3 Million ....................... 158  7.5.  Generation - Other .................................................................................... 159  7.5.1.  Mountainview ...................................................................................... 159  7.5.2.  Peakers .................................................................................................. 160  5.1.6.  5.1.7.  6.  7.  - iv - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title 8.  9.  Page Mohave Closure ................................................................................... 160  7.5.3.  7.5.4.  Solar Photovoltaic ................................................................................ 160  7.5.5.  Fuel Cells ............................................................................................... 161  Human Resources ................................................................................................ 161  8.1.  Human Resources Department and Executive Officers ...................... 165  8.1.1.  Human Resources Operating Unit .................................................... 166  8.1.2.  Executive Officers ................................................................................ 166  8.1.3.  Adopted Forecasts for SCE’s Human Resources Department and Executive Officers ................................................................................ 169  8.2.  Benefits and Other Compensation .......................................................... 170  8.2.1.  Short-Term Incentive Program .......................................................... 172  8.2.2.  Long-Term Incentives ......................................................................... 178  8.2.3.  Recognition Programs ......................................................................... 179  8.2.4.  Pension Costs ....................................................................................... 180  8.2.5.  Medical Programs ................................................................................ 181  8.2.6.  Executive Benefits Program ............................................................... 183  8.2.7.  Adopted Forecasts for Benefits and Other Compensation ............ 184  8.3.  Human Resources – Total Adopted Forecast........................................ 186  Operational Services ............................................................................................ 186  9.1.  Business Resiliency ................................................................................... 186  9.2.  Corporate Environmental Services ......................................................... 187  9.3.  Corporate Real Estate ............................................................................... 188  9.3.1.  CRE O&M ............................................................................................. 189  9.3.2.  CRE Capital .......................................................................................... 189  9.3.2.1.  Service Center Modernization Program ..................................... 191  9.3.2.1.1.  General Disagreements between SCE and TURN ............... 195  9.3.2.1.2.  Bishop Service Center .............................................................. 199  9.3.2.1.3.  Kernville Service Center .......................................................... 201  9.3.2.1.4.  Redlands Service Center .......................................................... 203  9.3.2.1.5.  Ridgecrest Service Center ........................................................ 205  9.3.2.1.6.  San Joaquin Service Center ..................................................... 207  9.3.2.1.7.  Santa Ana Service Center ........................................................ 209  9.3.2.1.8.  Santa Barbara Service Center .................................................. 212  9.3.2.1.9.  Barstow Service Center ............................................................ 213  9.3.2.1.10.  Blythe Service Center ............................................................... 214  -v- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title Page Shaver Lake Service Center ..................................................... 214  Operational Support Program ..................................................... 215  Infrastructure Upgrade Projects ............................................. 216  Substation Maintenance and Test Buildings (Substation Reliability Upgrades) ............................................................... 217  9.3.2.2.3.  Facility Repurpose Projects ..................................................... 217  9.3.2.2.4.  Projects Less Than $3 Million ................................................. 219  9.3.2.3. Blanket Capital Program ........................................................ 220  9.3.2.3.1.  Non-Electric Capital Maintenance ......................................... 221  9.3.2.3.2.  Substation Capital Maintenance............................................. 223  9.3.2.3.3.  Energy Efficiency ...................................................................... 225  9.3.2.3.4.  Ergonomic Equipment ............................................................. 225  9.3.2.3.5.  Ongoing Furniture Modifications .......................................... 226  9.3.2.3.6.  Various Major Structures......................................................... 226  9.3.2.3.7.  Conclusion: Approved Recorded and Forecast Blanket Capital Expenditures................................................................ 227  9.4.  Corporate Health and Safety ................................................................... 228  9.5.  Corporate Security .................................................................................... 229  9.6.  Supply Management ................................................................................. 231  9.7.  Supplier Diversity ..................................................................................... 232  9.8.  Transportation Services ............................................................................ 233  9.8.1.  Operating Costs ................................................................................... 233  9.8.1.1.  Non-Fuel Operating Costs ............................................................ 233  9.8.1.2.  Fuel Operating Costs ..................................................................... 234  9.8.2.  Capital ................................................................................................... 235  10.  Administrative & General ................................................................................... 236  10.1.  Ethics and Compliance ............................................................................. 236  10.2.  Regulatory Affairs ..................................................................................... 236  10.2.1.  Regulatory Affairs Labor: FERC Account 920/921 ....................... 236  10.2.2.  Regulatory Affairs – Integrated Planning Power Procurement: FERC Account 557 ............................................................................... 237  10.3.  Corporate Communications .................................................................... 237  10.3.1.  Corporate Communications Operations Labor: FERC Account 920/921 .................................................................................................. 237  10.3.2.  Corporate Communications – Outside Services: FERC Account 923238  9.3.2.1.11.  9.3.2.2.  9.3.2.2.1.  9.3.2.2.2.  - vi - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title Page 10.4.  Local Public Affairs ................................................................................... 238  10.4.1.  Local Public Affairs – FERC Account 920/921 ................................ 238  10.4.2.  Corporate Membership Dues and Fees – FERC Account 930 ....... 239  10.5.  Financial Services ...................................................................................... 241  10.6.  Audits .......................................................................................................... 242  10.7.  Enterprise Risk Management .................................................................. 243  10.8.  Legal ............................................................................................................ 244  10.8.1.  Removal of Costs Resulting from Alleged Imprudence ................ 244  10.8.2.  Law ........................................................................................................ 247  10.8.2.1.  In-House, FERC Accounts 920/921 ............................................. 247  10.8.2.2.  FERC Accounts 923/925/928 Outside Counsel ........................ 248  10.8.2.3.  FERC Account 930 Corporate Governance ................................ 249  10.8.3.  Claims .................................................................................................... 249  10.8.4.  Workers’ Compensation ..................................................................... 250  10.8.5.  Disability Program .............................................................................. 251  10.9.  Property and Liability Insurance ............................................................ 253  10.9.1.  Property Insurance .............................................................................. 253  10.9.2.  Liability Insurance ............................................................................... 253  11.  Ratemaking Proposals ......................................................................................... 253  11.1.  Establishment of the DER Deferred Project Memorandum Account (DERDPMA) .............................................................................................. 253  11.2.  Establishment of the Public Utilities Code § 706 SCE Officer Compensation Memorandum Account (SOCMA) .............................. 254  11.3.  Modification of the Pole Loading and Deteriorated Pole Programs Balancing Account (PLDPBA) ................................................................. 254  11.4.  Modification of the Safety and Reliability Investment Incentive Mechanism (SRIIM) .................................................................................. 254  11.5.  ORA’s Proposal to Establish a One-Way Storms Balancing Account255  11.6.  ORA’s Recommendation to Establish a Grid Modernization Memorandum Account ............................................................................ 255  11.7.  ORA’s Recommendation to Establish a DER Memorandum Account 256  11.8.  ORA’s Recommendation to Establish a Customer Service (CS) Re-Platform Memorandum Account...................................................... 256  - vii - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title 12.  13.  14.  15.  16.  17.  Page 11.9.  CALSLA’s Recommendation to Establish a Balancing Account to Record Tax Losses and Profits from Street Light Sales ....................... 257  11.10.  Uncontested Proposals for Memorandum Accounts and Balancing Accounts ..................................................................................................... 257  Jurisdictional Issues ............................................................................................. 259  Sales and Customer Forecast .............................................................................. 259  13.1.  Retail Electricity Sales ............................................................................... 260  13.2.  Customer Accounts and New Meter Connections............................... 261  Other Operating Revenues ................................................................................. 267  Cost Escalation ...................................................................................................... 268  Post Test Year Ratemaking ................................................................................. 269  16.1.  Summary of SCE’s Proposals .................................................................. 270  16.1.1.  Discussion ............................................................................................. 274  Rate Base Components ........................................................................................ 276  17.1.  Electric Plant .............................................................................................. 277  17.2.  Depreciation Expense ............................................................................... 277  17.3.  Taxes ............................................................................................................ 277  17.3.1.  The Tax Cuts and Jobs Act ................................................................. 277  17.3.2.  SCE Testimony: Impact of the Tax Cuts and Jobs Act .................. 278  17.3.2.1.  Revenue Requirement .................................................................. 278  17.3.2.2.  Accumulated Deferred Income Taxes ........................................ 280  17.3.2.3.  The Return to Ratepayers of Excess Deferred Income Taxes Does Not Violate IRS Normalization Rules ............................... 283  17.3.2.4.  Unprotected Assets ........................................................................ 287  17.3.3.  Other Tax Issues ................................................................................... 288  17.3.4.  The Impact on Rates ............................................................................ 289  17.4.  Rate Base ..................................................................................................... 291  17.5.  Customer Advances .................................................................................. 291  17.5.1.  Customer Advances – Electric Construction ................................... 292  17.5.2.  Customer Advances – Temporary Services ..................................... 293  17.6.  Material and Supplies ............................................................................... 293  17.6.1.  Generation M&S .................................................................................. 293  17.6.2.  T&D M&S.............................................................................................. 294  17.7.  Working Cash ............................................................................................ 294  17.8.  Lead Lag Study .......................................................................................... 294  - viii - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title 18.  19.  20.  21.  22.  23.  24.  Page 17.8.1.  Revenue Lag Days ............................................................................... 295  17.8.2.  Income Tax Lag .................................................................................... 296  17.8.3.  Fuel and Purchased Power Expense Lag ......................................... 297  17.8.4.  Other O&M Expense Lag (ISO Charges).......................................... 298  17.8.5.  Depreciation & Deferred Income Tax Lag ....................................... 298  17.9.  Customer Deposits .................................................................................... 299  17.10.  AFUDC ....................................................................................................... 300  17.11.  Rate Base Components – Additional Issues .......................................... 301  17.11.1.  Long-Term Incentives ......................................................................... 301  17.11.2.  Other Accounts Receivable ................................................................ 301  Depreciation Study............................................................................................... 301  18.1.  Foundational Overview ........................................................................... 304  18.2.  T&D Net Salvage ....................................................................................... 308  18.3.  Life ............................................................................................................... 309  18.3.1.  T&D Life ................................................................................................ 310  18.3.2.  Hydro Life............................................................................................. 311  18.3.3.  Solar Life ............................................................................................... 313  18.4.  Generation Decommissioning ................................................................. 313  18.5.  Depreciation Study – Additional Issues ................................................ 314  Rate Base – Additional Issues ............................................................................. 315  19.1.  Aged Poles .................................................................................................. 315  19.1.1.  SCE Has Not Presented Evidence Supporting Recovery .............. 316  19.1.2.  Other Disallowances From the 2015 GRC Decision ....................... 319  19.1.2.1.  Advanced Technology Laboratories ........................................... 319  19.1.2.2.  Pebbly Beach Automation ............................................................ 321  19.2.  2014-15 Capital Spending Above Authorized ...................................... 321  19.3.  Changes in Accounting ............................................................................ 323  19.4.  SPIDACalc Pole Issues ............................................................................. 325  19.5.  Correction for Shareholder Assigned Costs .......................................... 330  19.6.  Rate Base – Additional Issues .................................................................. 331  Results of Examination ........................................................................................ 333  Compliance............................................................................................................ 336  CEMA Bark Beetle Recovery .............................................................................. 337  CALSLA Issues ..................................................................................................... 337  Other Issues ........................................................................................................... 346  - ix - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Table of Contents (cont.) Title Page 24.1.  Tax Memorandum Accounts ................................................................... 346  24.2.  SCE Request for Oral Argument ............................................................. 349  25.  Conclusion ............................................................................................................. 349  26.  Comments on Proposed Decision ...................................................................... 349  27.  Assignment of Proceeding .................................................................................. 349  Findings of Fact ............................................................................................................. 349  Conclusions of Law ...................................................................................................... 391  ORDER ........................................................................................................................... 424  APPENDIX A - List of Acronyms APPENDIX B – Capitalized Software – Contingencies APPENDIX C – Results of Operations – 2018 - 2020 -x- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 DECISION ON TEST YEAR 2018 GENERAL RATE CASE FOR SOUTHERN CALIFORNIA EDISON COMPANY Summary This decision approves a test year revenue requirement of $5.102 billion for Southern California Edison Company (SCE) pursuant to its 2018 General Rate Case Application 16-09-001. The adopted amount is 9.55% lower than SCE’s request, but reflects our careful assessment and determination of the operating expenses and capital expenditures that are necessary for SCE to provide safe and reliable service at just and reasonable rates. The adopted 2018 revenue requirement shall become effective upon filing of tariffs pursuant to the directives of this decision. This decision also authorizes post-test year revenue requirement adjustments of $320 million for 2019 (a 6.3% increase) and $401 million for 2020 (a 7.4% increase). These adjustments provide funds necessary for SCE to continue to provide safe and reliable service to customers beyond the test year, while providing SCE a reasonable opportunity to earn the rate of return authorized by the Commission in Decision 17-07-005. The cumulative adopted effect on SCE’s revenue requirement over the 2018-2020 period, relative to present rates, is a 3.4% increase. The revenue requirement authorized in this decision does not include commodity costs of electricity procured for customers or costs of fuel used in generating electricity; these are addressed in a separate proceeding. The authorized amounts are less than SCE requested. SCE’s final updated 2018 revenue requirement request is $5.534 billion, representing a $22 million decrease relative to present rates. SCE requested attrition year increases of $431 million and $503 million for 2019 and 2020, respectively. SCE’s requested -2- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 cumulative increase by 2020, relative to present rates and inclusive of other adjustments, is 14.7%. A significant component of SCE’s request in this application is for capital expenditures, reflecting its proposals for long-term investments in its facilities. On a Total Company basis, SCE requests approximately $4.7 billion in capital expenditures during 2018 alone. The impact of current capital expenditures on current revenue requirements may be limited and incremental, but the cumulative impact is powerful over time as the value of the capital assets (including rate of return and cost of removal) is repaid by ratepayers. We approve approximately $3.86 billion of total capital expenditures, reflecting our judgement that the long-term benefits of these investments justify the costs. However, we also deny notable portions of SCE’s request for expenditures that SCE has not demonstrated are just and reasonable costs of safe and reliable service. Appendix C to this decision contains the detailed results of operations tables that summarize the annual GRC revenue requirements approved in this decision for 2018-2020, based on our decisions regarding the forecasted costs we find to be reasonable, and which are adopted in today’s decision. 1. Factual Background This is the General Rate Case (GRC) Phase 1 application of Southern California Edison Company (SCE). In Phase 1 of a GRC proceeding, the Commission determines the utility applicant’s electric system revenue requirements and addresses related issues. Phase 2 of the GRC follows a -3- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 separate application and addresses marginal cost, revenue allocation, and rate design matters.1 In this Phase 1 application, SCE originally requested an authorized base revenue requirement of $5.885 billion, effective January 1, 2018, representing an increase of $221 million over currently authorized levels.2 SCE requested further increases in 2019 and 2020 of $533 million and $570 million, respectively. SCE served updated testimony on December 8, 2017 and on February 16, 2018 served additional updated testimony addressing the impact of the Tax Cuts and Jobs Act (TCJA). With the latest update, SCE now requests a 2018 GRC revenue decrease of $22 million, 0.38% below the 2017 authorized GRC revenue requirement. SCE has also requested attrition year increases of $431 million and $503 million for 2019 and 2020, respectively. 1.1. Procedural Background On September 1, 2016, SCE filed its Application for authority to increase its authorized revenue, electric rates, and charges effective January 1, 2018. Protests or responses to SCE’s application were filed by the Office of Ratepayer Advocates (ORA),3 the Office of the Safety Advocates, The Utility Reform Network (TURN), Consumer Federation of California (CFC), National 1 The Phase 2 proceeding, A.17-06-030, was filed June 30, 2017. 2 SCE’s request for 2018 originally represented a total revenue increase of $313 million, 5.5% over currently authorized base rates prior to consideration of expected sales reductions and $48 million in other one-time balancing and memorandum account recoveries. 3 ORA was renamed the Public Advocates Office of the Public Utilities Commission pursuant to Senate Bill 854 in 2018. Because most of the pleading by this party were under the name of ORA, we utilize that name throughout the decision. -4- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Diversity Coalition (NDC), Solar Energy Industries Association (SEIA), City of Lancaster, and Alliance for Retail Energy Markets jointly with Direct Access Customer Coalition. Small Business Utility Advocates (SBUA) filed a motion for party status. Wald Street L.L.C., Tesla Business Center Owners Association, Inc., 38 Tesla, LLC, David Voo and Mary Voo, as Trustees of the Voo Trust, AKM Consulting Engineers, Inc., and Spyglass Tesla, LLC jointly filed a motion for party status. Each of these motions was granted by ruling. SCE filed a reply to the protests and responses on October 13, 2016. KEZY, LLC, and Betmar, LLC, also filed a joint motion for party status. Prior to the prehearing conference (PHC), Pacific Gas and Electric Company (PG&E) filed a motion for party status. Each of these motions was granted at the PHC. During the PHC held on October 25, 2016, party status was granted on oral motions of: California Street Light Association (CALSLA), Coalition of California Utility Employees (CUE), Vote Solar, Southern California Gas Company, and San Diego Gas & Electric Company. Following the PHC, motions for party status have been granted for: Western Manufactured Housing Communities Association, Collaborative Approaches to Utility Safety Enforcement, Local Government Sustainable Energy Coalition, City of Rancho Cucamonga, City of Victorville, and California Choice Energy Authority. TURN, Consumer Federation of California, Vote Solar, National Asian American Coalition, and SBUA each have been found eligible to claim intervenor compensation. Public Participation Hearings were held in the cities of Fontana, Lancaster, Azusa, Long Beach, South Gate, Santa Ana, Santa Barbara, and Oxnard. -5- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Evidentiary Hearing was held July 13 through August 2, 2017 and on March 19, 2018. Parties filed and served briefs on September 8, 2017 and reply briefs on September 29, 2017. As noted above, pursuant to the Commission’s Rate Case Plan, SCE served Update Testimony on December 8, 2017, followed by additional updated testimony addressing the impact of the TCJA. At SCE’s request pursuant to Rule 13.13, the Commission held an oral argument on June 20, 2018 in order to provide parties the opportunity to address the Commission on the issues in this proceeding. The proceeding was submitted for the Commission’s decision on this date. 1.2. Settlements On September 14, 2017, the Commission issued D.17-09-007 adopting as filed, a settlement agreement between SCE and the City of Lancaster. In this decision, the Commission approved SCE’s proposal to modify its Community Choice Aggregator fee structure. In addition to this settlement, SCE and SBUA reached stipulations resolving all issues between them. These stipulations are discussed at Section 5.4. 2. Evidentiary Standards and the Burden of Proof Public Utilities Code Section 451 provides, in part, “all charges demanded or received by any public utility … shall be just and reasonable.” Section 454 provides, … no public utility shall change any rate or so alter any classification, contract, practice or rule as to result in any new rate, except upon a showing before the commission and a finding by the commission that the new rate is justified. -6- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Based on the foregoing it is undisputed that SCE bears the burden to establish that its requests are just and reasonable. The evidentiary standard SCE must meet in establishing its requests are just and reasonable is by the preponderance of the evidence.4 We also note however, SCE states, As this brief will demonstrate, there are many instances where SCE has introduced evidence supporting its requests, yet no other party has met the burden of going forward with a contrary position. In these many instances, SCE must be found to have met its burden of proof.5 Although there are many instances when SCE is the only party to have introduced evidence on an issue; we will not conclude, based on the lack of any evidence to the contrary, that SCE has met its burden to establish that its request is just and reasonable. Even in the absence of any countervailing evidence from another party, SCE must meet its burden of proof to establish by a preponderance of the evidence that its proposal, if adopted, will result in fair and reasonable rates at a just and reasonable rate of return. Nevertheless, as a general matter, with respect to individual uncontested issues in this proceeding, we find that SCE has made a prima facie just and reasonable showing, and adopt the proposal, unless otherwise stated in this opinion. 3. Affordability Parties raised a number of themes in their testimony and briefs that have helped to frame our approach to this decision, and we introduce those themes here. One overarching theme has been referenced by parties as the “the 4 See Decision (D.) 15-11-021 at 8-9. 5 SCE Opening Brief, at 10. -7- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 regulatory compact” between a regulatory body, the regulated entity, and the customers it serves. Parties engaged in a somewhat philosophical debate over the meaning of this “compact” but we offer what we consider to be a neutral definition: “the regulatory approach that grants individual companies exclusive franchises to provide power within a specific geographic area as long as their rates are regulated by state regulatory commissions based on the cost of providing service, including a reasonable return on investment.”6 In this proceeding SCE requests authority to make significant capital investments during the three-year GRC period, not only for basic maintenance and replacement of equipment on its distribution system, but also additional investments to modernize that system. In the updated request we address in this decision, SCE’s 2018 revenue requirement would remain essentially unchanged from 2017 levels due to the effects of the Tax Cuts and Jobs Act, but its revenue requirements for 2019 and 2020 would increase by 7% and 9%, respectively. Those increases are considerably higher than the inflation forecasts for the same period that are in the evidentiary record of this proceeding, approximately 2.65%.7 The magnitude and substance of SCE’s requests in this proceeding stimulated testimony and briefing regarding the obligations imposed by the “regulatory compact” and how those are expressed within California’s framework for forecast-based cost-of-service utility regulation. A major area of 6 Timothy P. Duane, Regulation's Rationale: Learning from the California Energy Crisis, 19 Yale J. on Reg. (2002) at 476-477. Available at: http://digitalcommons.law.yale.edu/yjreg/vol19/iss2/5 7 TURN-08-A, at 3. February 2016 Short-Term Macro Forecast provided to TURN by SCE in its response to TURN data request TURN-SCE-12 Q.05. -8- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 contention was the extent to which the Commission should prioritize the affordability of SCE’s services as it weighs SCE’s requests for funds to maintain or enhance the safety and reliability of its service. The topic of affordability was included in the common briefing outline developed by parties at the close of evidentiary hearings. Although parties placed this topic near the end of their briefs, we find it important to discuss at the outset of this decision, so that the reasons underlying our decisions about SCE’s revenue requirement are clear. 3.1. Affordability and “Just and Reasonable” Rates This is the third consecutive SCE GRC where the Commission has emphasized the importance of affordability as a metric for evaluating funding request. In SCE’s test year 2012 proceeding, the Commission acknowledged that under cost-of-service ratemaking principles, “the utility is generally entitled to its reasonable costs and expenses, as well as the opportunity, but no guarantee, to earn a rate of return on the utility’s rate base.”8 The Commission included the same acknowledgement in its decision in SCE’s test year 2015 proceeding.9 In both instances, the Commission was simply acknowledging its role within the regulatory compact. However, the Commission was also very specific in describing SCE’s corresponding responsibilities in the cost-of-service framework of general rate cases: The burden is on SCE to not only establish that the proposed work activities are necessary, but also that SCE has prudently examined alternatives before coming to ratepayers to fund the chosen action. 8 D.12-11-051 at 10. 9 D.15-11-021 at 2. -9- PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The Commission reviews SCE’s showing to ensure that SCE is addressing the work in a cost-effective manner.10 In both the 2012 and 2015 proceedings, the Commission made clear that if SCE did not meet this burden and justify a higher revenue requirement, its proposals would not be approved: We confirm that the Commission’s mandate is specific and requires a balancing of interests to authorize rate recovery only for those just and reasonable costs necessary for safe and reliable service. This requires a hard look at each proposed expense, including whether it is necessary during the coming rate cycle and is appropriately calculated.11 Ratepayers are entitled to the Commission’s sharp eye and consideration of other options before committing their hard-earned cash. Therefore, we have neither accepted all requests nor adopted across-the-board percentage reductions. Instead, the decision is the result of scrutinizing each request according to the standards and policy articulated here.12 One of the central tasks facing the Commission in this proceeding is to balance safety and reliability risks in comparison with cost. SCE is required by law to “promote the safety, health, comfort, and convenience of its patrons, employees, and the public” while including only “just and reasonable” charges in its rates. Our fundamental challenge in many disputed areas of this case is to reach an outcome consistent with these twin objectives.13 We approve approximately $3.4 billion of total capital expenditures, reflecting our judgement that the long-term benefits of these 10 D.12-11-051 at 16. 11 Id. at 9. 12 Id. at 10. 13 D.15-11-021 at 11, citing Pub. Util. Code § 451. - 10 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 investments justify the costs. However, we also deny notable portions of SCE’s request for expenditures that SCE has not demonstrated are just and reasonable costs of safe and reliable service.14 As these references demonstrate, the Commission’s decisions in general rate case proceedings are guided, above all, by Public Utilities Code §§ 451 and 454: All charges demanded or received by any public utility, … for any product or commodity furnished or to be furnished or any service rendered or to be rendered shall be just and reasonable. Every unjust or unreasonable charge demanded or received for such product or commodity or service is unlawful. Every public utility shall furnish and maintain such adequate, efficient, just, and reasonable service, instrumentalities, equipment, and facilities, … as are necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public.15 … a public utility shall not change any rate or so alter any classification, contract, practice, or rule as to result in any new rate, except upon a showing before the Commission and a finding by the Commission that the new rate is justified.16 For this Commission, a key element of finding a charge or rate just and reasonable is whether that charge or rate is affordable. Public Utilities Code § 382(b) states: recognizing that electricity is a basic necessity, and that all residents of the state should be able to afford essential electricity and gas supplies, the Commission shall ensure that low-income ratepayers 14 Id. at 3. 15 Public Utilities Code § 451. 16 Public Utilities Code § 454(a). - 11 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 are not jeopardized or overburdened by monthly energy expenditures. Public Utilities Code § 739(d)(2) directs that the Commission shall ensure that the rates are sufficient … to recover a just and reasonable amount of revenue … while observing the principle that electricity and gas services are necessities, for which a low affordable rate is desirable…. 3.2. SCE’s Capital Expenditure Request SCE does not dispute this statutory framework, but asks the Commission to evaluate its request from a broader perspective. SCE’s approach to its GRC request is explained in the direct and rebuttal testimony of its Chief Executive Officer (CEO), Kevin Payne. We note here that the record in this proceeding benefitted from the direct participation of Mr. Payne, who also appeared as a witness during evidentiary hearings and responded to questions from intervenors, the Administrative Law Judges (ALJ), and Commission President Michael Picker. In response to intervenors’ criticisms and recommendations, Mr. Payne’s rebuttal testimony acknowledges “capital expenditures have indeed increased”17 but contends this occurred for valid reasons: “[o]ur need to keep our aging system reliable and resilient for our customers drives infrastructure replacement, which in turn drives prudent but increased capital spending.”18 Mr. Payne also defends SCE’s request for separate and additional funding to modernize its grid because it will support additional safety and reliability now, 17 SCE-17 at 28. 18 Ibid. - 12 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 while also establishing a foundation for distributed energy resources (DER) integration as future needs emerge.19 Mr. Payne’s testimony provides us with a useful summary and distillation of the reasoning behind SCE’s requests in this proceeding. We focus on capital expenditures in the following discussion because O&M spending levels are in large part reflective of authorized capital expenditures. Very generally, SCE seeks funding for three purposes regarding its distribution system, and a fourth category of funding for company-wide purposes. Mr. Payne provided shorthand explanations of these categories in his rebuttal testimony: 1. Conventional programs that are part and parcel of owning and managing the electric grid: grid management programs that SCE “currently undertake to maintain safety and reliability. This includes inspection-based maintenance and infrastructure replacement programs and load-growth driven programs that SCE has undertaken for decades.”20 2. “New programs that are driven by conventional needs, [which] can be viewed as both Grid Management and Grid Modernization. These are upgrades we would have to undertake regardless of any additional DER growth. They are triggered by safety and reliability needs, but in the future will provide ancillary benefits associated with DER enablement.”21 3. New programs driven by new needs, which have been referenced in this proceeding as “grid modernization” and which Mr. Payne states 19 Id. at 9-11. 20 SCE-17 at 10. Italics in the original. 21 Ibid. - 13 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 are needed “to support DER growth, enable DER penetration, foster DER integration, and maximize DER value.”22 4. Other Capital Projects and Programs completes SCE’s capital request. SCE’s requested funding for this category in 2018 totals almost $1 billion, and includes capital expenditures related to SCE’s generation assets, customer service, information technology, and operational services business units that support SCE’s daily operations (such as corporate real estate, service centers, supply management and transportation services). For the 2018 test year, SCE’s capital expenditure requests for the four purposes discussed in Mr. Payne’s testimony and outlined above total $3.998 billion. SCE’s request is summarized in the table below: 22 Id. at 11. Mr. Payne notes that this third group is the subject of matters being evaluated in the Commission’s Distribution Resources Plan proceeding (R.14-08-013). He further notes that some of the solutions for similar challenges in the second and third group “are largely the same, except the locations selected for deployment would differ based on the driver.” - 14 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Summary of SCE's Updated 2018 Capital Expenditure Request ($ Nominal) Category 1 Description Conventional Programs to Meet Conventional Needs Transmission &Distribution (T&D) Infrastructure Replacement & Maintenance Capacity-Driven T&D Activities Customer-Driven T&D Activities New Programs to Meet Conventional Needs (T&D Testimony other than SCE-02, Volume 10) New Programs to Meet New Needs Grid Modernization: Exhibit SCE-02, Volume 10 Other Capital Projects/Programs Distribution Construction & Maintenance Substation Construction & Maintenance Transmission Construction & Maintenance Generation Customer Service Information Technology Operational Services Total Updated Request 2 3 4 3.3. 2018 Request 1,244,952 691,000 539,002 145,872 491,337 986,047 80,907 96,572 38,513 100,679 38,839 366,015 252,147 3,998,000 Our Decision-Making Framework We have described the Commission’s approach to GRCs and SCE’s conceptual approach to its request at some length in order to illustrate the framework we have used to evaluate SCE’s forecast expenditures. Consistent with the manner in which SCE justifies its requests, we follow a three-step process: First, we agree with Mr. Payne that a certain level of revenue requirement is necessary to support the fundamental operation of any electric utility. We must ensure that we authorize the funds necessary for SCE to maintain its current infrastructure, at current levels of safety and reliability. However, even - 15 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 in this basic category, parties that agreed on the fundamental necessity of these funds still disagreed over the proper pace of such maintenance. Referring to the table above, SCE’s requests for these “conventional programs to meet conventional needs” sum to approximately $2.7 billion, or 67.5% of SCE’s 2018 request. Second, SCE requests an additional increment of funding to upgrade its existing distribution grid, contending that new technology could cost-effectively provide useful upgrades. Mr. Payne described these investments as “new programs that are driven by conventional needs,” which he considers “prudently updating the grid so that it can continue providing safe and reliable service to our customers year after year after year.”23 Again, Mr. Payne suggests that these programs can be viewed as both grid management and grid modernization investments, useful today but also likely to provide future benefits as DERs expand. Referring again to the table above, this additional increment of funding is equal to $300 million, or 7.5% of SCE’s 2018 request. Intervenors in this proceeding made numerous recommendations regarding this second category of funding requests, often relying on the cost-effectiveness principles articulated by the Commission in SCE’s 2012 and 2015 GRCs. Third, SCE requests authority to invest another additional increment of funds in modernizing its distribution grid, in the category described by Mr. Payne as “new programs driven by new needs.”24 SCE’s September 2016 testimony emphasized that these investments would support DER growth, 23 SCE-17 at 10. 24 Id. at 11. - 16 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 enable DER penetration, foster DER integration, and maximize DER value, but in its rebuttal testimony SCE shifted the emphasis of its rationale for these investments and stressed that they were necessary for reliability improvements. This additional increment of funding is equal to $237 million, or 5.9% of SCE’s 2018 request. It is this third group that led to the strongest disagreements between parties. SCE argues forcefully that infrastructure upgrades to modernize its grid must begin now in order to enable implementation of California’s ambitious clean energy policies. Other parties argue just as forcefully that SCE’s preferred approach is either not necessary at this time, too costly, or too deterministic because the Commission had yet to issue policy directives regarding distributed resource planning. Fourth and finally, this decision addresses SCE’s funding requests related to “other capital projects and programs.” As we noted above, this category accounts for nearly $1 billion of SCE’s proposed capital expenditures in 2018, but we have already counted Distribution, Substation and Transmission Construction and Maintenance as part of “conventional programs to meet conventional needs, so the other remaining projects sum to $757.7 million out of SCE’s total 2018 request, or 19% of the total. Several intervenors registered strong opposition to certain SCE proposals in this category. By distinguishing between the specific purposes of each category of its proposals as SCE has done, we can evaluate SCE’s funding requests while remaining cognizant of the incremental effect that various investments will have on SCE’s revenue requirement and, consequently, on customer bills. This returns us to the central theme of affordability, and we conclude this introduction with an overview of the positions taken by SCE and intervenors on this topic. - 17 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We remain mindful that our fundamental responsibility is to ensure that the utilities under our jurisdiction are equipped to provide safe and reliable service at just and reasonable rates. TURN makes the same point in the closing paragraph of its opening brief: The Commission should only approve the minimum spending truly necessary to provide safe and reliable service, and spending proposals ostensibly meant to improve “safety or reliability” must be scrutinized to ensure they provide meaningful benefits in relation to the requested spending, and to ensure that SCE is not ignoring less expensive methods that would work as well to achieve valid goals.25 TURN asserts the increases in SCE’s rates of 38% from 2005 to 2015, while inflation increased approximately 23%, may largely be attributed to a doubling of capital expenditures for SCE’s transmission and distribution systems between 2006 and 2015.26 This has led to a doubling of rate base during that period from $10.304 billion to $22.231 billion.27 TURN contends this increased rate base “will contribute to revenue requirement and rate increases for decades to come.”28 Citing its testimony regarding what it considers to be SCE’s inordinately high bills, high rates of utility service disconnections and “extraordinary spending increases” authorized in recent SCE GRCs, TURN urges the Commission to consider this information when weighing approval of certain spending requests: 25 TURN Opening Brief, at 370. TURN is quoting its witness Hawiger, TURN-10 at 18-19. 26 Id., at 364-365. 27 Id. at 365. 28 Id. at 366. - 18 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Undoubtedly there are many requests in this rate case that represent spending necessary to provide safe and reliable service. However, there are also many programs and spending requests that may be desirable, but are not necessary for safe and reliable service and should be deferred or denied. TURN offers one final useful reminder: The Commission can, and does, address issues related to affordability in other proceedings, especially those focused on rate design, low income energy efficiency, and the design of the CARE discount program. However, those cases address how to deal with the backend - how to ameliorate the impact of high rates and bills through other programs and cost allocation. They do not address the underlying cause of the high bills. The primary drivers of high customer bills, even with relatively low consumption levels compared to other states, are the high revenue requirements and associated high electric rates. It is in this rate case that the Commission can actually mitigate the root of the problem by weeding out spending requests that provide minimal benefit from a safety and reliability perspective.29 CFC also references the testimony of SCE’s Mr. Payne in its discussion of affordability. CFC notes Mr. Payne’s agreement that SCE’s request in this proceeding is a “substantial one” and his assertion that, nevertheless, “[w]hen viewed in the context of safety and grid needs, our request is reasonable.30 CFC responds that “[w]hen viewed in the context of affordability, however, the application's proposed increases are less reasonable.”31 CFC cites the same Public Utilities Code sections that we quoted above, and asks, “what is 29 Id. at 368. 30 CFC Opening Brief at 5, citing SCE-01 at 4. 31 Ibid. - 19 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ‘reasonable’?”32 CFC suggests that a good or service whose price is rising faster than consumer incomes is, by definition, becoming less affordable and notes that SCE initially proposed to increase its revenue requirement over this three-year GRC period at an annualized rate of 7.25%. CFC counters that a reasonable rate increase would be one that did not “vastly” exceed the growth rate of the typical utility customer's income. CFC showed in testimony that SCE’s customers have seen annual income gains that were typically on the order of 1.4%, and the median growth rate has been 2.3%. Finally, somewhat generously in light of its testimony, CFC concludes that a reasonable rate increase would be limited to double the rate of median income growth, or 4.6 %, not the 7.25% proposed in SCE’s application. We share the concerns of TURN and CFC. Not only is this GRC proceeding following upon the significant historical increases in SCE’s revenue requirements demonstrated by TURN, in this GRC after an initial 0.38% reduction for 2018 (due to the one-time benefits of the Tax Cut and Jobs Act) SCE’s final updated request seeks revenue requirement increases of 7.15% for 2019, and 9.39% for 2020. We do not consider increases of this magnitude to be affordable for ratepayers. Therefore, in every instance where SCE cannot establish by a preponderance of the evidence that a request is necessary to provide safe and reliable service, we deny their requests. We do so with a goal of limiting the annual increase in SCE’s revenue requirements during this GRC period to, not double the growth in customer income, but rather a true alignment 32 Id., at 2. - 20 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 with no more than that growth rate. It is only by endeavoring to meet that goal, that we can begin to strive for greater affordability. 3.4. Recent Statutes and Commission Rulemakings Regarding Affordability In the time since SCE filed its application, new statutes have been enacted, and the Commission has initiated two rulemaking proceedings related to affordability. First, in September 2017 the Legislature passed, and the Governor signed, Senate Bill (SB) 598. SB 598 requires the Commission to develop policies, rules, or regulations with a goal of the statewide level of gas and electric service disconnections for nonpayment by residential customers. In Section 1 of SB 598 The Legislature finds and declares the following: (a) Residential disconnections for nonpayment by major gas and electrical corporations rose significantly from 547,000 in 2010 to 816,000 in 2015. (b) Gas and electric service shutoffs threaten the health of two million people annually with significant impact on infants, children, the elderly, low-income families, communities of color, people for whom English is a second language, physically disabled persons, and persons with life-threatening medical conditions. (c) The loss of basic gas or electric service causes tremendous hardship and undue stress, including increased health risks to vulnerable populations, as well as overreliance on emergency services and underutilization of preventive programs. Senate Bill 598 added §718 to the Public Utilities Code. Section 718, subsection (b)(1) provides that in each gas and electrical general rate case, the Commission shall do both of the following: - 21 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 (A) Designate the impact of any proposed increase in rates on disconnections for nonpayment as an issue in the scope of the proceeding. (B) Conduct an assessment of and properly identify the impact of any proposed increase in rates on disconnections for nonpayment, which shall be included in the record of the proceeding. Because Senate Bill 598 became effective in 2018, after SCE filed its GRC application, we do not implement its provisions in this decision. However, CFC made a similar proposal in its testimony, that the Commission require SCE, as part of its next GRC application: (1) to show that disconnections subsequent to the decision on this GRC are not unjustifiably biased toward any district or other customer group as the result of the company being limited by resource availability, and (2) to provide an analysis of the relationship between rate increases, arrearages, and disconnections. SCE urges rejection of CFC’s first proposal, contending it is unnecessary because SCE already complies with Commission-approved tariffs and Public Utilities Code § 453, which SCE argues preclude any bias or discrimination against localities or classes of service. We find CFC has not established the need for a report of this nature as to “the company being limited by resource availability” as the term is not defined for this context. CFC’s second proposal is supported by SCE and TURN. SCE agrees to work with CFC and other stakeholders to develop a report, to be included as part of its next GRC, that analyzes the relationship between rate increases, arrearages, and disconnections, if any. TURN supports CFC, but also requests that SCE’s - 22 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 methodology for this analysis be vetted through a stakeholder process before SCE undertakes this project.33 CFC’s second proposal is consistent with the requirements of SB 598, and this decision directs SCE to prepare the report. In addition, we consider it reasonable to direct that the report includes an analysis of the relationship of the agreed-upon metrics to localities and customer class of service. We also direct SCE to engage in a stakeholder process to review its proposed methodology with stakeholders and incorporate their input prior to beginning its analysis. Turning to Commission proceedings, on July 12, 2018, the CPUC opened two related Rulemakings that address the affordability of utility service. First, as directed by SB 598 the Commission opened R.18-07-005, its “Order Instituting Rulemaking to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs.” The proceeding is following a phased approach, with Phase 1 intended to identify and adopt nearterm improvements to the current system. Phase 1 is now complete, with the Commission adopted D.18-12-013 in December 2018. That decision approved interim rules with immediate reforms to help reduce the statewide level of service disconnections for residential energy customers, and improve the reconnection process following future disconnections.34 Phase 2 of the proceeding will take a broader approach to the evaluation of residential natural gas and electric disconnections with the goal of determining whether the 33 TURN Reply Brief at 94. 34 The new rules will: (1) prohibit the disconnection of elderly and medically vulnerable customers, such as those who qualify for medical baseline, life support and/or who are above 65 years old; (2) prevent disconnections during extremely hot or freezing days; and, (3) limit the rate of disconnections to utility-specific 2017 levels. See D.18-12-013, Ordering Paragraph 1. - 23 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 disconnection rate can be reduced through broader reforms and new preventive approaches. Second, the Commission also opened a rulemaking directly focused on affordability, with the intent to develop a common understanding and tools to assess, consistent with Commission jurisdiction, the impacts on affordability of individual Commission proceedings and utility rate requests.35 Pursuant to the scoping memo in that proceeding, an initial workshop was held in January 2019 and is expected to be followed by additional workshops, issuance of a Commission staff report to provide a framework for subsequent comments by interested parties, and a Commission decision by the end of 2019. We expect that the results of these rulemakings will lead to better data and other information being available to intervenors in SCE’s next GRC proceeding. This, in turn, will assist the Commission in continuing its analysis of the affordability of SCE’s service and the specific areas of its revenue requirement that are putting upward pressure on SCE’s rates. We encourage intervenors to continue their efforts in this area and we will ensure that SCE provides any information and analysis that will assist those efforts. 4. Transmission and Distribution 4.1. T&D – General SCE’s Transmission and Distribution (T&D) organization plans, engineers, constructs, operates, and maintains transmission and distribution facilities required to deliver electricity to approximately 14 million residents and 5 million customer accounts throughout SCE’s 50,000 square mile service territory. The 35 R.18-07-006 at 2. - 24 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 T&D organization is SCE’s largest operating unit. The table below broadly summarizes the SCE assets that are operated by the T&D organization.36 SCE Transmission and Distribution Organization Physical Assets Count Asset Type (as of 12/31/2015) Transmission Lines (circuit miles) Distribution Lines (primary conductor miles) Substations Circuits Wood Poles Substation Transformers Distribution Transformers Underground Structures Switches Capacitors Streetlights (lamps) 13,061 105,773 865 4,636 1,406,811 2,753 728,627 422,707 67,302 13,568 683,813 In this proceeding, for Test Year 2018 SCE requests approval of $3,586 million for T&D capital expenditures, and $739 million for Operations and Maintenance (O&M) expenses. The details of SCE’s request are shown in the table below. 36 SCE-02, Vol. 1, at 2, Table I-1 “SCE Key Physical Assets.” - 25 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Requested Test Year 2018 Transmission & Distribution Capital Expenditures and O&M Expenses ($000) Subject Capital37 Operational Overview and Risk-Informed Decision-Making Customer Driven Programs System Planning Distribution Maintenance and Inspection Distribution Construction & Maintenance Substation Construction & Maintenance Transmission Construction & Maintenance Infrastructure Replacement Poles Grid Modernization Grid Technology Safety, Training & Environmental Programs Other Costs, Other Operating Revenues Total T&D GRC Request 4.1.1. (146.758) 539.002 1,038.161 273.955 203.700 176.329 216.793 493.661 317.992 440.683 32.841 3,586.359 O&M38 (10.200) 14.724 159.967 70.496 78.148 40.919 41.941 4.135 15.914 62.080 261.282 739.406 Exhibit Source (plus errata) SCE-18, Vol. 1 SCE-18, Vol. 2 SCE-18, Vol. 3 SCE-18, Vol. 4 SCE-18, Vol. 5 SCE-18, Vol. 6 SCE-18, Vol. 7 SCE-18, Vol. 8 SCE-18, Vol. 9 SCE-18, Vol. 10 SCE-18, Vol. 11 SCE-18, Vol. 12 SCE-18, Vol. 13 Operational Overview In Exhibit SCE-01 (Policy) SCE discusses how it pursues affordability by implementing initiatives intended to increase how effectively and efficiently it serves its customers. SCE’s testimony states that the company has renewed its focus on “Operational Excellence” (OpX) as it relates to prioritizing work and improving productivity.39 The results of SCE’s OpX initiatives are captured in its 37 SCE Reply Brief, Summary of SCE’s Updated Capital Expenditures Request, 2018, CPUC-Jurisdictional Only, Nominal $ millions. 38 Id., Summary of SCE’s Updated O&M Request (Including Other Operating Revenue), Total Company 2015, Constant $ millions. 39 SCE-01, at 20. SCE states that it initiated Operational Excellence in 2013 and launched a second phase in 2015. - 26 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 forecast savings of Test Year 2018 O&M expenses and capital expenditures. For the T&D organization, SCE forecasts 2018 savings of $10 million for O&M40 and $145.529 million for capital.41 No other party disputes the level of OpX savings forecast by SCE. We find SCE’s forecasts of OpX savings reasonable and adopt them in this decision. 4.1.2. Risk-Informed Decision Making SCE describes its risk-informed planning approach as “relatively new” and therefore its risk analysis and resulting risk spend efficiency (RSE) metric “has not matured sufficiently to drive our 2018 GRC request at a program or project level.”42 ORA and CUE agree that at this stage of SCE’s progress, the Commission should not base its decision on safety-related cost recovery on SCE's risk-informed decision-making analyses.43 SCE agrees, though notes that its risk- approach has nevertheless influenced some operational decisions and scoping efforts, and “was one of many factors considered in funding allocation decisions for this GRC.”44 4.1.3. Safety and Reliability Investment Incentive Mechanism In SCE’s 2006, 2009, 2012, and 2015 GRCs, the Commission adopted the Reliability Investment Incentive Mechanism (RIIM). In SCE’s 2015 GRC, the Commission enhanced and renamed the RIIM, as the Safety and Reliability 40 SCE-18, Vol. 1, at 3: Table II-3 “T&D OpX O&M Benefits.“ 41 Ibid.: Table II-2 “T&D OpX Capital Benefits.“ 42 SCE-18, Vol. 1, at 11. 43 ORA-05, at 2. 44 SCE-18, Vol. 1, at 11. - 27 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Investment Incentive Mechanism (SRIIM). SRIIM replaced previous reliability mechanisms that had focused solely on reliability metrics. SRIIM is comprised of two components: 1. Capital spending on core safety and reliability-related projects and programs; and 2. Hiring field personnel that directly work on safety and reliability-related projects and programs. SCE proposes continuing SRIIM for this rate case cycle. In response to recommendations made by CUE in its testimony, SCE agreed to withdraw its proposal to eliminate two programs in SRIIM (Underground Structures and Underground Switch Replacements). SCE also agreed with CUE that 4kV Substation Elimination should be added to SRIIM.45 Based on SCE's agreement with CURE, we consider three enhancements to the capital mechanism and four enhancements to the workforce mechanism. First, we adopt the three capital mechanism enhancements in SCE's request, as revised by SCE in its rebuttal testimony to reflect agreements with CUE: 1. The programs included in SRIIM shall now include SCE's new Overhead Conductor Program (OCP) and 4 kilovolt (kV) Overload-Driven Cutovers, plus the SCE/CUE agreed-upon 4 kV Elimination Program. Thus, SRIIM now includes 10 core categories; 2. SRIIM capital expenditure targets should be established based on the actual level of capital expenditures that the Commission authorizes in this decision; and 45 SCE Opening Brief at 12, citing SCE-18, Vol. 1, at 9. - 28 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 3. Any spending occurring in the High Priority categories in excess of authorized amounts can be used to achieve the targets established for the SRIIM capital categories. However, as CUE recommends (and SCE appears to accept in its rebuttal testimony) we leave in place the two limits on SRIIM transfers that we adopted in D.15-11-021: (1) that such limits cannot occur until High Priority Spending is more than 10 percent over the adopted forecast, and (2) SCE is earning less than its authorized rate of return. Second, we adopt the four enhancements to the existing SRIIM workforce mechanism requested by SCE: 1. Add foreman/troubleman trainer and operator trainee classifications; 2. Increase the headcount target from 2,225 to 2,375. As agreed to by SCE, we adopt CUE’s proposal to measure headcount as an average of the last quarter of 2020. 3. Adjust the headcount target by one-half the percentage change in the authorized versus requested T&D capital; and 4. Change the measurement period from a single day to a more reasonable actual time frame, so that if SCE meets the headcount during the designated time frame, it will be deemed to have satisfied the workforce component of SRIIM. 4.2. T&D – Customer-Driven Programs Customer-Driven Programs include capital expenditures that SCE incurs when responding to requests from its customers. The major costs in this area include the following: 1. Connecting new residential, commercial, and agricultural customers to SCE’s system; 2. Meeting customer requests under Rule 20 to underground certain overhead facilities; 3. Relocating existing SCE facilities to meet customer needs; and 4. Providing customers with added facilities under Rule 2. - 29 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE states that these programs are necessary for SCE to meet its obligation to serve its customers, and are subject to SCE's Preliminary Statement and certain SCE Tariff Rules such as Rule 2 (Description of Service), Rule 15 (Distribution Line Extensions), Rule 16 (Service Extensions), and Rule 20 (Replacement of Overhead with Underground Electric Facilities). Thus, SCE contends that the level of capital expenditures in this area is largely outside of its control because spending will change based on the number and type of customer requests actually experienced by SCE, as well as other external factors such as permitting. 4.2.1. New Service Connections SCE uses its forecast of new meter installations and its estimated unit costs of various customer-related activities to develop its capital expenditure forecasts for each new service connection work category. This approach is consistent with the forecasting methodology the Commission adopted in SCE's 2012 GRC and 2015 GRCs. ORA agrees with SCE's forecast methodology for New Service Connections but utilizes its own meter forecast in developing its proposal. As shown in the table below, SCE forecasts $539.002 million in Test Year 2018 capital expenditures. ORA recommends $508.278 million; TURN recommends $494.517 million; and CFC recommends $505.755 million. - 30 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Summary of Customer-Driven Programs 2018 Capital Expenditure Forecasts46 100% CPUC Jurisdictional – Nominal $000 Activity SCE ORA TURN CFC Residential Service Connections 35,363 33,845 30,857 Residential Line Extension 31,425 29,946 26,733 Residential Tract Development 94,530 90,015 75,710 Residential Backbone Development 28,941 27,549 19,294 Commercial/Industrial Service Connections 25,877 23,323 18,172 20,800 Commercial/Industrial Line Extensions 41,338 37,141 42,604 Commercial/Industrial Tract Development 15,694 14,098 15,314 Agricultural Service Connections 2,562 2,560 Agricultural Line Extensions 2,779 2,742 Street Light Installations 38,900 37,231 Distribution Rule 20A Conversions 23,643 14,085 Distribution Rule 20B Conversions 14,924 14,924 Distribution Rule 20C Conversions 8,210 8,210 Transmission Overhead to Underground Conversion 6,031 6,031 Relocation of Distribution Lines 60,437 60,437 Distribution Added Facilities 13,130 13,130 Distribution Transformers 95,217 93,011 Total Capital – Customer Driven Programs 539,002 508,278 Many of the disputed forecasts between SCE and other parties will ultimately be resolved by the meter set forecasts that we adopt in this decision, which we address in Section 13 below (Sales and Customer Forecast). SCE agrees to re-calculate its cost forecasts for New Service Connections based on the final new meter set forecast adopted in this GRC. In Section 13 we adopt TURN’s forecast of new meters, and we summarize those adopted values here in order to provide context for our discussion of customer-driven programs. Our 46 SCE-18, Vol. 2, at 3: Table I-2 “Summary of Customer-Driven Programs Capital Expenditures.” - 31 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 adopted forecast results in reductions to SCE’s forecast levels of capital expenditures for residential and commercial customers.47 2016 2017 2018 2019 2020 New Meter Connections Adopted Forecast48 Residential Commercial # Requested # Adopted # Requested # Adopted SCE TURN SCE TURN 29,895 31,142 6,092 6,092 33,532 34,013 6,666 6,697 41,702 36,388 6,825 7,045 43,438 37,955 7,665 7,350 42,801 37,729 8,188 7,534 Agricultural # Adopted Uncontested 349 321 321 321 321 In addition to disagreement over new meters, other disputes stem from differences between SCE and TURN regarding SCE’s unit cost forecasts. TURN also challenged (separately from its recommended reductions in meter sets) SCE’s unit cost estimates for several of the customer-driven activities listed in the table above. We address those cost disputes here. 4.2.1.1. Residential Line Extensions Residential line extension capital expenditures generally include the cost of installing primary and secondary systems in two situations: 47 For this reason, we agree with SCE’s responses to ORA and CFC regarding their recommendations for customer-driven programs: SCE agrees that it will adjust its forecast for new residential service connections (ORA) and new commercial service connections (CFC) based on the new meter set forecasts adopted in this decision. See SCE-18, Vol. 2, at 6 and 10. 48 As we discuss below in Section 13 (Sales and Customer Forecast) TURN did not develop its own forecasts for Streetlights. However, since the number of streetlights is directly related to the number of new residential meter connections, and since we adopt TURN's forecasts for new residential meters, our adopted 2017 and 2018 forecasts for Streetlights reflect revisions to SCE’s request to align those values with our adopted residential forecasts. - 32 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 1. when small-scale development and construction of four or fewer homes occurs beyond the current end of SCE’s distribution system; and 2. when a multi-unit complex replaces a single-family home or small apartment building.49 SCE defines the unit cost for this work as the average cost to provide a mile of line extension. SCE shows that unit costs have varied between $122,000 and $168,000 per mile of cable from 2011-2015. SCE calculates a five-year weighted average cost of $140,000 per cable-mile and calculated the total forecast capital expenditures by multiplying the forecast unit cost per mile by the miles of cable SCE expects to install from 2016-2020. SCE contends that this method reflects the “strong” historical correlation between counts of new meters set in a given year and miles of line extension cable installed in that same year.50 TURN differs from SCE regarding how many years of data should be used in the forecast of how many cable-feet will be needed for each meter that is installed: TURN uses 2006-2015 data, while SCE uses 2007-2015. SCE contends that 2006 data should be excluded because in that year SCE installed a “significantly higher” number of residential meters in 2006 than either SCE or TURN forecasts for 2018. SCE asserts that including 2006 data will cause the forecast to less accurately predict 2018 activity. We find SCE’s approach to forecasting cable-feet per installed meter for residential line extensions to be reasonable and we approve SCE’s use of its estimates to calculate its capital expenditure forecast for Test Year 2018. 49 SCE-02, Vol. 2, at 11. 50 SCE-02, Vol. 2, at 12. - 33 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.2.1.2. Residential Tract Development SCE’s residential tract development work category involves extension of service to new housing developments where no electrical infrastructure currently exists. SCE states that capital expenditures for residential tract development generally include the cost of cable installed by SCE in customer-installed conduits and structures. Expenditures also include SCE-installed transformers and the secondary system needed to serve the residential development. SCE defines the cost unit for this work as the length of installed underground cable measured in miles. SCE states that its analysis shows a “strong” correlation between the miles of tract cable installed in a given year and the number of meter sets in the next year as the tract cable is required to complete service installations of new developments in the following year.51 SCE states that its unit cost for tract cable includes the labor and material to install the cable itself as well as any other associated assets such as transformers, switches, conduits, and underground structures. TURN argues that SCE’s estimate of cumulative cable-feet per installed meter is highly dependent on the year the analysis is started; and SCE did not properly account for excess installed cable in SCE’s system due to the large amount of overbuild several years ago, when housing developers required SCE to install more residential tract cable than turned out to be justified as the housing market softened in Southern California. In rebuttal testimony, SCE explained why its use of all data from the last ten years would be more logical than TURN’s use of a 14-year average that 51 SCE-02, Vol. 2, at 16. - 34 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 excludes the two most recently available years of data, 2014 and 2015. SCE also cited to its opening testimony, where it explained that the excess installed cable has in fact been reduced as the housing market gradually recovered in recent years.52 We find SCE’s estimation methods to be sound, and we agree that SCE has shown that previous levels of excess tract cable have in fact been reduced. We find SCE’s approach to forecasting cable-feet per installed meter for residential tract developments to be reasonable and we approve SCE’s use of its estimates to calculate its capital expenditure forecast for Test Year 2018. 4.2.1.3. Residential Backbone Development SCE’s “backbone” system consists of sections of distribution line on major thoroughfares that connect multiple tracts and commercial/industrial projects together. The residential distribution system connects to the backbone system through conduits and vaults with cable connections at the switch positions.53 SCE summarizes the capital expenditures for this work category as follows: 1. Main-line feeder-system installations to serve residential tract developments; and 2. The conduits required to feed smaller, non-residential customers located in a residential area, such as gas stations, restaurants, retail stores, etc. The conduits installed in these backbone systems also support the collateral streetlight subsystems along the major arterial thoroughfares, as well as the public safety 52 SCE-18, Vol. 2, at 7. 53 SCE-02, Vol. 2, at 15. - 35 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 services for controlled intersections, and the power required for landscape irrigation systems and public sanitation lift-stations.54 SCE defines the cost unit for residential backbone development as the length of underground cable installed in miles. SCE states that its unit cost for residential backbone includes the labor and material to install the cable as well as associated assets such as transformers, switches, conduits, and underground structures. SCE’s unit cost for 2011-2015 has varied from $121,000 to $176,000 per mile. SCE used a five-year weighted average cost of $148,000 per mile of cable as the basis to forecast total 2016-2020 costs for residential backbone development. The dispute between SCE and TURN again centers on which years of historical data should be used to forecast the length of underground cable that will serve as the basis for forecast costs. SCE uses a ten-year average in order to account for the year-to-year variability during the housing bubble and decline. SCE asserts that this is preferable to TURN’s use of a five-year average, which is less accurate in smoothing out the variability of this work area and taking into account historical developments. SCE provides a convincing explanation of the proper years from which historical data should be relied upon for this forecast. We find SCE’s approach to forecasting the length of underground cable to be used in future residential backbone developments to be reasonable and we approve SCE’s use of its estimates to calculate its capital expenditure forecast for Test Year 2018. 54 Id., at 19. - 36 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.2.1.4. Commercial/Industrial Service Connections and Tract Development SCE’s commercial/industrial service connection work category involves the costs to provide a new service connection to individual commercial and industrial customers per SCE’s Tariff Rule 16. SCE states that capital expenditures for this category generally include installation of the permanent service cables or cables from the SCE distribution transformer (or other distribution structures) to the new customer’s electric service panel(s). SCE defines the unit of work for this category as the number of meter sets, just as is done in the case of residential service connections. SCE’s commercial/industrial tract development work category involves the costs to construct system additions to serve new commercial and industrial customers under SCE’s Line Extension Tariff Rule 15, which are usually constructed in conjunction with street improvements. SCE states that capital expenditures for this category generally include installing conduit and structures, cable, transformers, switches, and other apparatus that are necessary to provide service to the current development.55 SCE defines the unit of work for this category as the length of underground cable installed, as measured in miles. TURN and SCE disagree regarding the number of years to use in calculating unit costs. SCE used a 5-year average (2011-2015) for new connections and a 10-year average (2006-2015) for tract development. TURN recommends using a 10-year average for both work categories. In this instance, SCE argues that data from 2011-2015 better reflect the expected level of new 55 SCE-02, Vol. 2, at 28. SCE adds, “we may also install a limited amount of conduits and structures when we have a reasonable expectation that we will need to serve future developments located beyond the geographical limits of the current project.” - 37 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 connections in the forecast period because the years prior to 2006 included costs for a significant increase in connections resulting from the robust housing market during that period. SCE asserts that the recorded commercial meter sets for 2000-2006 do not reflect the typical current-day commercial service connections and tract development, which are characterized by smaller-scale development.56 We find SCE’s approach to forecasting the unit costs of commercial/industrial service connections and tract development to be reasonable and we approve SCE’s use of its cost estimates to calculate its forecast capital expenditure forecast for Test Year 2018. 4.2.2. Rule 20 Issues SCE manages programs to convert existing overhead electric facilities to underground facilities pursuant to Tariff Rule 20. SCE explains that Rule 20 consists of three sub-parts: 1. Under Rule 20A, each governmental agency in SCE’s service territory is allocated a portion of SCE’s Commission-authorized Rule 20A capital budget to be used for overhead conversions based on a system wide formula. SCE describes Rule 20A conversion projects as “among the most complex projects within the Distribution Business Line. Each project requires coordination with multiple utilities and customers, and necessitates acquiring multiple permits based on the magnitude and duration of the projects.”57 2. Under Rule 20B, SCE converts overhead lines to underground at the request of a governmental agency, developer, an individual, 56 SCE-18, Vol. 2, at 9. We are left to infer that SCE’s reference to data from 2000-2006, which TURN did not rely upon, is meant to suggest that the activity in those earlier years created imbalances that were addressed from 2006-2010, and that justifies SCE’s approach of excluding the entire period and simply using data from 2011-2015. 57 SCE-02, Vol. 2, at 39. - 38 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 or a group of customers. SCE explains that these projects generally arise when a private party or governmental agency wishes to eliminate the visual impact of existing overhead lines in a proposed project, or must remove the lines as a condition to obtain permitting from various governmental agencies.58 The entity requesting a Rule 20B conversion pays part of the project costs. 3. Under Rule 20C, SCE converts overhead lines to underground when an individual customer or group of customers makes a request. SCE explains that these projects generally arise when an individual property owner or small developer of a new project wishes to remove existing overhead lines less than 600 feet in total length, or on one side of the street, or overhead lines on private property.59 The customer or customers requesting a Rule 20C conversion pays part of the project costs. ORA opposes SCE’s requested budget for Rule 20A. SCE states that in its 2015 rate case it simply used its forecast from the 2012 GRC as the basis for its projection of spending. SCE revised its approach in the instant proceeding. Based on its recorded costs for 2011-2015 and its estimated costs for 2016, SCE requests authorization of an annual amount equal to the five-year average of 2011-2015 recorded costs, which is $22.182 million in constant 2015 dollars during the forecast period (or $23.065 million for 2017, $23.643 million for 2018, $24.380 million for 2019, and $25.151 million for 2020 in nominal dollars).60 ORA notes that it has recommended reduced funding levels for this program because SCE’s subsequent recorded expenditures were usually less than the amounts authorized by the Commission. ORA showed in its testimony that 58 Ibid. 59 Id., at 40. 60 Id., at 41, Figure II-18: (Distribution Rule 20A Conversions Capital Expenditure Summary). - 39 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE failed to spend the amounts authorized in 2014, 2015 and 2016. ORA also notes that in D.15-11-021 the Commission adopted ORA’s proposal to adjust authorized Rule 20A expenditures to account for prior underspending.61 In this proceeding ORA again recommends the same approach, whereby the Commission adopts SCE’s forecasted 2017 and 2018 Rule 20A expenditures, but also incorporate an adjustment to reflect the underspending that occurred in 2014 through 2016. ORA calculates an adjustment of $9.558 million in each of the years 2017 and 2018 (each year’s proposed offset represents one half of the underspent $19.117 million). As ORA noted in its opening brief, since ORA filed its testimony in April 2017 the Commission has acted to address similar patterns of underspending of Rule 20A budgeted amounts by PG&E. The Commission’s decision in PG&E’s 2017 Test Year GRC ordered PG&E to establish a one-way Rule 20A balancing account that tracks the annual capital and expense costs for Rule 20A undergrounding projects, on a forecast and recorded basis. The Commission ordered that overcollected balances in the account shall remain available for future Rule 20A projects, and that the balances in the account would be reviewed in PG&E’s next GRC proceeding. We take the same approach here and order SCE to establish a one-way Rule 20A balancing account that tracks the annual capital and expense costs for Rule 20A undergrounding projects, on a forecast and recorded basis. With the creation of this one-way balancing account, we find it reasonable to authorize the capital expenditure forecasts requested by SCE, equal to $23.065 million for 2017 and $23.643 for 2018. 61 D.15-11-021 at 90. - 40 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.2.3. Distribution Transformers SCE states that its T&D organization must maintain an inventory of distribution transformers (rated less than 500 Kilovolt-Ampere (kVA) of load) because relatively large numbers must be on hand for installation and replacement on a regular basis. SCE explains that new service connections are a major driver for new transformer purchases, but most distribution work activity involves installing or replacing under-sized, failed or deteriorated transformers: SCE replaces distribution transformers when they fail in service, or when we observe deterioration during inspection or other fieldwork. Deterioration includes leaks, corrosion, and damage caused by vehicle collisions or acts of nature. When SCE replaces a pole or cable, it is often cost-effective and prudent to replace the attached transformer at the same time, depending on the condition of the transformer.62 SCE forecasts the total cost of transformer replacement for all activities by estimating the transformers needed for various activities as well as the cost per transformer for each activity. SCE’s forecast Test Year 2018 capital expenditures for distribution transformers is $95.217 million.63 ORA agrees with SCE's proposed methodology, but its recommended capital expenditure forecast for 2017-2018 differs from SCE’s because ORA modifies its inputs of units of work to reflect the numerous recommendations of various ORA witnesses regarding capital activities which utilize distribution transformers.64 62 SCE-02, Vol. 2, at 49. 63 SCE-18, Vol. 2, at 15, Table I-9 (Distribution Transformers Capital Expenditures, 100% CPUC Jurisdictional - Nominal $000) 64 ORA-08 (Wilson) at 61. ORA notes that SCE lists 31 different types of capital programs that require some level of transformer installation or replacement. - 41 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 In its rebuttal testimony, SCE agrees to revise its distribution transformer forecast based on the Commission's authorized amounts for those capital activities which utilize distribution transformers.65 Having resolved each of the contested items in SCE’s testimony on customer-driven programs, our final authorized levels of capital expenditures for each activity are shown in the table below. 65 SCE-18, Vol. 2, at 16. - 42 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Summary of Adopted 2017-2018 Capital Expenditure Forecasts for Customer-Driven Programs (100% CPUC Jurisdictional – Nominal $000) Activity Residential Service Connections Residential Line Extension Residential Tract Development Residential Backbone Development Commercial/Industrial Service Connections Commercial/Industrial Line Extensions Commercial/Industrial Tract Development Agricultural Service Connections Agricultural Line Extensions Street Light Installations Distribution Rule 20A Conversions Distribution Rule 20B Conversions Distribution Rule 20C Conversions Transmission Overhead to Underground Conversion Relocation of Distribution Lines Distribution Added Facilities Distribution Transformers Total Capital – Customer Driven Programs 4.3. SCE Proposed Total 2017 2018 2017-2018 2017 2018 27,736 35,363 63,099 28,134 30,857 58,991 24,067 31,425 55,493 24,216 26,733 50,949 88,536 94,530 183,066 70,808 75,710 146,518 27,151 28,941 56,092 18,049 19,294 37,344 24,654 25,877 50,531 16,850 18,172 35,023 39,294 41,338 80,632 39,500 42,604 82,104 14,877 15,694 30,571 14,324 15,314 29,638 2,500 2,562 5,062 2,500 2,562 5,062 2,710 30,511 2,779 38,900 5,489 69,411 2,710 30,949 2,779 33,944 5,489 64,893 23,065 23,643 46,708 23,065 23,643 46,708 14,558 14,924 29,482 14,558 14,924 29,482 8,008 8,210 16,218 8,008 8,210 16,218 5,888 6,031 11,919 5,888 6,031 11,919 58,953 60,437 119,390 58,953 60,437 119,390 12,807 90,531 13,130 95,217 25,937 185,748 12,807 82,669 13,130 89,446 25,937 172,115 1,034,848 453,988 483,790 937,777 495,846 539,001 Adopted Total 2017-2018 T&D – System Planning The Test Year 2018 O&M and capital expenditure forecasts presented in SCE’s testimony on transmission and distribution system planning is based on - 43 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s current 10-year plan for “the projects and programs required to expand, upgrade, and reconfigure the electrical grid over the next 10 years.”66 In this context, SCE states that the term “grid” refers to “the infrastructure comprised generally of transmission lines, substations, distribution circuits, and critical equipment such as circuit breakers, relays, substation transformers, conductors, and automation apparatus.” The overall drivers of SCE’s planning process are accommodating increased capacity needs (resulting from new customers or increased load from existing customers) while meeting system reliability. SCE states that in this GRC it has taken an integrated, long-term approach to planning and asset management to simultaneously account for multiple drivers such as aging infrastructure, technology changes, or policy goals. For Test Year 2018, SCE forecasts $1,039.208 million in capital costs67 and $14.726 million for O&M expenses.68 We authorize SCE’s uncontested O&M forecast. Various components of SCE’s capital expenditure forecast are opposed by ORA, TURN and SEIA-Vote Solar. ORA’s recommended reductions would result in a $261.66 million reduction to SCE’s 2017-2018 capital expenditure forecast.69 TURN’s recommended reductions would result in a $240.903 million reduction to SCE’s 2017-2018 capital expenditure forecast.70 SEIA-Vote Solar’s 66 SCE-02, Vol. 3R, at 1. 67 SCE-18, Vol. 3A, at 3, Table I-2 (Summary of System Planning Capital Expenditures, SCE and ORA Forecasts, Total Company – Nominal $000). 68 SCE-18, Vol. 3, at 6, Table I-5 (Summary of System Planning O&M Expenses). 69 SCE-18, Vol. 3A, at 3: Table I-2 “Summary of System Planning Capital Expenditures, SCE and ORA Forecasts, Total Company – Nominal $000)“. 70 Id., at 4: Table I-3 “Summary of System Planning Capital Expenditures, SCE and TURN Forecasts, Total Company – Nominal $000)”. - 44 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 recommended reductions would result in a $389.424 million reduction to SCE’s 2017-2018 capital expenditure forecast.71 Summary of Parties’ Positions on 2017-2018 Capital Expenditure Forecasts for System Planning (TOTAL COMPANY – Nominal $000) Activity SCE Added Facilities Projects Substation Expansion Projects Transmission System Generation Interconnection Generator Interconnection Program In-Service Projects 4 kV Cutover Program 4 kV Elimination Program Distribution Circuit Upgrades New Distribution Circuits Substation Equipment Replacement Program Subtransmission Lines Plan Distribution Var Plan Distribution Plant Betterment Substation Monitoring Programs A-Bank Plan Grid Reliability Projects Subtransmission VAR Plan Policy Driven Transmission Projects Right of Way Generation Interconnection RAS Total Capital - System Planning 71 49,184 224,101 117,209 1,758 9,191 72,618 317,765 100,485 90,137 49,785 205,582 12,953 28,840 400 64,728 406,248 2,653 260,134 1,063 25,766 2,040,601 ORA TURN SEIAVote Solar 49,184 215,602 117,209 1,758 9,191 56,315 180,210 99,438 67,463 20,825 157,913 12,953 28,840 400 64,728 406,248 2,653 260,134 1,063 25,766 1,777,893 0 0 144, 109 92,238 0 0 347,248 SCE-18, Vol. 3, at 5: Table I-4 “Summary of System Planning Capital Expenditures, SCE and SEIA-Vote Solar Forecasts, Total Company – Nominal $000)” with SCE forecast revisions incorporated from SCE-18, Vol. 3A, at 3: Table I-2. - 45 - 0 0 PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.3.1. Photovoltaic (PV) Dependability and Capacity-Driven Capital Expenditures We depart from the order of topics in the parties’ mutually agreed-upon common briefing outline in order to address what we consider a threshold recommendation by SEIA-Vote Solar, who contend that the peak load forecast that serves as the basis for SCE’s system planning forecast is fundamentally flawed. Specifically, SEIA-Vote Solar find fault with the PV dependability study that SCE used to determine how PV generation could be relied upon to offset peak load conditions. SCE uses “PV dependability” in its distribution planning process to determine how much of existing and forecast PV would be available to serve load during the system peak.72 SCE applies the PV dependability curve at two different stages of its planning process: (1) adjustment of recorded load and (2) development of forecast PV.73 According to SEIA-Vote Solar, SCE is underestimating PV dependability and overestimating peak loads, and thereby overestimating the need for capacity-related capital expenditures. Based on its contention that SCE’s study was flawed, SEIA-Vote Solar conclude that SCE's request for $878 million of projected capacity-related costs is not adequately supported and therefore cannot be approved by the Commission. Instead, SEIA-Vote Solar recommend that SCE be required to develop a new load forecast using a revised PV dependability curve, and then submit a new request for capacity-related projects based on that forecast. SEIA-Vote Solar explain their concerns by noting that 72 SEIA-Vote Solar-01, at 34-35, citing SCE response to SEIA-Vote Solar Data Request Question 1.13. 73 Id. at 35. - 46 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The Commission is undergoing a thoughtful process in the Distribution Resources Planning proceeding, the Integrated Distributed Energy Resources Proceeding and other forums, following a path and a vision outlined in the Commission’s DER Action Plan. We believe this vision is aligned with that held by SEIA and Vote Solar. SCE argues that its need for the first of several multi-billion-dollar, grid modernization applications requires jumping ahead of this deliberative process. The Commission need not deliberate over the timing of this case, however. Under any of SCE's rationales, the application shows itself to not only be premature, but simply unjustified. The bulk of SCE's grid modernization investments should be rejected and its distribution capacity investments should be revisited with greater scrutiny. SCE's next rate case, filed towards the end of the activities outlined in the DER Action Plan in 2019, will provide the utility with an opportunity to present a proposal more in line with what the Commission determines is in the interest of ratepayers.74 In rebuttal, SCE contends that SEIA-Vote Solar’s assessment of SCE’s PV growth forecast and PV dependability study is incorrect. SCE makes the following points in response to SEIA-Vote Solar. First, SCE asserts that it appropriately applies different PV output estimates in its studies, because the studies have different purposes: For system planning purposes, SCE uses minimum PV output to account for varying solar intermittency; this is appropriate because for system planning purposes, it is important to determine how much solar output the SCE system can rely on. SCE’s conservative approach is designed to help ensure SCE can provide adequate substation and distribution circuit capacity to serve forecast maximum (peak) loads.75 74 SEIA-Vote Solar Opening Brief at 5. 75 SCE-18, Vol. 3, at 34. - 47 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Conversely, for reverse power flow analysis, SCE appropriately uses maximum PV output and daytime minimum loads to reflect the highest level of solar output at times when reverse power flow is at its maximum. Again, this conservative approach is appropriate to help ensure SCE can plan for and mitigate adverse conditions including impacts to voltage, protection, and thermal limits.76 Second, SCE responds to SEIA-Vote Solar’s contention that “SCE’s forecast of PV growth is significantly higher than what market analysts expect in California in the 2018-2020 period” by noting that SCE’s cumulative total of approved net energy metering (NEM) as of June, 2017 was 1,864 MW, “well above” SEIA-Vote Solar’s reference point that estimated 1,658 MW in 2017.77 Third, SCE faults SEIA-Vote Solar’s proposal because SCE’s PV dependability analysis considers circuit and substation peak load; this contrasts with SEIA-Vote Solar’s PV dependability curve, which utilizes SCE’s top ten load days in 2010 and 2011, “which only includes a limited data set and may not account for circuit peaks occurring on different days and under different conditions, such as cloud cover.”78 SCE contends that its own PV dependability curve “includes more data points that span across its typical peaking period, which appropriately represents the variability of SCE’s PV output during peak periods.”79 SCE states that this data includes 15 minute interval data from June to September, for all generators across SCE’s system, to estimate daily PV output. 76 Ibid. 77 Id. at 35. 78 Ibid. 79 Id. at 35-36. - 48 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Finally, SCE responds to SEIA-Vote Solar’s criticism that SCE did not properly account for Demand Response (DR) and Energy Storage. SCE states that “the impact of DR is taken into consideration during the adjustment to our annual summer peaks on SCE’s substations and circuits.”80 SCE agrees that storage plays a significant role in meeting its requirements for Local Capacity Requirements (LCR), “but these resources are procured to meet bulk system requirements, not distribution. Because these resources are largely dispatched by the California Independent System Operators (CAISO), SCE cannot rely on these resources for distribution reliability and hence, are not included in the forecast.”81 Based on our review of SEIA-Vote Solar’s critiques of SCE’s PV dependability study, and SCE’s rebuttal of those criticisms, we find that it is reasonable to accept SCE’s use of its study for the purpose of preparing its GRC forecast. However, we do not discount SEIA-Vote Solar’s motivation for conducting its analysis: “SEIA and Vote Solar share SCE's objective of creating new opportunities for DERs [Distributed Energy Resources], but our vision diverges substantially from that … manifested in this application.”82 SEIA and Vote Solar go on to explain that they “envision new benefits being created by DERs beyond the benefits they provide directly to host customers by reducing utility expenditures on the distribution system while also improving customer electric services. In this regard, we support a number of investments that SCE proposes, which we have determined are truly needed to facilitate DER 80 Id. at 36. 81 Ibid. 82 SEIA-Vote Solar Opening Brief at 4. - 49 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 deployment. However, the scale of these resources is modest, particularly in comparison to SCE's dramatic proposal.”83 We acknowledge SEIA-Vote Solar’s concerns regarding the scale and timing of SCE’s requests, but we disagree that simply rejecting SCE’s application is the correct solution. For that reason, we proceed with our review of each specific request made by SCE and decide each of them on their merits. 4.3.2. Distribution Circuit Upgrades SCE considers distribution circuit upgrades when it forecasts any portion of its distribution system to be overloaded and if existing distribution equipment cannot meet the needs of the system. Typical work under this category includes installing new switches, upgrading cable or conductor, or installing new conductor to create circuit ties to facilitate load transfers between substations and circuits. TURN recommends reducing SCE's 2017-18 capital expenditure forecast by $8.247 million, from $100.485 million to $92.238 million. TURN contends that SCE's DER forecast should exclude circuit upgrades driven by wholesale DERs because SCE should seek recovery of the costs to accommodate wholesale DERs through Tariff Rule 21. In rebuttal, SCE affirms that wholesale DER interconnection customers met the requirements of Tariff Rule 21 at the time they connected to SCE’s system, including paying for all upgrades triggered by their interconnection at the time of the connection. Furthermore, regardless of installed wholesale DERs, SCE must upgrade the circuits identified in its testimony to be able to accommodate its forecast of future retail DER. Thus, 83 Id. at 5. - 50 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 “SCE cannot and should not require wholesale DERs, already connected to SCE's system, to pay for circuit upgrades triggered by new retail DER.”84 We authorize SCE’s requested 2017-2018 capital expenditure forecast of $100.485 million for Distribution Circuit Upgrades.85 4.3.3. New Distribution Circuits If Distribution Circuit Upgrade projects cannot meet the need of a forecasted overload on SCE’s distribution system, or the Distribution Circuit Upgrade solution is economically unfeasible and does not meet the long-term needs of the area, SCE will consider new distribution circuit solutions in the Distribution Substation Plan (DSP). SCE builds new distribution circuits as part of three types of projects: (1) new substation projects, (2) substation capacity increase projects, and (3) as standalone projects. ORA recommends reducing SCE's 2017-18 capital expenditure forecast from $90.137 million to $67.463 million, based on SCE's 2016 actual recorded costs and then escalating SCE's 2016 forecast for 2017 and 2018.86 In rebuttal, SCE states that it developed the New Distribution Circuit forecast on a project-specific basis to meet needs identified during SCE’s planning process. ORA’s methodology did not address SCE’s project-specific forecast and ORA does not contest the need for any specific projects SCE identified as necessary, so we will not rely upon ORA’s formulaic 84 SCE-18, Vol. 3, at 12-13, emphasis added. 85 SCE-18, Vol. 3A, at 12, Table 111-7 (Distribution Circuit Upgrades Capital Expenditures). 86 Exhibit ORA-09, at 74. - 51 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 recommendation here. We authorize SCE’s requested 2017-2018 capital expenditure forecast of $90.137 million for New Distribution Circuits.87 4.3.4. Substation Expansion Projects Substation expansion projects are undertaken when a distribution substation is expected to exceed its planning limits and cannot transfer load to a neighboring substation, and the expansion project is the most cost effective solution when compared against others, such as adding a new distribution circuit.88 These projects fall into three categories: (1) substation capacity projects located within scope in the existing substation footprint; (2) substation expansion that includes projects where the substation perimeter fence requires expansion; and (3) new substations. ORA stated in testimony that it expects one of SCE’s projects, the new “Safari” substation located in Irvine, will be delayed due to community discontent and will not be completed in this GRC cycle. In rebuttal, SCE states that it plans to complete the project in 2018: as of April, 2017 approximately 55% of the project scope had been completed, with an estimated 12 months of construction work remaining.89 Based on the additional information provided by SCE in its rebuttal testimony, we decline to adopt ORA’s recommendation. We authorize SCE’s requested 2017-2018 capital expenditure forecast of $224.101 million for Substation Expansion Projects Capital Expenditures.90 87 SCE-18, Vol. 3, at 10: Table 111-6 “New Distribution Circuits Capital Expenditures.” 88 SCE-02, Vol. 3RA, at 40. 89 Exhibit SCE-18, Vol. 3, at 14-15. 90 SCE-18, Vol. 3, at 14, Table 111-8 (Distribution Circuit Upgrades Capital Expenditures). - 52 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.3.5. Substation Equipment Replacement Program SCE’s Substation Equipment Replacement Program (SERP) is one of three programs within the company’s “System Improvement Planning Process” (the others are the Distribution VAR (reactive power) plan and the Substation Monitoring Programs).91 SCE states that “these programs include upgrades to the distribution system that involve protection, reactive power support, and monitoring substation loading and duct bank temperatures…”92 The SERP “evaluates the adequacy of substation terminal equipment and system protection equipment, and proposes upgrades when deficiencies are identified. The SERP identifies substations where available fault current, or short-circuit duty, exceeds safe equipment ratings essential to the provision of safe, reliable service.”93 ORA recommends reducing SCE's 2017-18 capital expenditure forecast by $28.96 million, from $49.785 million to $20.825 million. That amount is equal to 2015 authorized capital expenditures, with escalation, for 2017 and 2018. ORA contends that SCE has not demonstrated the need for more funds than authorized in 2015, has not supported its capacity to do more work, did not provide a supportive study referenced in its direct testimony, and did not acknowledge or explain the unit cost increases that underlie its forecast. 91 SCE explains that “Volt-ampere reactive power (VAR) is the unit used to measure reactive power in alternating current electric systems. Because alternating current systems have varying voltage, these systems must vary the current with the voltage to maintain stability. VARs measure the lead or lag between synchronization of voltage and current.” SCE-02, Vol. 3, at 44. 92 SCE-02, Vol. 3RA, at 43. 93 Ibid. - 53 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE addressed each of ORA’s contentions in rebuttal testimony and clarified where its support for its requested expenditures can be found in the proceeding record. SCE also re-emphasized that its forecast spending “is required to replace overstressed circuit breakers on SCE’s system.”94 Based on SCE’s support for its proposal, we authorize SCE’s requested amount for 2017-2018 of $49.785 million.95 4.3.6. Subtransmission Lines Plan The objective of SCE’s Subtransmission Lines Plan is to provide adequate 66 kV or 115 kV line capacity in each of its subtransmission networks to serve forecast peak loads at its B-substations.96 SCE requests approval of its forecast 2017-2018 capital expenditures of $205.582 million, of which $205.127 million is CPUC-jurisdictional.97 ORA notes that SCE’s recorded spending in 2016 for these projects totaled $25.571 million lower than its forecast, and questions whether SCE’s new forecast is accurate. ORA recommends approval of $157.913 million for 2017-2018, which is the simple average of SCE’s recorded and forecast values for 2016-2020. In rebuttal, SCE explains that its forecast is based on project-specific requirements, and that it expended less than forecast in 2016 due to construction permitting and other unexpected delays on specific projects. 94 SCE-18, Vol. 3, at 17. 95 Id., Table 111-9 (Substation Equipment Replacement Program Capital Expenditures). 96 SCE-02, Vol. 3RA, at 93. SCE-02, Vol. 3R, at 57, Table IV-14 (Distribution & Subtransmission Planning Capital Expenditure Summary). 97 - 54 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We find that SCE’s rebuttal testimony addressed the concerns raised by ORA, and we therefore authorize SCE’s requested amount for 2017-2018 of $205.582 million.98 4.3.7. 4 kV Programs SCE requests funding for two separate 4 kV programs: its 4 kV Cutover Program converts portions of 4 kV circuits to higher voltages in order to reduce load and foster reliability; its 4 kV Substation Elimination Program involves conversion of the entire 4 kV circuitry from a substation to higher voltage. SCE states that most of its circuits operate at voltages of 12 kV, 16 kV, or 33 kV but over 25% of its circuits and roughly 20% of its substations operate at voltages of 4 kV or lower.99 SCE contends that this system poses several challenges in system operations that impact its ability to reliably serve customers due to age, obsolescence, and increased load and DER growth.100 SCE also notes that while 26% of households in SCE’s service territory are in disadvantaged communities, 44% of households served by 4 kV circuits are in those communities.101 SCE summarizes the drivers for its 4 kV program as (1) mitigating safety and reliability risks of old and obsolete equipment; (2) alleviating space constraints that prevent expansion of existing 4 kV substations; (3) providing operational flexibility and mitigating power quality concerns; (4) preventing future circuit overloads due to insufficient capacity; (5) minimizing energy losses 98 SCE-18, Vol. 3, at 18, Table 111-10 (Subtransmission Lines Plan Capital Expenditures). 99 SCE-18, Vol. 3, at 20. 100 SCE-02, Vol. 3RA, at 76. 101 Ibid. - 55 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 because the overall cost to provide electricity at 4 kV is greater than at either 12 kV or 16 kV; and (6) DER integration.102 SCE explains why it decided in this GRC to include DER integration as a factor when identifying the need for conversions and eliminations of 4 kV substations: As customers adopt more DERs, the reliability and capacity issues associated with 4 kV systems are expected to be exacerbated, absent modernization of SCE’s distribution system:  Many 4 kV systems lack sufficient DER hosting capacity because they operate with lower overall capacity;  4 kV systems lack existing automation and impede the future addition of automation technology;  Without the automation technology to give operators visibility and control, coupled with outdated voltage regulation schemes, problems with capacity and voltage quality will continue if not increase; and SCE contends that the lack of automation in SCE’s 4 kV systems prevents grid operators from quickly identifying, troubleshooting, and restoring power.103 4.3.7.1. 4 kV Cutover Program SCE states that when circuits and substations experience overloads that require immediate attention, it will cutover partial circuits sufficiently to reduce the loading below the established planned loading limits.104 SCE states that this approach will ameliorate the problem in the short run and is a cost-effective solution until larger portions of the substation or circuit must be upgraded. 102 SCE-02, Vol. 3RA, at 76-83. 103 Id. at 84. 104 Id. at 86. - 56 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s 2017-2018 forecast of capital expenditure for this program is $72.618 million.105 ORA recommends a reduction in SCE’s forecast capital spending of $16.303 million to $56.315 million. ORA developed its own 2017-2018 forecasts using 2015 GRC authorized amounts, stating that SCE has not provided reasoning and justification for (1) SCE’s spending pattern in 2014-2015, and (2) SCE’s decision to change the basis for its forecast from a methodology based on “amps cutover” to one based on “transformers removed.” ORA asserts that SCE’s forecast unit cost is 2.5 times higher than the historical average and therefore recommends that the Commission authorize the same budget approved in D.15-11-021. TURN supports the 4 kV cutover program because its witness found that cutovers of 4 kV circuits due to overloads is “reasonable and effective.”106 TURN recommends that the Commission authorize the program but disallow $8.388 million from SCE's 2018 test year forecast of $36.663 million, finding that ORA’s analysis demonstrates that SCE's forecast unit cost per circuit is more than double the historical average for 2006-2016. In rebuttal, SCE defends its change in methodology by explaining that “while Amps are used to measure the overload on a circuit, the mitigation is achieved by removing and replacing transformers.”107 SCE explains that it updated its forecast methodology to use the count of transformer replacements as the cost unit because the number of transformers replaced is a better indicator 105 SCE-18, Vol. 3, at 18: Table III-11 “4 kV Cutover Program Capital Expenditures.” 106 TURN-06, at 33 and 40. 107 Id. at 22. - 57 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 of the scope of work needed. According to SCE, the number of transformers that needs to be replaced on a circuit to cutover a certain number of Amps can vary significantly depending on the specific characteristics of the circuit.108 Finally, SCE finds flaws in ORA’s methodology for reconciling the differences between Amps-based unit costs and transformer-based unit costs and concludes that “for these reasons, ORA’s per-circuit unit cost analysis should not be used for comparison or forecasting purposes.”109 We find that SCE has demonstrated that its methodology for estimating the scope and cost of its 4 kV cutover program is reasonable. We approve SCE’s requested levels of 2017 and 2018 funding ($35.955 million in 2017 and $36.663 million in 2018, for a 2017-2018 total equal to $72.618).110 4.3.7.2. 4 kV Substation Elimination Program SCE describes complete elimination of 4 kV substations as the best long-term option when drivers such as aging infrastructure, costs, reliability, and high penetration of DERs require a longer-term solution.111 SCE cites benefits including avoidance of additional costs to replace obsolete equipment, improved operational flexibility and reduced maintenance costs, improved safety, reliability and power quality, and enabling higher penetration of DERs. SCE’s 2017-2018 forecast of capital expenditures for this program is $317.765 million.112 108 Id. at 23. 109 See SCE-18, Vol. 3 at 23-24. 110 SCE-18, Vol. 3, at 21: Table III-11 “4 kV Cutover Program Capital Expenditures.” 111 SCE-02, Vol. 3RA, at 85. 112 SCE-18, Vol. 3, at 21: Table III-12 “4 kV Elimination Program Capital Expenditures.” - 58 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 CUE supports the substation elimination program, but recommends that the Commission require SCE to remove these substations at a faster pace than requested by SCE.113 ORA recommends a reduction in the 2017-2018 forecast to $180.21 million. ORA bases its proposal on the expenditures authorized in the 2015 GRC, arguing that SCE did not present evidence in its application or workpapers to support the forecast increase or provide data to allow reviewers to accurately compare the 4 kV Substation Elimination Program across rate cases.114 TURN opposes continuation of the substation elimination program, other than providing limited test year 2018 funding of $4.9 million to enable elimination of one substation per year to address specific substations that have unusual reliability problems. TURN estimates this would reduce SCE’s test year 2018 capital forecast of $178.556 million by $173.659 million.115 TURN agrees that the Commission has previously approved this program, but contends that the Commission has never evaluated the drivers cited by SCE in support of its proposal. TURN reviewed SCE’s rationale for the program and conducted a cost-benefit analysis of SCE’s proposed expenditures and concluded the following:  The age of 4 kV substations and circuits does not in itself justify wholesale preemptive replacement  SCE’s contention that 4 kV circuits exhibit declining reliability conflicts with the available evidence, which demonstrates 4 kV 113 CUE-01, at 8. 114See 115 ORA-09, at 85. TURN Opening Brief at 9. - 59 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 circuits have the same, if not better, reliability as higher voltage circuits  SCE’s elimination program fails a basic benefit-cost analysis o It is not cost-effective to preemptively replace 4 kV substations o There is no basis to assume SCE would need to rebuild all the 4 kV substations targeted for elimination  SCE’s equity concerns regarding 4 kV circuits are not supported by the data o There is no valid environmental justice issue regarding 4 kV circuits o There is no existing or forecast problem with DER capacity on 4 kV circuits TURN also claims SCE has exaggerated the risk associated with retaining 4 kV substations, and suggests that SCE undertake cutovers instead of substation elimination as capacity problems arise. TURN acknowledges the reliability benefits associated with 4 kV upgrades, but contends that all customers should not pay for costs that benefit 12% of the customers.116 Based on the same cost-benefit analysis, TURN expresses its concerns that SCE could be harming low-income customers by expanding what TURN calls SCE’s “non-cost-effective 4 kV Substation Elimination Program.”117 In rebuttal, SCE reiterates its position that the drivers of the elimination program, in combination, warrant its requested level of funding; SCE faults TURN for dismissing each driver in turn, without considering their combined effects. SCE also contends that TURN’s proposal “translates to a run-to-failure 116 See Exhibit TURN-06, at 33. 117 See Exhibit TURN-10, at 33-36. - 60 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 model for 4 kV substation equipment, in which breakdown replacement is infeasible as spare parts are not available and physical constraints at the substations will hinder upgrades or equipment replacement.”118 SCE, on the other hand, “believes it is necessary to proactively remove obsolete substation equipment that has reached the end of its useful life. 4 kV Substation Elimination is consistent with other preemptive infrastructure replacement programs that replace obsolete and failing equipment prior to in-service failure.”119 We find TURN’s thorough analysis of SCE’s proposal to be convincing. As TURN observes, the Commission authorized $85 million for this program in 2015, less than 50% of SCE’s current request, and in this rate case ORA recommends continuing with the same level of funding authorized in the Test Year 2015 rate case. TURN further observes “in the last rate case, it does not appear that any party actually contested the spending.”120 Now that SCE proposes to expand the pace of the program, a closer look is warranted. TURN conducted the necessary analysis and demonstrated that the program provides questionable benefits. On this basis, we find that SCE’s request for full funding of the program in the 2018-2020 period should be denied. Instead, we approve the level of funding recommended by TURN for the 2018 test year, which we calculate to be $4.897 million ($178.556 million minus $173.659 million). 4.3.8. Grid Reliability Projects SCE explains that Grid Reliability Projects are planned on the portion of SCE’s system that is under operational control of the CAISO. SCE forecasts 118 SCE-18, Vol. 3, at 25. 119 Ibid. 120 TURN Opening Brief at 10. - 61 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Test Year 2018 capital expenditures of $185.128 million on a Total Company basis, of which $77.98 million is CPUC-jurisdictional. TURN contends that the Cerritos Channel Transmission Line Relocation project is unlikely to be used and useful during the 2018-2020 rate case period, and recommends that the entire $57.904 million forecasted amount (2016-2020, CPUC jurisdictional) be disallowed. In rebuttal, SCE contends that the project is on an “expedited” track to completion and that SCE does not expect any delay in receiving its permit to construct or in completing construction on this project. The Commission granted SCE a permit to construct the Cerritos Channel Transmission Tower Replacement Project in D.18-08-021. In that decision, the Commission noted that construction of the project is scheduled to begin September 1, 2018 and to be completed by the fourth quarter of 2020.121 On this basis, we agree with TURN that the project is unlikely to be used and useful during the 2018-2020 rate case period. Therefore, we disallow the inclusion of all spending prior to 2016 and the $57.904 million forecasted amount (CPUC jurisdictional) requested by SCE for the 2016-2020 period. For Test Year 2018, the disallowed amount is $34.048 million (CPUC jurisdictional).122 4.4. T&D – Distribution Maintenance and Inspection SCE states that its Distribution Maintenance and Inspection organization performs maintenance and inspection activities associated with SCE’s 121 D.18-08-021 at 3. 122 SCE-02, Vol. 3R, at 53, Table IV-8, line 3 (Grid Reliability Projects Capital Expenditure Summary). - 62 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 distribution grid, including planned and unplanned work.123 SCE developed its forecast by using its 2015 recorded adjusted expenses as a basis for proposed Test Year projects and activities. For Test Year 2018, SCE forecasts $273.955 million in capital costs124 and $159.968 million for O&M expenses.125 SCE’s requests are unopposed. We authorize SCE’s undisputed Test Year 2018 forecasts. 4.5. T&D – Distribution Construction & Maintenance SCE states that its Distribution Construction & Maintenance organization performs all activities associated with installing, maintaining, replacing, and removing distribution electrical equipment, structures, and other facilities.126 For Test Year 2018, SCE forecasts $203.700 million in capital costs127 and $70.491 million for O&M expenses.128 SCE’s capital request is unopposed, and we approve it based on our own review of SCE’s forecast. ORA recommends O&M expense reductions totaling $4.544 million. First, for Street Lighting Operations and Maintenance (Federal Energy Regulatory Commission (FERC) sub-account 585.170), ORA recommends a Test Year O&M reduction from $6.936 million to $4.543 million. In rebuttal 123 Ex. SCE-2, Vol. 4, at 1. 124 SCE-18, Volume 04, at 1, Table I-1 (Distribution Maintenance and Inspection Capital Summary). 125 SCE-18, Volume 04, at 2, Table I-2, (Summary of Distribution Maintenance and Inspection O&M Expense). 126 Ex. SCE-2, Vol. 5, at 1. 127 SCE-18, Volume 05, at 1, Table I-1 (Summary of Distribution Construction and Maintenance Capital Expenditures). 128 SCE-18, Volume 05, at 2, Table I-2 (Summary of Distribution Construction and Maintenance O&M Expenses). - 63 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 testimony, SCE suggests that ORA’s recommendation appears to reflect a mistaken reading of SCE’s streetlight model (which produces the forecast), by omitting one of the four categories of costs from the calculation.129 ORA did not respond to SCE’s observation, which SCE documents with reference to data responses provided to ORA.130 SCE’s explanation is reasonable. We adopt SCE’s Test Year 2018 forecast for FERC sub-account 585.170, equal to $6.936 million.131 Second, ORA opposes SCE’s request regarding Service Guarantees #2 and #3 (FERC sub-account 587.170). SCE provides two T&D-related service guarantees to its customers: (1) that SCE will restore power within 24 hours of learning of an unplanned outage, and (2) that SCE will provide affected customers with a three-day advance notice of any planned outages. Currently, the guarantee payouts ($30 per incident to each impacted customer) are shareholder funded. SCE proposes that the Commission depart from its long-standing historical practice of having shareholders be responsible for the costs of credits paid out for missing service guarantees. ORA notes that the Commission rejected SCE’s proposal in D.15-11-021 and recommends that Commission continue to assign all of the costs of these credits to shareholders.132 We agree with ORA. SCE has not made a persuasive argument that ratepayers should fund SCE’s service guarantees. That responsibility shall continue to fall on SCE’s shareholders. 129 SCE-18, Vol. 5, at 8. 130 Ibid. 131 Id. at 7, Table I-6 (Streetlight Operations and Maintenance, Constant 2015 $000). 132 ORA-07, at 15-17. - 64 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Third and finally, for Distribution Storm O&M (FERC sub-account 598.170), ORA proposes a reduction in SCE's forecast from $9.388 million to $7.814 million and proposes to implement a one-way balancing account. SCE and ORA disagree over whether SCE’s forecast should be based on recorded data from 2012-2016 (ORA) or 2011-2015 (SCE). However, we find more compelling ORA’s testimony showing that SCE significantly underspent the budgets authorized by the Commission in its 2012 GRC and its 2015 GRC.133 For this reason, we authorize Test Year 2018 O&M for FERC sub-account 598.170 equal to the amount recommended by ORA, $7.814 million.134 Regarding its proposed one-way balancing account, ORA contends that it will benefit ratepayers because unspent funds will be returned to them, rather than directed to other uses by SCE. SCE responds that a one-way balancing account would unfairly penalize shareholders for acts of nature that are outside of SCE’s control, given the unpredictability of the weather. SCE notes that such an account would lead to an unbalanced outcome where ratepayers would receive refunds in years when the weather was mild, but shareholders would likely fund part of storm-related repairs in years when the weather was more severe. We denied a similar request by ORA in our decision on SCE’s 2015 GRC. We deny ORA’s request again in this decision. While we generally share ORA’s concerns regarding underspending of amounts authorized in previous GRC decisions, in this specific instance we agree with SCE that storm-related spending 133 Id. at 18. 134 SCE-18, Vol. 5, at 3, Table I-3 (Distribution Storm O&M, Constant 2015 $000). - 65 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 will vary with the weather. We anticipate that ORA’s more reasonable forecast will result in less underspending, thus making ORA’s proposed balancing account unnecessary. 4.6. T&D – Substation Construction & Maintenance SCE states that its Substation Construction & Maintenance O&M expense forecast supports activities such as inspection and maintenance of SCE’s substation equipment, substation and grid control center operating activities, and other substation activities, including inspecting, maintaining, and replacing protection and control equipment, spare parts, tools and work equipment, improving the physical security of substations, and modernizing outdated grid control rooms. For Test Year 2018, SCE forecasts $78.15 million for O&M expenses.135 For capital, SCE's direct testimony presented its 2016-2020 capital forecast (CPUC jurisdictional) of $590 million, of which $83.7 million, $92.3 million, and $136.5 million are forecast for 2016, 2017, and 2018, respectively.136 In its rebuttal testimony, SCE made the following changes to its capital forecast: • SCE agreed with ORA to use 2016 recorded costs (as opposed to 2016 forecast cost) for capital expenditures. • In alignment with the testimonies of ORA, TURN, and SEIA-Vote Solar, SCE is no longer seeking costs for the Subtransmission Relay Upgrade in 2018-2020. 135 See Table I-1, at 2, of Exhibit SCE-18, Vol. 6. 136 See Table I-3, at 2, of Exhibit SCE-02, Vol. 6. - 66 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN originally opposed one aspect of SCE’s request regarding SCE’s Substation Protection and Control System Replacement program, but withdrew that opposition in its opening brief.137 After these agreements, one capital issue remains disputed. Regarding Substation Physical Security, SCE proposes to upgrade eight substation projects per year from 2016-2020.138 ORA proposes that SCE be allowed to upgrade only five substations per year in 2017-2018, based on its view that only those substations that experienced four thefts have a “high frequency” of incidents. SCE contends that “[d]epending on the circumstances, it would not be safe or prudent for SCE to wait until a substation experiences four copper thefts before SCE makes upgrades” so ORA’s proposal leaves too many sites vulnerable, thus placing SCE employees and members of the public at risk. We find that SCE’s rebuttal testimony effectively refuted ORA’s recommendation to reduce SCE’s requested funding for Substation Physical Security. We authorize SCE’s requests for $8.321 million in 2017 and $8.530 million in 2018.139 Having resolved this disputed item, we adopt SCE’s capital expenditure forecast for Test Year 2018, $176.329 million.140 We also adopt SCE’s undisputed Test Year 2018 O&M forecast of $78.15 million.141 137 TURN Opening Brief at 20. 138 Exhibit SCE-02, Vol. 6, at 46. See Table I-17 on p. 46, which shows the nominal costs of the enhancements for the eight substations/year to be approximately $1 million/substation. 139 Exhibit SCE-29, at 228. 140 SCE-18, Vol. 6, at 3, Table I-2 (Summary of Substation Construction & Maintenance Capital Expenditures). This table includes SCE’s 2018 total forecasted amount of $217.917 which includes $41.589 million for the Substation Relay Upgrade project that SCE subsequently agreed to remove (see SCE-18, Vol. 6, at 17-19). Removal of the $41.589 results in the adopted forecast expenditures, $176.329 million. - 67 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.7. T&D – Transmission Construction & Maintenance SCE states that its Transmission Construction & Maintenance forecast supports its transmission inspection, maintenance, and construction activities. Transmission inspection activities include routine annual patrols and inspections of SCE’s overhead and underground transmission lines and additional inspections during and after storms or other emergencies. Transmission maintenance activities include transmission line maintenance, insulator washing, and road and right-of-way maintenance. SCE’s capital expenditure request supports transmission relocations, claims, and maintaining a spare parts inventory. Finally, SCE’s request also includes costs to inspect and maintain the company's fiber-optic communications network, which includes over 5,000 miles of fiber-optic cable.142 For Test Year 2018, SCE forecasts $40.918 million for O&M expenses.143 SCE’s Test Year 2018 capital forecast equals $216.793 million.144 ORA opposes a portion of SCE’s O&M forecast for FERC Account 571.150: (1) Transmission Overhead and Underground Line Maintenance, (2) Transmission Vegetation Management. Regarding SCE’s capital forecast, ORA recommends reductions of $616,000 in 2016 and $519,600 in 2017 for transmission tools and work equipment activities. 141 Id., at 2, Table I-1 (Summary of Substation Construction & Maintenance O&M Expenses). 142 SCE-02, Vol. 7, at 1. 143 SCE-18, Vol. 7, at 2, Table I-1 (Transmission Construction and Maintenance Summary of O&M Expenses, Constant 2015 $000). 144 Id. at 3, Table I-2 (Transmission Construction and Maintenance Summary of Capital Expenditures, Total Company – Nominal $000). - 68 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.7.1. Transmission Overhead and Underground Line Maintenance – FERC Account 571.150 (partial) SCE’s Test Year 2018 forecast for Transmission Overhead and Underground Line Maintenance is $6.840 million, which is equal to the last recorded year for this expense, 2015. ORA recommends $5.786 million, which is based on a 4-year average of recorded costs (2011-2013 and 2015; both ORA and SCE agree that 2014 recorded costs are an outlier). In rebuttal testimony, SCE explains that the T&D division changed its overhead accounting methodology in 2014, which renders the 2011-2013 non-labor expenses unrepresentative of test year expenses.145 ORA did not challenge SCE’s rebuttal testimony in hearings or briefs. We find SCE’s support for its forecast to be reasonable and adopt SCE’s Test Year 2018 forecast of $6.840 million.146 4.7.2. Transmission Vegetation Management – FERC Account 571.150 (partial) SCE states that Transmission Vegetation Management includes the expenses associated with tree trimming and tree removal in proximity to transmission and distribution high voltage lines, and weed abatement around overhead structures in proximity to high voltage transmission and distribution lines located in high-fire designated areas. These expenses also include costs of planting different species of trees as replacements and undertaking preventive soil treatment. SCE states that the majority of costs are from a fixed price 145 Exhibit SCE-18, Vol. 7, at 5-6. 146 Id. at 24, Table I-1 (Transmission Construction and Maintenance Summary of O&M Expenses) and SCE-02, Vol. 7, at 14, Table II-6 (Transmission Overhead and Underground Line Maintenance, Portion of GRC Account 571.150, Recorded and Adjusted 2011-2015/Forecast 2016-2018Transmission and Overhead Underground Line Maintenance). - 69 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 contract with SCE’s tree trimming contractors, which requires them to maintain compliance for the approximately 1.5 million trees that exist in proximity to energized conductors throughout SCE’s service territory.147 SCE’s Test Year 2018 forecast for Transmission Vegetation Management is $10.443 million, which is equal to the last recorded year for this expense, 2015. SCE explains that it took this approach to best reflect “the work expected in the Test Year and the new vendor contract term implemented in May 2014.”148 ORA recommends $9.474 million, which is based on a two-year average of recorded expenses (2014-2015). In rebuttal testimony, SCE contends that the use of the most recent recorded year is reasonable because (1) the new vendor contract covered only part of 2014 and (2) the Commission has previously found that “if costs have shown a trend in a certain direction over three or more years [as is the case here], the last recorded year is an appropriate base estimate.”149 ORA did not challenge SCE’s rebuttal testimony in hearings or briefs. We find SCE’s explanation reasonable and authorize SCE’s Test Year 2018 forecast of $10.443 million.150 4.7.3. Transmission Tools and Work Equipment SCE states that Transmission Tools and Work Equipment include the costs for acquiring and retiring portable tools and work equipment that cost more than 147 SCE-02, Vol. 7, at 24. SCE further explains “SCE must comply with many vegetation regulations including General Order (GO) 95 Rules 35 and 37; Public Resources Code §§ 4292 and 4293; and FERC FAC-003-2, which require SCE to manage vegetation near its wires. SCE engages a contractor to trim and remove trees and weeds, and other activities, to facilitate compliance with these requirements.” Ibid. 148 Id. at 25. 149 SCE-18, Vol. 7, at 8, citing D.89-12-057 and D.04-07-022. 150 Id. at 4, Table I-3 (Transmission and Overhead Underground Line Maintenance, Constant 2015 $000). - 70 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $1,000, such as electric generators, cable pulling equipment, gas monitors, air compressors and compression tools for making high voltage electrical connections.151 SCE used a five-year average (2011-2015) to develop its 2016 – 2018 forecasts due to the unpredictability of equipment retirements and external drivers.152 ORA proposes to use SCE’s recorded adjusted capital expenditure for 2016, and SCE agrees. For 2017, ORA recommends reducing SCE’s 2017 forecast to 70% of SCE’s 2015 recorded expenditures to be consistent with SCE’s forecast for Transmission Planned Capital Maintenance, which SCE has separately reduced to 70% of prior levels, due to resource constraints. ORA bases its adjustment on what it states appears to be a correlation between increased expenditures on Transmission Tools and Work Equipment and the increased workload starting in 2013 in the Transmission Planned Capital Maintenance program. In rebuttal testimony, SCE contends that ORA’s proposed reduction is based on incorrect assumptions and analysis: (1) the tools and equipment in question are used to support all activities in Transmission Construction and Maintenance, not just Transmission Planned Capital Maintenance; and (2) there is not, in fact, a statistically strong correlation between Transmission Tools and Work Equipment and Transmission Planned Capital Maintenance.153 151 SCE-02, Vol. 7, at 33-34. 152 Id. at 34. 153 SCE-18, Vol. 7, at 10-13, providing SCE’s statistical analysis. - 71 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s reasoning and analysis convincingly support its position. We authorize the following SCE capital expenditure forecasts: for 2016, $1.274 million; for 2017, $1.917 million; and for 2018, $1.953 million.154 4.8. T&D – Infrastructure Replacement SCE’s distribution and substation infrastructure includes major equipment such as transformers, switches, circuit breakers, capacitors, automatic reclosers (ARs), cable, and conductors.155 SCE states that its Infrastructure Replacement programs reduce the impact of aging infrastructure on the reliability and safety of SCE’s distribution and substation systems by replacing equipment before it fails in service.156 SCE's proposed 2017-2018 capital expenditures in its 11 Infrastructure Replacement programs total $964.532 million.157 ORA recommends reductions totaling $68.803 million; TURN recommends reductions totaling $182.823 million; and CFC recommends reductions totaling $23.214 million. Parties’ positions are summarized in the table below. 154 SCE Opening Brief at 32. SCE clarifies that it is in agreement with ORA regarding the 2016 and 2018 forecasts. 155 SCE-02, Vol. 8, at 1. 156 Id., Summary. 157 SCE-18, Vol. 8A, at 2, Table I-1 (Summary of Infrastructure Replacement Capital Expenditures). - 72 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Requested Infrastructure Replacement Capital Expenditures Total Company – Nominal $000 Activity Distribution Infrastructure Replacement Program Worst Circuit Rehabilitation Cable Life Extension CIC Replacement Overhead Conductor Program Underground Oil Switch Replacement Capacitor Bank Replacement158 Automatic Recloser Replacement Substation Infrastructure Replacement Program PCB Transformer Replacement Substation Transformer Bank Replacement Substation Circuit Breaker Replacement Substation Switchrack Rebuilds Total Request Total 2017-2018 2017 2018 123,106 23,402 31,142 136,087 11,150 13,674 2,310 126,207 23,991 41,643 139,514 12,701 14,018 2,368 249,313 47,393 72,785 275,601 23,851 27,692 4,678 1,413 66,349 43,875 18,362 470,870 1,449 68,003 44,943 18,825 493,662 2,862 134,352 88,818 37,187 964,531 Parties that Proposed Reductions ORA TURN CFC 2017-2018 2017-2018 2017-2018 Activity Distribution Infrastructure Replacement Program Worst Circuit Rehabilitation Cable Life Extension CIC Replacement Overhead Conductor Program Underground Oil Switch Replacement Capacitor Bank Replacement Automatic Recloser Replacement Substation Infrastructure Replacement Program PCB Transformer Replacement Substation Transformer Bank Replacement Substation Circuit Breaker Replacement Substation Switchrack Rebuilds Total 158 ~ ~ ~ YES YES ~ YES YES YES Per agreement with TURN, SCE reduced its request to these amounts in SCE-18, Vol. 8, at 19-21. - 73 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.8.1. Worst Circuit Rehabilitation Program SCE describes its Worst Circuit Rehabilitation (WCR) program as “an ongoing effort to manage system reliability by dealing with the challenge of infrastructure aging.”159 The program’s objective is to both improve system reliability by replacing distribution circuit infrastructure before it fails, thereby avoiding unplanned outages to SCE’s customers, and making circuits more resilient to future failures. The program focuses on circuits that disproportionately contribute to system SAIDI and SAIFI, as well as circuits where average customers are receiving relatively lower service reliability.160 SCE further explains that “because cable failure is the largest equipment contributor to poor system reliability, circuit rehabilitation typically involves replacement of each circuit’s most risk-significant mainline cable. This program also replaces infrastructure that has a lower reliability record and adds circuit enhancements such as automation, automatic reclosers (ARs), branch line fuses, and fault indicators wherever determined to be cost-effective.”161 TURN proposes reducing SCE’s WCR forecast by $39.057 million in 2017 and 2018, based on its argument that SCE’s reliability modeling forecast may be 159 Exhibit SCE-02, Vol. 8, at 13. 160 Ibid. System Average Interruption Duration Index (SAIDI) measures the total duration of interruption for the average customer during a given year. SCE’s 2015 SAIDI, with Major Event Days (MEDs) excluded, was 100.2 minutes of interruption. Outages recorded as cable, elbow/junction bar, or cable splice contributed 22.7 minutes, or approximately 23% of the system total. System Average Interruption Frequency Index (SAIFI) measures the total frequency of sustained interruption for the average customer during a given year. SCE’s 2015 SAIFI, with MEDs excluded, was 0.86 interruptions. Outages recorded as cable, elbow/junction bar, or cable splice contributed 0.18 interruptions, or approximately 21% of the system total. 161 Ibid. - 74 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 flawed.162 In rebuttal testimony, SCE defends its modeling by stating that it has compared the model results to available data as a means of validating the reasonableness of the underlying assumptions, with the model differing from actual total cable failures in the sample by less than 1%.163 Finally, SCE explains that TURN’s proposal would reduce SCE’s pace of replacement from 350 miles of mainline cable per year to 295 miles per year; SCE contends that its requested pace is necessary to maintain existing reliability levels.164 We approve SCE’s requested amount for its WCR program, a total of $249.313 million for 2017-2018.165 SCE’s rebuttal testimony and the testimony of its witness at hearing justify the requested amounts. TURN also makes three policy recommendations: (1) the Commission should direct SCE to begin recording cable failures by cable type; (2) the Commission should direct SCE to change the minimum age used to select mainline-cable replacements; and (3) SCE should be directed to begin piloting cable injections (instead of replacements) on mainline cable, and report on quantitative and qualitative findings from the pilot in the next GRC. SCE agrees with TURN that it is prudent to explore if cable injection would be beneficial for mainline cable. However, instead of going directly to a pilot as TURN suggests, SCE recommends a cost-benefit analysis be performed first to determine if a pilot is necessary. Overall, SCE suggests that the 162 SCE-18, Vol. 8A, at 1. 163 Exhibit SCE-18, Vol. 8, at 5. 164 SCE Opening Brief at 34, citing testimony of SCE witness Goizueta, at Reporter’s Transcript (RT) 1839. 165 SCE-18, Vol. 8, at 3, Table I-2 (Worst Circuit Rehabilitation Program Capital Expenditures). - 75 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Commission should adopt TURN’s recommendation with SCE’s proposed modification, i.e. to perform a cost-benefit analysis before undertaking a potential pilot.166 We adopt TURN’s recommendation, as modified by SCE. 4.8.2. Cable Life Extension Program SCE states that its Cable Life Extension program “does not directly replace infrastructure but provides information to target cable segments to be replaced by the Cable-in-Conduit Replacement Program.” The difference between SCE and ORA appears to be due to be minor rounding adjustments.167 We authorize SCE’s requested amount for this program, a total of $47.393 million for 2017-2018.168 4.8.3. Cable-In-Conduit Replacement Program SCE states that its cable-in-conduit (CIC) Replacement program “preemptively replaces segments of SCE’s cable-in-conduit population approaching the end of their service lives. The objective of the program is to reduce the number of in-service failures of CIC cable and thus drive down the number of unplanned outages to SCE customers.”169 The difference between SCE and ORA appears to be due to be minor rounding adjustments. We authorize 166 Id. at 6-7. 167 SCE-29, at 192. 168 SCE-18, Vol. 8, at 2, Table I-1 (Summary of Infrastructure Replacement Capital Expenditures). 169 SCE-02, Vol. 8, at 44. - 76 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s requested amount for this program, a total of $72.785 million for 2017-2018.170 4.8.4. Overhead Conductor Program SCE developed and implemented its OCP following the Commission's decision in the 2015 rate case. SCE states that the goals of the OCP are to reduce the frequency and impact of "wire down" events by proactively replacing overhead conductors as well as reactively performing emergency wire down work during events or performing planned conductor work coincident with these events. SCE identifies necessary work by ranking overhead circuits based on criteria such as increased likelihood of wire down events.171 SCE initiated the OCP in 2013 by collecting data and conducting research. In 2014, SCE's analysis determined that "the safety risk of electrocution caused by energized wire down events is considerable relative to other system risks." In 2015, SCE started scoping and executing work to address that safety risk. Although the Commission had not authorized any funding for OCP in D.15-11-021, once the program became operational SCE replaced 74 circuit-miles in 2015 and 202 circuit-miles in 2016, with recorded capital expenditures for the program equal to $58 million in 2015 and $97 million in 2016.172 For 2017 and 2018, SCE originally forecasted annual replacement of 300 circuit-miles. SCE then analyzed 2015 historical cost data to develop unit costs, resulting in its request for authorization of $136.087 million in capital 170 SCE-18, Vol. 8, at 2, Table I-1 (Summary of Infrastructure Replacement Capital Expenditures). 171 SCE-02, Vol. 8, at 47. 172 SCE-02, Vol. 8, at 49, Table III-12, "Historical and Forecast Spend for OCP." - 77 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 expenditures for 2017 and $139.514 million for 2018, a two-year total of $275.601 million.173 SCE revised its request in rebuttal testimony, stating "[b]ased on 2016 results, SCE believes that for the same amount of money SCE requested in its original GRC capital forecast, SCE can replace approximately 434 miles of small wire versus the originally-forecast 300 miles in each of 2017 and 2018."174 For the same period, ORA recommends $206.986 million, while TURN recommends $148.305 million, and CFC recommends $252.387 million. ORA recommends that SCE be authorized to replace 200 circuit-miles in 2017 and 250 circuit-miles in 2018. ORA agrees that the OCP is a worthwhile program, but questions whether SCE can complete all the work it forecasts for 2017 and 2018. First, ORA notes that SCE provided no support for its original forecast of 300 circuit-mile replacements per year. Second, ORA notes the importance of "remaining cognizant of the fact that the OCP is a new program, and that SCE is continuing to refine its criteria for selecting OCP projects.175 TURN recommends that SCE replace 120 circuit miles per year. TURN faults SCE's forecast for three reasons: (1) SCE has not sufficiently supported its proposed rate of 300 circuit-miles per-year; (2) SCE has not justified its reliance on reconductoring to the exclusion of alternative mitigations; and (3) SCE has failed to incorporate the possibility of infrared testing as part of a full suite of options. TURN recommends that the Commission authorize a reduced pace of OCP activity "until SCE is able to provide a well-conceived, well-tested and comprehensive solution to wire-down prevention." Finally, TURN analyzed the 173 Ibid. 174 SCE-18, Vol. 8, at 13. 175 ORA Opening Brief at 60. - 78 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 underlying causes of the "wire down" events targeted by the OCP and recommends that the Commission direct SCE to record 10% of these costs below-the-line “due to the adverse impacts associated with its past practice of installing oversized branch line fuses.” SCE would have an opportunity in the 2021 GRC to make a showing that demonstrates the steps it is taking to address this problem associated with its own past engineering practices, and the Commission could then re-visit whether below-the-line treatment continues to be appropriate. CFC also supports SCE’s OCP but, like ORA and TURN, observes that because the program is in its early stages of development a slower pace of work should be authorized. CFC highlights SCE's statement in its opening T&D testimony (Exhibit SCE-02, vol. 1, Operational Overview and Risk-Informed Decision-Making) that given the early stages of the OCP, SCE is still evaluating the benefits from existing mitigations (i.e. reconductoring and fusing) and from potential future mitigations (i.e. protection and automation device installations).176 SCE further explained that because empirical data is not yet available on the effectiveness of these mitigations, subject matter experts estimated the effectiveness “based on their judgment of how they would prevent melt and break wire downs.”177 SCE's testimony forms the basis for CFC's recommendation that the Commission authorize OCP expenditures for 2018 equal to $116.3 million, which CFC estimates would fund replacement 176 SCE-02, Vol. 1, at 41. 177 Ibid. - 79 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 250 circuit-miles. CFC proposes to increase the limit on replacement miles by 2.5% each year thereafter. In rebuttal, SCE finds fault with the methodologies relied upon by ORA, TURN and CFC to develop their recommendations. SCE also opposes TURN's recommendation for a 10% disallowance due to the adverse impacts associated with SCE's past practice of installing oversized branch line fuses. We find that SCE has not met its burden to prove that its requested levels of OCP funding are reasonable. We agree with ORA that SCE provided no explanation of how it determined that annual replacement of 300 circuit-miles would be optimal.178 Regarding program costs, SCE states that it completed all “forecast” work in 2016 while recording $97.330 million for OCP compared to its 2016 “forecast” of $142.203 million. SCE claims that “this lower cost was achieved due to SCE’s continued efforts to look for ways to improve processes and lower costs for our customers” but this Commission did not authorize either SCE’s forecast pace of work in 2016 or SCE’s forecasted costs. The fact that SCE bettered its own forecast is not persuasive. CFC’s analysis of the implications of SCE’s experience to-date is more accurate: CFC does not dispute SCE's need to replace overhead conductor. However, due to the non-trivial, last-minute changes in the numbers presented, and the variety of objectives the program serves, CFC recommends ramping-up OCP over the GRC years. The significant changes in some important program numbers, particularly late in the GRC application process, support CFC's contention that OCP 178 SCE asserts in its Reply Brief that its forecast was “well supported by the record evidence” (SCE Reply Brief at 18, citing Exhibit SCE-18, Vol. 8, at 7-19) but that Exhibit provides no support for SCE’s forecasted level of replacements in 2017 and 2018. - 80 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 remains in a pioneering phase. Recent revisions suggest a program whose fundamental details remain somewhat in flux.179 In this decision, we authorize the same level of annual expenditures for 2017-2018 that SCE recorded in 2016: $97.330 million (subject to the adjustment we order below). SCE states that this level of spending supported replacement of 202 circuit-miles in 2016, so we expect that SCE will continue replacements at that level, if not a higher level in the event that SCE continues to find ways to improve processes and lower costs. We also adopt TURN’s recommendation that we impose a 10% disallowance, to be paid for by shareholders, to recognize the role that the incorrect engineering had in creating circumstances where some wires may have more extensive damage than they would have otherwise. First, for OCP recorded costs in 2015 and 2016 totaling $155.456 million, the disallowance equals $15.54 million. Second, for the annual OCP capital expenditures we have approved for 2017 and the remainder of this GRC period (2018-2020), SCE shall record 10% of its recorded costs in a below-the-line account.180 On a forecast basis, this amount would equal $9.733 million annually. 4.8.5. Underground Oil Switch Replacement Program SCE’s Underground Oil Switch Replacement program replaces oil-filled switches in underground structures which SCE believes are approaching the end of their service lives and pose a threat to both system reliability and public and 179 CFC Opening Brief at 15. 180 TURN Opening Brief at 31, citing Exhibit TURN-04-A, at 35. - 81 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 employee safety.181 We authorize SCE’s unopposed requested amount for this program, a total of $23.851 million for 2017-2018.182 4.8.6. Capacitor Bank Replacement Program Capacitor banks are used in SCE’s distribution system to regulate the voltage to usable levels by compensating for load inductance. SCE’s Capacitor Bank Replacement program replaces failed and obsolete capacitor banks and their appurtenant capacitor switches.183 In its opening brief SCE explains that it originally forecast $34.744 million in capital expenditures for 2017-2018, based on a forecast annual replacement volume higher than the historical five-year average, albeit “significantly” lower than the steady state replacement rate; SCE also agreed to accept TURN’s proposal to use 2014 unit costs, which reduces SCE's forecast to $27.692 million.184 TURN goes beyond the changes accepted by SCE and recommends a forecast of 231 replacements per year (based on the 2011-2016 average replacement rate), which would reduce 2017-2018 capital expenditures to $18.274 million. 181 SCE-02, Vol. 8, at 52. 182 SCE-18, Vol. 8, at 2, Table I-1 (Summary of Infrastructure Replacement Capital Expenditures). 183 SCE-02, Vol. 8, at 57. 184 SCE-18, Vol. 8, at 20-21. - 82 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We decline to impose the additional reductions proposed by TURN. We adopt the reduced forecast proposed by SCE, totaling $27.692 million for the 2017-2018 period.185 4.8.7. Automatic Recloser Program SCE’s Automatic Recloser program replaces ARs which have been identified as being obsolete and/or unreliable. We approve SCE’s unopposed requested amount for this program, a total of $4.678 million for 2017-2018.186 4.8.8. PCB Transformer Replacement Program SCE’s PCB Transformer Replacement program replaces distribution line transformers suspected of being contaminated with polychlorinated biphenyl (PCB) oil. We approve SCE’s unopposed requested amount for this program, a total of $2.862 million for 2017-2018.187 4.8.9. Substation Infrastructure Replacement Program SCE states that its Substation Infrastructure Replacement program preemptively replaces major pieces of aging or obsolete substation equipment to minimize the negative effect of aging on system reliability, safety, and operability/maintainability. SCE requests approval of 2017-2018 capital expenditures for the three functions within this program as follows:188 185 Id. at 21, Table I-5 (Revised Capacitor Bank Replacement Program Capital Forecast, 100% CPUC Jurisdictional – Nominal $000). 186 Id. at 2, Table I-1 (Summary of Infrastructure Replacement Capital Expenditures, Total Company – Nominal $000). 187 Ibid. 188 Ibid. - 83 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 1. Transformer Replacement: $134.352 million 2. Circuit Breaker Replacement: $88.818 million 3. Substation Switchrack Rebuild: $37.187 million We approve SCE’s unopposed requested amounts for this program. - 84 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.8.10. Conclusion: Adopted Infrastructure Replacement Program Capital Expenditures Adopted Infrastructure Replacement Capital Expenditures Total Company – Nominal $000 Activity 2017 Distribution Infrastructure Replacement Program Worst Circuit Rehabilitation 123,106 Cable Life Extension 23,402 CIC Replacement 31,142 Overhead Conductor Program 136,087 Underground Oil Switch 11,150 Replacement Capacitor Bank 13,674 Replacement189 Automatic Reclosure 2,310 Replacement Substation Infrastructure Replacement Program PCB Transformer Replacement 1,413 Substation Transformer Bank 66,349 Replacement Substation Circuit Breaker 43,875 Replacement Substation Switchrack 18,362 Rebuilds Total Adopted 470,870 Expenditures 4.9. 2018 Total 20172018 2017 2018 Total 20172018 126,207 23,991 41,643 139,514 249,313 47,393 72,785 275,601 123,106 23,402 31,142 87,597 126,207 23,991 41,643 87,597 249,313 47,393 72,785 175,194 12,701 23,851 11,150 12,701 23,851 14,018 27,692 13,674 14,018 27,692 2,368 4,678 2,310 2,368 4,678 1,449 2,862 1,413 1,449 2,862 68,003 134,352 66,349 68,003 134,352 44,943 88,818 43,875 44,943 88,818 18,825 37,187 18,362 18,825 37,187 493,662 964,532 422,380 441,745 864,125 T&D – Poles SCE states that its pole programs address major safety and reliability risks and the compliance requirements of General Order (GO) 165 (GO 165) and 189 Per agreement with TURN, reduced to these amounts in SCE-18, Vol. 8, at 19-21. - 85 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 General Order 95 (GO 95).190 SCE states that these forecasts are primarily driven by regulatory requirements and are based on the amount of work that SCE estimates will be required to comply with these rules. SCE's pole-related forecasts include funding for its Deteriorated Pole Program, its Pole Loading Program (PLP), its Joint Pole Organization, and other items such as joint pole credits and wood pole disposal. SCE requests authorization of 2018 Test Year revenue requirements of $37.041 million in O&M expenses and $322.891 million in capital expenditures.191 4.9.1. O&M Expenses SCE prepares its O&M forecast separately for transmission poles and distribution poles. Its common methodology involves (1) estimating the per-unit cost for each activity and (2) estimating the expected activity for the period. SCE then multiplies the two values by each other in order to calculate the forecast O&M expenses. ORA disputes both terms in this equation for Distribution and Transmission Pole Loading Assessments as well as Distribution Pole Loading Program Repairs; ORA also disputes SCE’s forecast expenses for its Joint Pole Organization. TURN accepts SCE’s estimated levels of activity, but disputes SCE’s per-unit costs for Distribution and Transmission Pole Loading Assessments as well as Distribution and Transmission Pole Loading Program 190 Exhibit SCE-18, Vol. 9, at 1. 191 Id., at 3, Table I-1 (Summary of Pole O&M Expenses); at 4, Table I-2 (Summary of Pole Capital Expenditures); SCE-29A at 41, 160, 161, 163; and SCE-59 at 40, Table VIII-15 (Joint Pole Organization, Portion of GRC Account 583.125, Recorded and Adjusted 2011-2015/Forecast 2016-2018). - 86 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Repairs. The table below summarizes SCE’s poles-related O&M request and the recommendations of ORA and TURN.192 Summary of Pole O&M Expense Recommendations Constant 2015 $000 GRC Account Description SCE Transmission Deteriorated Pole Inspections 566.125 Transmission Pole Loading Program Assessments Total Account 566.125 Transmission Pole Loading Program Related Expense 571.125 Transmission Pole Loading Program Repairs Total Account 571.125 Distribution Deteriorated Pole Inspections Joint Pole Organization 583.125 Joint Pole O&M Credits Distribution Pole Loading Program Assessments Total Account 583.125 Distribution Pole Loading Program Related Expense 593.125 Distribution Pole Loading Program Repairs Total Account 593.125 Total 685 2,441 3,126 199 386 585 4,983 3,649 (3,140) 21,966 27,458 2,403 3,469 5,872 37,041 2018 Forecast ORA ORA TURN Variance 685 685 1,866 (575) 2,208 2,551 (575) 2,893 199 199 386 351 585 550 4,983 - 4,983 7,442 3,793 3,649 (3,140) - (3,140) 16,792 (5,174) 19,872 26,077 (1,381) 25,364 2,403 - 2,403 2,182 (1,287) 3,154 4,585 (1,287) 5,557 33,798 (3,243) 34,364 TURN Variance (233) (233) (35) (35) (2,094) (2,094) (315) (315) (2,677) As explained below, this decision adopts SCE’s uncontested requests for (1) Transmission and Distribution Pole Loading Program Related Expenses and (2) Transmission and Distribution Deteriorated Pole Inspections. SCE’s forecast for Joint Pole Organization expenses is also adopted. This decision adopts TURN’s recommendations for (1) Distribution and Transmission Pole Loading Assessments and (2) Distribution and Transmission Pole Loading Program Repairs. Regarding the Joint Pole Organization, ORA prepared its own forecast by starting with SCE’s 2015 recorded costs, and adding one-third of the annual 192 Ibid. - 87 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 increase requested by SCE. However, ORA did not take the next step and complete its analysis by determining whether its recommended funding level would be sufficient to support the activities that serve as the basis for SCE’s own forecast. We adopt SCE’s more directly estimated forecast, equal to $3.649 million for the 2018 Test Year. SCE calculated this amount by starting with its 2015 recorded costs, and adding the specific costs of the additional personnel it determined would be needed to support its forecasted activity levels.193 Regarding TURN’s recommendations, as noted above TURN accepts SCE’s forecast rate of work. However, TURN then provides a detailed analysis of SCE’s estimated unit costs and concludes that SCE’s estimates should be adjusted downward. First, regarding SCE’s unit costs for assessments, TURN demonstrates that SCE’s estimates have been a “moving target” in this proceeding, having been modified by SCE three times since it filed its application. TURN reviews the recorded 2016 costs provided by SCE in its rebuttal testimony and recommends a per-assessment cost equal to $100 per pole. TURN then calculates a 2018 O&M forecast of $22.08 million, which is $2.327 million lower than SCE’s request.194 We adopt TURN’s estimate as shown below for the relevant GRC Accounts: 193 SCE-59 at 40, Table VIII-15 (Joint Pole Organization, Portion of GRC Account 583.125, Recorded and Adjusted 2011-2015/Forecast 2016-2018). 194 TURN Opening Brief at 42, relying on values provided in SCE-18, Vol. 9, Appendix A, Table XII-42 (Appendix A is SCE’s testimony in A.17-04-004, its 2016 Energy Resource Recovery Account (ERRA) compliance review proceeding. Table XII-42 presents SCE’s 2016 recorded costs for Pole Loading and Deteriorated Pole O&M Expense. - 88 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Adopted Transmission and Distribution Test Year 2018 Pole Loading Program Assessments O&M Forecast Constant 2015 $000 GRC Account 566.125 (partial) 583.125 (partial) 2018 Approved 2,208 19,872 22,080 Description Transmission Pole Loading Program Assessments Distribution Pole Loading Program Assessments Total Adopted Second, regarding SCE’s unit costs for repairs, TURN recommends use of 2016 data to estimate costs, rather than the 2015 data used by SCE, because SCE conducted 1,034 repairs in 2016 versus only 424 repairs in 2015. After what appears to have been a fairly collegial exchange of views and corrected calculations, TURN and SCE agree that averaging the 2015 and 2016 data produce a per-unit repair cost of $1,562 per repair, while using only the 2016 data results in a per-unit repair cost of $1,420 per repair. TURN states that it “continues to believe that the $1,420 per repair unit cost derived from 2016 is the more reasonable figure under the circumstances” and we agree. Using that estimate, we adopt TURN’s recommended forecast as shown below: Test Year 2018 Adopted Transmission and Distribution Pole Loading Program Repairs O&M Forecast Constant 2015 $000 GRC Account 571.125 (partial) 593.125 (partial) Description Transmission Pole Loading Program Repairs Distribution Pole Loading Program Repairs Total Adopted - 89 - 2018 Approved 351 3,154 3,505 PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.9.2. Capital Expenditures ORA did not contest SCE's pole-related capital forecasts. TURN recommends reductions to four components of SCE’s pole-related capital forecasts, as shown in the table below: TURN Recommended Pole Capital Expenditures195 Total Company – Nominal $000 SCE TURN Reduction 2017-2018 2017-2018 2017-2018 Activity Distribution Deteriorated Pole Replacement and Restorations Pole Loading Distribution Pole Replacements Pole Loading Transmission Pole Replacements Transmission Deteriorated Pole Replacement and Restorations Totals 370,757 330,972 (39,785) 232,100 40,744 207,128 37,595 (24,972) (3,149) 140,812 130,003 (10,809) 784,413 705,698 (78,715) In testimony, TURN recommends downward adjustment of the unit costs for the categories shown above by removing SCE’s reported increase in contractor costs from 2012 to 2015. TURN shows that these costs increased by amounts “above and beyond” general inflation.196 In rebuttal, SCE asserts that because SCE uses a competitive process to determine contractor costs, the costs are reasonable and the Commission should reject TURN’s argument.197 We find that SCE has not affirmatively demonstrated that its contractor costs are reasonable. SCE’s circular argument that, because SCE uses a 195 SCE-18, Vol. 9, at 4, Table I-2 (Summary of Pole Capital Expenditures), with 2016 forecast removed. 196 TURN-12, at 30-32. 197 SCE-18, Vol. 9, at 21. - 90 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 competitive process, the results of that process must be reasonable, is insufficient. TURN asks reasonable questions regarding the reasons SCE’s contractor costs increased much faster than the rate of inflation, and SCE has not responded with a fact-based explanation. For this reason, we authorize SCE to spend the amounts recommended by TURN and summarized in the table above. 4.9.3. Pole Loading and Deteriorated Pole Programs Balancing Account TURN requests that the Pole Loading and Deteriorated Pole Programs Balancing Account (PLDPBA) only be continued on the condition that it becomes a one-way balancing account. SCE proposes that the current cap on the PLDPBA be removed. We find that no changes in the structure of the PLDPBA are warranted at this time. 4.10. T&D – Grid Modernization SCE’s “grid modernization” proposal is the central contested issue in this proceeding. SCE’s opening testimony reviews recent technological and policy trends that SCE asserts will “require a paradigm shift whereby generation can be optimized no matter where it is on a distribution circuit and power can flow in either direction without hindering reliability or the safety of customers, utility workers, or the public.”198 In its reply brief, SCE observes that “the issues surrounding Grid Modernization have coalesced around whether SCE needs to improve reliability through grid modernization, and whether the level of automation and supporting technology SCE proposes is a reasonable path to achieve this.”199 198 SCE-02, Vol. 10, at 3. 199 SCE Reply Brief at 21. - 91 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s framing of the issues is on point. We summarize the range of parties’ positions and recommendations below.  CUE takes no position on grid modernization for the purposes of facilitating DER, but supports SCE’s proposals regarding system reliability improvements.200  ORA contends that SCE’s request for Grid Modernization investments is premature, mainly because relevant Commission guidance from the Distribution Resources Plan proceeding is pending. Instead, ORA recommends that for this 3-year rate case cycle the Commission continue funding certain historical programs. [ORA-9A at 2-4]. That said, ORA does support funding of circuit specific Distributed Energy Resource-related upgrades if they are properly justified [ORA-9A at 57].201  TURN contends that reliability and DER-related benefits derive from creating additional visibility and flexibility for grid operators, not from full grid reconfiguration automation.202 TURN concludes that “there is little demonstrated ‘need’ for SCE’s grid modernization proposal, and TURN’s more modest proposed investment provides an amount of reliability improvement more in line with customers’ value of service, and would allow grid operators to accurately estimate circuit loading conditions for reconfigurations.”203 TURN asserts that its recommended alternative level of investments would achieve 55% of the reliability benefits that SCE claims its own proposal would deliver, but at 25% of the costs.204  SEIA and Vote Solar contend that SCE has failed to meet its burden of demonstrating that the costs associated with its 200 CUE Reply Brief at 34. 201 ORA Reply Brief at 1, Summary of Recommendations. 202 TURN Opening Brief at 49. 203 TURN Reply Brief at 5. 204 TURN Opening Brief at 51. - 92 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 proposed grid modernization program are just and reasonable. Accordingly, the Commission should deny SCE’s request and instead authorize distribution automation expenditures consistent with historical spending.  CFC references SCE’s grid modernization proposal as it contends that “when viewed in the context of affordability, however, the application's proposed increases are less reasonable”205 and suggests that “while CFC acknowledges SCE's need to replace infrastructure, those replacements must be done at a pace ratepayers can actually afford.”206 SCE prefaces its detailed grid modernization proposals by explaining that its distribution system has historically been structured to accommodate power flows running in one direction – from central station generation to the end-use customer. The design of SCE’s distribution system – the capacity along the circuit, the automation and switches installed to detect and manage faults, and the placement of circuit ties – has hinged on this one-way flow of power. SCE then suggests that the “modern grid” envisioned by the Commission in its Distributed Resources Plan (DRP) proceeding, as well as other state and federal policies, requires a “paradigm shift” whereby generation can be optimized no matter where it is on a distribution circuit and power can flow in either direction without hindering reliability or the safety of customers, utility workers, or the public. Finally, separate and apart from the paradigm shift described above, SCE asserts that its distribution grid is aging and is facing new strains in the form of greater cybersecurity risks, nearing capacity limits on certain circuits and 205 CFC Opening Brief at 5. 206 Id. at 6. - 93 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 telecommunications wires, and technology obsolescence. SCE states that its field area network is at 90% capacity: with a growing number of grid devices being deployed each year, and future plans to interact with smart inverters, SCE expects to exceed capacity in 2018. SCE also suggests that its customers are coming to expect more reliability: as their reliance on new technology grows, they have less tolerance of outages, security breaches, and communications issues. Based on the above, SCE concludes that grid modernization is needed to keep pace with this new technology and customer expectations. Even without DER growth, grid modernization is needed to maintain SCE’s aging distribution grid and improve its reliability. SCE states that it has assessed (1) traditional drivers such as accommodating increased capacity needs while meeting system reliability and (2) emerging drivers such as technology changes and emerging policy goals. As a result, SCE has developed and submitted its grid modernization proposal with the intention of achieving the three benefits for SCE’s customers listed below:  Enhance safety and reliability: improve system reliability and outage restoration while supporting increasing levels of DERs and two-way flows of energy;  Enable DER integration and adoption: support customer choice of new technologies and services in an expedient and cost-efficient manner; and  Realize DER benefits: enable opportunities to obtain optimal value from DERs through wholesale and distribution grid services.207 207 SCE-02, Vol. 10, at 5. - 94 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE originally requested $637 million in capital in Test Year 2018 for new or expanded programs to improve the performance of its grid, and address concerns regarding integration of DERs. SCE subsequently revised its request to approximately $539 million. SCE’s current request is summarized in the table below. SCE Grid Modernization Summary of Requested Capital Expenditures (100% CPUC Jurisdictional – Nominal $000) Activity Distribution Automation Communications Tools for Data Analysis and Decision-Making Total Grid Modernization 2018 2019 2020 65,393 72,283 221,348 173,751 228,293 248,366 234,600 268,939 Total 2017-2020 749,634 763,339 20,595 45,564 48,665 33,854 148,678 158,271 440,663 525,324 537,393 1,661,651 2017 - 95 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Grid Modernization Detail of Requested Capital Expenditures (100% CPUC Jurisdictional – Nominal $000) Activity 2017 Historical Circuit Automation WCR Enhanced Distribution Automation DER-Focused Enhanced Distribution Automation Sub-Total: Distribution Automation Substation Automation (SA-3) Common Substation Platform (CSP) New Field Area Network (FAN) Existing FAN Support, Distribution System Efficiency Enhancement Program (DSEEP) Wide Area Network (WAN) Sub-Total: Communications System Modeling Tool (SMT) Distribution Resource Plan External Portal (DRPEP) Grid Management System (GMS) Sub-Total: Tools for Data Analysis and Decision-Making Total Request 4.10.1. Total 2017-2020 4,607 2018 2019 2020 142,696 147,173 151,852 441,721 60,786 78,652 81,120 82,748 303,306 65,393 221,348 228,293 234,600 749,634 46,418 106,761 103,116 103,980 360,275 3,933 7,513 18,929 19,445 49,820 11,697 14,650 82,698 101,652 210,697 5,327 6,180 5,328 4,573 21,408 4,908 72,283 38,647 173,751 38,295 248,366 39,289 268,939 121,139 763,339 6,457 2,467 8,924 1,836 3,641 5,477 12,302 39,456 48,665 33,854 134,277 20,595 45,564 48,665 33,854 148,678 158,271 440,663 525,324 537,393 1,661,651 4,607 Grid Modernization Capital Expenditures SCE’s capital request for Grid Modernization can be separated into three sub-groups: (1) distribution automation programs, (2) communications and control equipment, and (3) planning tools. We review each sub-group below. 4.10.1.1. Distribution Automation Programs The first sub-group of SCE’s grid modernization program is its “Enhanced Distribution Automation” program (Enhanced DA). SCE states that this - 96 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 program will continue, but expand the scale and scope of, its historical circuit automation program as follows: Current (“Historical”) DA Program Purpose:  respond to reliability objectives  basic circuit automation efforts Technology:208  about three-quarters of SCE’s circuits include some level of automation: o one or two remote-controlled mid-point switches o one remote-controlled circuit tie switch o rudimentary telemetry Outcomes: SCE states that “the deployed equipment enables only basic automation and limited visibility to circuit-level data, not well suited for circuits integrating DERs. As more DERs connect to distribution circuits, information about conditions along the circuit, (e.g., load, power flow, voltage) needed by grid operators to manage reliability, is becoming distorted.”209 208 SCE provides the following definitions in SCE-02, Vol. 10 (footnotes 57-58): Switches are electrical components that enable the flow or interruption of electricity along a conductor as needed for circuit operation. Circuit ties provide the pathway through which power can be re-routed from one circuit to another. Telemetry is an automated communications process by which measurements and other data are collected at remote or inaccessible points and transmitted to receiving equipment for operations monitoring in near-real time. 209 SCE-02, Vol. 10, at 34-35. - 97 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Enhanced Distribution Automation Program Purpose: To support reliability and enables DERs by: 1. increasing situational awareness with more near real-time telemetry data points throughout the circuits that will help identify issues quickly and accurately, 2. facilitating remote isolation and restoration and therefore decreased outage duration and area of impact, and 3. increasing operational flexibility with appropriately-sized line sections for circuit switching, which will minimize de-energized sections during planned and unplanned outages. Technology:  three mid-point switches  three circuit-ties210  improved telemetry and communication devices Outcomes: SCE states that “the increase in switches and circuit-ties will provide operators with significantly more ‘switching’ options, therefore providing more operational flexibility to isolate faults, minimize outages to customers, and restore customers faster. The Distribution Automation program will also enable grid operators to obtain critical visibility and optimize DERs.”211 If approved by the Commission, SCE’s Enhanced DA program would replace its Historical DA program beginning in 2018. The proposed Enhanced 210 TURN Opening Brief at 47: In rebuttal testimony SCE reduced its capital cost forecast for the distribution automation program by $50 million for 2018, and by $172 million for 2018-2020, by eliminating the Circuit Tie Upgrades component, citing SCE-18 Vol. 2, at 5:3-12 and at 6, Table I-2. 211 SCE-02, Vol. 10, at 36. - 98 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 DA program is divided into two sub-programs: a WCR DA program and a DER-focused DA program. First, the proposed WCR DA program would install new technology on 200 circuits per year over this GRC period. Each circuit would be automated in two stages, for two different purposes: stage one automation would be intended to maintain reliability as part of the aging infrastructure replacement program, for which SCE seeks separate funding in this GRC; stage two automation would be intended to augment the circuits to make them capable of fully integrating DERs and improving system reliability.212 Second, the proposed DER-focused DA program would identify an average of 88 circuits per year “using a prioritization methodology that considers the opportunity to contribute to grid services, deferral pilot locations, and locations of high DER penetration where there may be reverse power flow on multiple circuits at the same substation.”213 More specifically, SCE expects to automate 263 circuits in the 2018-2020 period due to three different DER-related causes: 1) 63 circuits that are forecast to have relatively high levels of DER growth due to organic adoption of rooftop solar and/or planned wholesale projects; 2) 126 circuits that are classified as optimal DER locations; and 3) 74 circuits that will be impacted by DER procurement through deferral pilots.214 Based on the above, SCE requests approval of its forecast 2017-2018 distribution automation capital expenditures shown below: 212 SCE-02, Vol. 10, at 42. 213 Ibid. 214 SCE-18, Vol. 10, at 37; TURN-06, at 72. - 99 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Grid Modernization Distribution Automation Capital Expenditures Request215 (100% CPUC Jurisdictional – Nominal $000) Activity 2017 Historical Circuit Automation (CA) WCR Enhanced Distribution Automation DER-Focused Enhanced Distribution Automation Total Distribution Automation 2018 4,607 60,786 65,393 142,696 78,652 221,348 Total 2017-2018 4,607 142,696 139,438 286,741 As noted above regarding SCE’s overall grid modernization proposals, CUE takes no position on SCE’s DER-related requests but supports SCE’s requests to fund system reliability improvements. ORA recommends only continued funding for certain historical programs and funding for properly justified circuit-specific DER-related upgrades. SEIA and Vote Solar also recommend only funding levels consistent with historical spending. CFC recommends replacements only at a pace ratepayers can afford. TURN provides the most detailed recommendations among the intervenors, and offers a “primary” and a “secondary” recommendation. TURN’s primary recommendation is that the Commission authorize an annual budget of $22 million for distribution automation, based on a tripling of SCE’s recorded annual budgets for traditional distribution automation.216 TURN’s secondary recommendation is that, if the Commission concludes that additional reliability or grid flexibility benefits are needed, the Commission should authorize a total Test Year 2018 budget for grid modernization of 215 Id., at 38, Table II-4 (Distribution Automation Capital Expenditures). 216 TURN Opening Brief at xxiii: “This amount of spending should achieve close to 50% of the reliability benefits of SCE’s program at about one-twentieth of SCE’s forecast cost of $440 million per year.” - 100 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $116.474 million, a reduction of $324.194 million from SCE’s proposal. TURN recommends funding for a reduced number of remote fault indicators (RFIs) and remote controlled switches (RCS), funding for the Common Substation Platform (CSP), funding for 50% of the cost of the Grid Management System (GMS), and funding for software decision-making tools. TURN recommends zero funding for the new field area network (FAN) and the new wide area network (WAN), since those are only necessary to provide complete switching automation.217 We find that the approach proposed by TURN in its “secondary” recommendation will result in the proper balance between SCE’s need to maintain and upgrade aging infrastructure while also accommodating realistic levels of DER growth in the 2018-2020 GRC period. For the Distribution Automation component, TURN recommends $64.675 million for WCR Enhanced DA and $11.178 million for DER Focused Enhanced Distribution Automation, totaling $75.853 million of capital expenditures in 2018.218 First, regarding the WCR portion of distribution automation, TURN recommends as follows: ...if the Commission determines that additional spending for reliability improvements and grid flexibility is warranted, TURN recommends the Commission authorize $64.675 million per year for the WCR portion of distribution automation. 217 TURN Opening Brief at xxiii-xxiv: “The Commission should find that TURN’s secondary recommendation achieves over 55% of the reliability benefits of SCE’s program at about 25% of the costs, and provides grid operators with the visibility and flexibility to address any DER-related operational problems.” 218 TURN Opening Brief at 52, Table 6. - 101 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 This amount includes funding for: (1) five Remote Fault Indicators (RFIs) on the 600 WCR circuits; (2) one tie switch and (3) up to two RCS switches on the 110 WCR circuits that have no existing ties.219 Second, regarding the DER portion of distribution automation, we adopt TURN’s recommendation to fund the installation RCSs and RFIs on approximately 54 of the 264 circuits targeted by SCE, at a cost of $11.178 million.220 We find reasonable TURN’s analysis and conclusion that beyond this number of installations there is insufficient value to installing more advanced Remote Intelligent Switches to achieve full switching automation. SCE Grid Modernization Distribution Automation Capital Expenditures Requested and Adopted Amounts221 (100% CPUC Jurisdictional – Nominal $000) Requested Activity Historical Circuit Automation (CA) WCR Enhanced Distribution Automation DER-Focused Enhanced Distribution Automation Total Distribution Automation 2017 Approved Total 2017-2018 2018 4,607 - 4,607 - 142,696 142,696 60,786 65,393 2017 Total 2017-2018 2018 4,607 - 4,607 - 64,675 64,675 78,652 139,438 60,786 11,178 71,964 221,348 286,741 65,393 75,853 141,246 219 TURN Opening Brief at 51, citing TURN-04R, at 63:4-8; TURN-04A2, at 42, Table 10. As explained by Mr. Jones on the stand, the $23.752 million for switches and ties was an error but TURN does not change its recommended level 2018 funding. 220 TURN Opening Brief at 50. As discussed later in this decision, TURN also recommends increased funding for the Distribution System Efficiency Enhancement Program (DSEEP) to increase the capacity of the existing NetComm mesh network. 221 SCE-18 Vol. 10, at 38, Table II-4 (Distribution Automation Capital Expenditures). - 102 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.10.1.2. Communications The second sub-group of SCE’s grid modernization program involves installation of communications and control equipment. SCE requests approval of its forecast 2017-2018 communications capital expenditures shown below. SCE Grid Modernization Communications Capital Expenditures Request222 (100% CPUC Jurisdictional – Nominal $000) Activity Total 2017-2018 46,418 106,761 153,179 3,933 7,513 11,446 11,697 14,650 26,347 2017 Substation Automation (SA-3) Common Substation Platform (CSP) New Field Area Network (FAN) Existing FAN Support, Distribution System Efficiency Enhancement Program (DSEEP) Wide Area Network (WAN) Total Communications 2018 5,327 6,180 11,507 4,908 38,647 72,283 173,751 43,555 246,034 TURN’s corresponding recommendations are summarized below.223 Activity Substation Automation (SA-3) Common Substation Platform (CSP) New Field Area Network (FAN) Existing FAN Support, Distribution System Efficiency Enhancement Program (DSEEP) Wide Area Network (WAN) Total Communications 222 46,418 0 Total 2017-2018 46,418 3,933 7,513 11,446 0 0 0 7,000 7,000 14,000 0 57,531 0 14,513 0 71,864 2017 2018 SCE-18, Vol. 10 A4, at 4, Table I-1 (Summary of Grid Modernization Capital Expenditures). 223 TURN Opening Brief at 52, Table 6 (TURN’s Secondary Recommendation for Grid Modernization Capital Spending), footnotes omitted. - 103 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We authorize the following capital expenditures for the communications and control subgroup:  Substation Automation (SA-3): we do not authorize SCE’s proposal for this program and therefore deny SCE’s request for funding over the 2018-2020 period. We find that SCE has not demonstrated the need to proactively update substations at this time. However, SCE’s request for 2017 ($46.418 million) was uncontested, and we approve that amount.  Common Substation Platform (CSP): we approve SCE’s uncontested proposal for this program and therefore approve SCE’s request for $11.446 million over the 2017-2018 period. We find that the CSP will deliver cybersecurity and interoperability benefits.  Field Area Network (FAN): we approve SCE’s proposal for this program and therefore approve SCE’s request for $ 26.347 million over the 2017-2018 period. We find that the FAN is needed now, based on expected cybersecurity benefits and in order to ensure that distribution devices have sufficient communications.  Distribution System Efficiency Enhancement Program (DSEEP) and support for the existing FAN: because we approve SCE’s FAN proposal, we also approve SCE’s related request for DSEEP and support for the existing FAN, a total of $11.507 million over the 2017-2018 period.  Wide Area Network (WAN): we do not authorize SCE’s proposal for this program because SCE’s showing did not demonstrate why WAN expenditures were necessary during this GRC period. The table below summarizes our determinations regarding the communications-related components of SCE’s grid modernization proposal. - 104 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Grid Modernization Communications Capital Expenditures Requested and Authorized (100% CPUC Jurisdictional – Nominal $000) Requested Activity 2017 Substation Automation (SA-3) Common Substation Platform (CSP) New Field Area Network (FAN) Existing FAN Support, Distribution System Efficiency Enhancement Program (DSEEP) Wide Area Network (WAN) Total Communications 4.10.1.3. 2018 Authorized Total 2017-2018 2017 Total 2017-2018 2018 46,418 106,761 153,180 46,418 - 46,418 3,933 7,513 11,446 3,933 7,513 11,446 11,697 14,650 26,347 11,697 14,650 26,347 5,327 6,180 11,507 5,327 6,180 11,507 4,908 38,647 43,555 - - - 72,283 173,751 246,034 67,375 28,343 95,718 Tools for Data Analysis and Decision-Making The third sub-group of SCE’s grid modernization program involves capital spending for a number of tools to support and enable improved data analysis and decision-making. SCE requests approval of its forecast 2017-2018 s capital expenditures for Tools for Data Analysis and Decision Making shown in the table below. SCE Grid Modernization Tools for Data Analysis and Decision-Making Capital Expenditures Request and Authorized (100% CPUC Jurisdictional – Nominal $000) Activity 2017 2018 System Modeling Tool (SMT) 6,457 2,467 Distribution Resource Plan External Portal (DRPEP) 1,836 3,641 Grid Management System (GMS) 12,302 39,456 Total Tools 20,595 45,564 - 105 - Total 2017-2018 8,924 5,477 51,758 66,159 PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 As we explain below, we authorize each of SCE’s requests. 4.10.1.3.1. System Modeling Tool (SMT) The SMT is a set of software applications that will enable SCE engineers to perform more precise and near-real-time power-flow and capacity analyses of the electric system. The SMT replaces SCE’s current software tools for capacity analyses throughout its grid, which are inadequate because they require significant manual effort and rely upon conservative assumptions that limit their precision. The added functionality in SMT will facilitate capacity planning, interconnection studies, and the DRP’s Integration Capacity Analysis (ICA). SCE requests $2.467 million for Test Year 2018 capital expenditures and we approve that amount.224 SCE's request is compliant with the DRP proceeding. 4.10.1.3.2. DRP External Portal The DRPEP, will create an interactive website for customers and potential DER applicants to access current circuit interconnection capacities anywhere on SCE distribution grid. DRPEP will be the public interface for SCE’s ICA results, which will be generated through SMT. SCE requests $3.641 million for Test Year 2018 capital expenditures and we approve that amount.225 SCE's request is compliant with the DRP proceeding. 4.10.1.3.3. Grid Management System SCE requests $39.456 million for Test Year 2018 capital expenditures for the GMS and we approve that amount.226 The GMS will provide cybersecurity benefits, enable DERs, and integrate SCE’s distribution software. 224 SCE-18, Vol. 10, at 4, Table I-1 (Summary of Grid Modernization Capital Expenditures). 225 Ibid. - 106 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4.10.2. Grid Modernization O&M Expenses SCE’s request for 2018 O&M expenses related to grid modernization include costs for Organizational Change Management (OCM), grid modernization employee training, inspections of Programmable Capacitor Controls (PCC) for Distribution Volt/VAR Control, and establishment of a Program Management Office (PMO). SCE estimated specific needs based on number of employees requiring training and consultant costs. SCE requests approval of $4.135 million in 2018 O&M expenses.227 4.10.2.1. Intervenors’ Positions ORA recommends no funding for O&M costs associated with the Grid Modernization activities. Instead, all Grid Modernization costs should be reviewed and authorized by the Commission once the pending parallel proceedings related to the Grid Modernization proposal have reached a decision. SEIA-Vote Solar supports ORA’s recommendation228 and TURN does not provide testimony on O&M. 4.10.2.2. SCE’s Rebuttal to Intervenors’ Positions SCE notes that ORA did not oppose the reasonableness of the scope or the cost forecast methodology of SCE’s Grid Modernization O&M expenditures. Therefore, if capital funding for Grid Modernization is approved, the related O&M is required to implement SCE’s Grid Modernization plan. 226 Ibid. 227 Id. at 6, Table I-3 (Grid Modernization O&M Expenses, Constant 2015 $000). 228 SEIA-Vote Solar does not specifically mention O&M, but generally agrees with ORA’s Grid Modernization funding proposals. - 107 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We agree with SCE’s logic and find SCE’s forecast 2018 O&M expenses to be reasonable. We adopt SCE’s forecast. 4.11. T&D – Grid Technology In its testimony on grid technology, SCE describes its Advanced Technology Division, the work it performs, and the associated cost of the work. SCE states that its Advanced Technology Division “tests, evaluates, and pilots new and emerging technologies to meet the evolving needs of customers and to comply with many new federal and state energy policies.”229 SCE requests approval of $16.505 million in O&M expenses230 and $52.985 million in capital expenditures for Test Year 2018.231 We review the contested items in SCE’s request below. 4.11.1. Distribution Volt VAR Control SCE explains that the Distribution Volt VAR Control (DVVC) program centralizes control of the field and substation capacitors, so that SCE can coordinate and optimize voltage and VARs across all circuits that are fed by a substation. SCE explains that the program will reduce energy consumption and foster reliability by limiting voltage fluctuations, and that this should provide a 1% actual savings in energy costs for customers for every 1% reduction in voltage.232 229 SCE-02, Vol. 11, Summary. 230 SCE-18, Vol. 11, at 4, Table I-3 (Summary of Grid Technology O&M Expenses, Constant 2015 $000). 231 Id. at 3, Table I-1 (Summary of Grid Technology Capital Expenditures, 100% CPUC Jurisdictional – Nominal $000). 232 SCE Opening Brief at 83, citing SCE-02, Vol. 11, at 45-46 and SCE-18, Vol. 11, at 22. - 108 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA opposes funding for SCE’s DVVC program on the basis that the program is actually a “grid modernization” program, and ORA opposes funding the latter program in this GRC. In rebuttal, SCE asserts that DVVC predates the Commission’s DRP proceeding, and in any case “fits squarely within the Energy Division’s definition of projects that ‘can be proposed and authorized through IOUs’ GRCs separate from Grid Modernization Guidance.’”233 SCE states that it had proposed DVVC-type projects, and been laying the foundations for this project with its new Distribution Management System application in the both the 2012 and 2015 GRC, long before DERs were an issue of focus for the Commission. We find SCE’s explanation that the DVVC program is being proposed for its reliability benefits and the benefits of reduced energy costs that it will bring to SCE’s customers to be reasonable. We approve SCE’s requested level of funding for Test Year 2018, $4.414 million. 4.11.2. Equipment Demonstration & Evaluation Facility This item is addressed in Section 19 of this decision, “Rate Base – Other Issues.” 4.11.3. Energy Storage Pilots SCE requests funding of capital expenditures for its Distributed Energy Storage Integration (DESI) pilot program. SCE explains that in order to integrate energy storage, it “plans to conduct pilots to better understand energy storage performance and cost competitiveness, and making sure electric service remains 233 SCE-18, Vol. 11, at 24. - 109 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 safe and reliable as more energy storage is integrated onto the grid.”234 SCE forecasts capital expenditures totaling $22.499 million in 2018. ORA and TURN oppose SCE’s DESI pilot funding request. ORA opposes SCE’s proposed DESI pilots because ORA believes the pilots violate a Commission order in its Electric Program Investment Charge (EPIC) proceeding that ORA believes prohibits SCE and other investor-owned utilities from seeking funding for research, development and demonstration (RD&D) proposals in GRCs. ORA asserts that the DESI pilots should instead be proposed as technology demonstration and deployment (TD&D) projects in the EPIC program. SCE addresses ORA’s assertions in rebuttal testimony. SCE contends that the types of projects eligible for funding in GRCs and the EPIC program are mutually exclusive, and the DESI pilots fit the criteria for GRC funding, and not EPIC funding. The Commission has defined an EPIC-eligible RD&D project as one that supports research into: the installation and operation of pre-commercial technologies or strategies at a scale sufficiently large and in conditions sufficiently reflective of anticipated actual operating environments to enable appraisal of the operational and performance characteristics and the financial risks.235 SCE contends that, while it is correct that the energy storage technologies that SCE proposes to implement in its DESI pilots are in the early stages of the technology maturity cycle, these technologies are already commercially 234 SCE-02, Vol. 11, at 34. 235 D.12-05-037, Ordering Paragraph 3. - 110 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 available.236 As such, they would not qualify for EPIC funding, which only supports research into pre-commercial technologies. Furthermore, the DESI pilots involve expenditure for capital projects that will be “used and useful” for the duration of their service lives, and “will provide energy services to customers for the useful life of the asset, rather than for a particular project or demonstration.”237 This contrasts with EPIC projects that are only funded for a three-year period. TURN opposes funding for the DESI pilots for four reasons: 1. The majority of proposed costs should be directed through the EPIC program; 2. The proposed energy storage projects do not provide ratepayer benefits that could not be obtained with existing pilots or SCE-owned storage facilities; 3. The energy storage pilots do not meet fundamental requirements of the Commission’s Energy Storage Mandate Program and are not needed for other pilot proceedings; and 4. The energy storage pilots are not needed for the DRP or Integrated Distributed Energy Resources (IDER) Programs. As it did in response to ORA’s contentions, SCE provides extensive rebuttal testimony that refutes each of TURN’s contentions. Based on our review of the extensive record regarding SCE’s proposed DESI pilots, we find that SCE’s forecast level of capital expenditures in 2018 is reasonable, and we authorize the $22.499 million requested by SCE. 236 SCE-18, Vol. 11, at 12: “the energy storage technologies we seek funding for are commercially available and fully supported as commercial products by vendors.” 237 Id. at 13. - 111 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Based on the discussions of the disputed items above, we approve SCE’s request for Grid Technology capital expenditures and O&M expenses in Test Year 2018 as shown in the tables below. Adopted Grid Technology Capital Expenditures (100% CPUC Jurisdictional – Nominal $000) Activity 2017 Distribution Volt VAR Control Capacitor Automation Program Advanced Technology Laboratories Advanced Outage Detection and Analytics Program (withdrawn in SCE18, Vol. 11) Energy Storage Pilots Total 2018 Total 2018 2017Adopted 2018 7,065 4,414 2,854 0 14,604 3,567 2,651 2,854 8,676 4,414 0 5,928 0 0 0 0 14,518 28,699 22,499 32,841 37,017 61,540 22,499 32,841 Adopted Grid Technology 2018 O&M Forecast (Constant 2015 $ Millions) GRC Account Activity Requested Adopted 560.260 Grid Technology Expenses – Transmission 2,598 2,598 580.260 Grid Technology Expenses – Distribution 13,317 13,317 Total 15,915 15,915 4.12. T&D – Safety Training & Environmental Programs In its testimony on Safety, Training & Environmental Programs SCE requests the O&M expenses it considers necessary for its T&D operating unit to provide safety programs; develop and deliver training programs; environmental programs; and disposal of hazardous waste. SCE requests $62.081 million for - 112 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 O&M expenses in Test Year 2018.238 ORA challenges SCE’s forecasts in two areas, which we discuss below. 4.12.1. Environmental Program – Transmission (Acct. 565.281) SCE requests $4.608 million in Test Year 2018 for its transmission-related environmental program. This program supports restoration activities on transmission projects after construction is complete. SCE’s request is based on the environmental remediation work forecasted for specific transmission projects in 2018-2020. ORA forecasts $2.898 million for 2018, which is the amount that SCE recorded in 2015. In rebuttal, SCE explains that its project-specific forecast uses the same methodology the Commission adopted for SCE in D.15-11-021. We agree that SCE’s current forecasting method, based on work that is likely to be required rather than an analysis of historical costs, is reasonable. We adopt SCE’s forecast of $4.608 million in Test Year 2018 O&M for Account 565.281. 4.12.2. Hazardous Waste Management & Disposal – Distribution (Acct. 598.250) SCE requests $3.551 million in Test Year 2018 for its distribution waste management program. SCE states that its waste management services include the lab expenses and cost to dispose of equipment and material removed from the field such as transformers, oil and oil-filled equipment, hazardous materials, non-hazardous materials, wood poles, and universal waste. SCE forecast its 2018 expenses by calculating the average of four years of recorded expenses (2012-2015). SCE based its forecast on this four-year average because “the 238 SCE-18, Vol. 12, at 2, Table I-1 (Safety, Training and Environmental Programs O&M, Constant 2015 $000). - 113 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 frequency and likelihood of occurrence of the events requiring waste removal fluctuate from year-to-year and are difficult to predict.”239 ORA forecasts $2.359 million for 2018, which is the amount that SCE recorded in 2015. ORA bases its recommendation on the fact that SCE’s recorded costs have declined each year between 2011-2015. In rebuttal, SCE agrees that its costs for this account show a downward trend through 2015, but notes that 2016 recorded costs were 66% higher than 2015 costs “primarily due to the types of costs that appear intermittently and may vary significantly from year to year” such as a lead paint remediation project at a distribution substation, and an increase in clean-up of transformer oil spills.240 We agree that the level of recorded costs during the 2011-2016 period is “indicative of the unpredictable nature of this account” and supports the use of a multi-year average as the forecasting methodology.241 We also find that SCE properly excluded two years showing unusually high activity, which would have otherwise inflated its forecast. We adopt SCE’s forecast of $3.551 million in Test Year 2018 O&M for Account 598.250. Based on the discussion above, we approve SCE’s request for $62.081 million for O&M expenses in Test Year 2018 as shown in the table below. 239 SCE-02, Vol. 12, at 30. For the same reason, SCE excluded 2011 costs from its calculation because of the unusually high expenses to perform waste clean-up after the windstorms. 240 SCE-18, Vol. 12, at 8-9. 241 Id. at 9. - 114 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 T&D Safety, Training and Environmental Programs 2018 O&M Forecast (Constant 2015 $ Millions) GRC Account Description SCE Forecast 565.281 Environmental Programs – Transmission 566.250 Employee Safety - Transmission Personnel Training Delivery - Transmission Personnel Training Seat-Time - Transmission Personnel Informational Meetings - Transmission Personnel Employee Recognition - Transmission Personnel Total 566.250 573.250 Waste Management - Transmission 582.250 Environmental Programs – Distribution 588.250 Employee Safety - Distribution Personnel Training Delivery - Distribution Personnel Training Seat-Time - Distribution Personnel Informational Meetings - Distribution Personnel Employee Recognition - Distribution Personnel Total 588.250 598.250 Waste Management - Distribution Total 4,608 ORA Differences Adopted 2,898 4,608 2,734 3,284 6,368 520 151 13,057 13,057 246 246 2,012 2,012 9,065 9,244 17,589 2,591 117 38,607 38,607 3,551 1,192 3,551 62,081 59,179 62,081 4.13. T&D – Other Costs, Other Operating Revenues SCE requests approval of two distinct forecasts in SCE-02, volume 13. One requested approval is for SCE’s forecast of Other Operating Revenues (OOR). SCE receives OOR from transactions not associated with the sale of electric energy. Tariffed OOR is based on CPUC or FERC-approved rates. Tariffed OOR offsets the revenue requirement SCE would otherwise collect from - 115 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 general ratepayers. SCE forecasts $126.426 million in 2018 for tariffed OOR for T&D activities.242 No party disputes SCE’s 2018 forecast for T&D OOR. We find SCE’s undisputed forecast of total OOR reasonable and adopt it. The second requested approval is for SCE’s forecast of O&M costs for operational support groups within the T&D organization. SCE forecasts the Test Year 2018 costs of the activities performed by a number of support groups:  Grid Interconnection Contract Development;  Reliability Standards Compliance;  Grid Contract Management;  Distribution Construction Contract Management; and  Real Properties. SCE also forecasts the costs for related activities such as T&D work order write-offs and claims; line rents; underground locating; and related expenses. SCE requested approval of its forecast for $130.944 million in O&M expense for Test Year 2018 for these areas.243 TURN and ORA contested a number of line items in SCE’s forecast. TURN recommended a methodological change to SCE’s calculation of its forecast for underground locating services (Account 588.281). SCE accepts the change recommended by TURN. This results in a test year forecast equal to 242 In SCE-02, Vol. 13, at 40, Table III-19 (Other Operating Revenue (OOR) Request Test Year 2018 Forecast) SCE forecast $130.703 million in OOR. SCE subsequently reduced this forecast by $4.277 million in SCE-60, Tax Update at 16-17, Appendix A at 57. 243 Id. at 5, Table III-1. SCE notes that this amount is effectively reduced by the forecast OpX savings of $10 million identified in Table I-3 of Exhibit SCE-02, Vol. 1. On that basis, SCE’s 2018 O&M request becomes $120.944 million. - 116 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $8.227 million, which is $363,000 lower than SCE’s original request ($8.590 million). We approve the mutually-agreed upon lower value. ORA contested the following line items in SCE’s forecast: 1. 2. 3. 4. Transmission Work Order Write-Offs Distribution Work Order Write-Offs Transmission Capital-Related Expense Distribution Capital-Related Expense Regarding the first and second items, write-offs for Transmission work orders (Account 560.281) and Distribution work orders (Account 588.281), SCE’s forecasts are based on five-year averages of recorded data. ORA proposes to use the most recent recorded year (2015) because ORA finds a downward trend in costs in recent years. In rebuttal, SCE noted that the Commission has approved the five-year average methodology in SCE’s two most recent GRC proceedings. For example, in D.15-11-021 the Commission agreed that using a five-year average to forecast accounts that are influenced by forces outside SCE’s control, such as these accounts. We see no reason to change our precedent at this time, so we approve SCE’s forecasted amounts as shown in the table at the end of this section.244 Regarding the third and fourth items, Transmission/Substation Capital-Related Expense (Account 560.281) and Distribution Capital-Related Expense (Account 594.281), in both instances ORA objects to the methodology that SCE used to calculate its forecasts. SCE’s rebuttal testimony provided a detailed explanation of the logic underlying SCE’s calculations, as well as a detailed critique of ORA’s method. SCE’s explanation showed why its approach 244 We will be open to revisiting this methodology in SCE’s next GRC if additional data is presented that shows a more established downward trend. - 117 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 is reasonable. Therefore, we approve SCE’s forecasted amounts, as shown in the table below:245 T&D Operational Support and Other Costs 2018 O&M Forecast (Constant 2015 $ Millions) GRC Account 560.221 560.281 Total 566.280 Total 567.150 570.281 583.281 588.280 588.281 Total 594.281 920.220 Description SCE ORA Reliability Standards 1,407 1,407 Compliance Transmission Work 2,404 966 Order Write-Offs Transmission Capital 12,637 12,471 Related Expense 560.281 15,042 13,437 Grid Contract 2,041 2,041 Management Grid Interconnection 5,530 5,530 Contract Development 566.28 7,571 7,571 Transmission Line Rents 17,203 17,203 Transmission Participant 14,082 14,082 Share Distribution Claims 11,413 11,413 Write-Offs Distribution Construction Contract 1,294 1,294 Management Distribution Work Order 7,389 6,490 Write-Offs Distribution Line Rents 2,889 2,889 Underground Locating 8,590 8,590 Service 588.281 18,868 17,969 Distribution Capital 40,725 34,923 Related Expense Real Properties 3,339 3,339 Total* 130,944 122,638 *Due to rounding, subtotals may not sum to totals. 245 ORA Variance TURN TURN Variance Adopted 1,407 (1,438) 2,404 (166) 12,637 (1,604) 15,042 0 2,041 0 5,530 0 0 7,571 17,203 0 14,082 0 11,413 0 1,294 (899) 7,389 0 2,889 0 (899) 8,227 (363) 8,227 (363) 18,505 (5,802) 40,725 0 (8,305) 3,339 130,581 (363) SCE-18, Vol. 13, at 3, Table I-2 (T&D Operational Support and Other Costs, 2018 O&M Forecast, (Constant 2015 $ Millions)). - 118 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 5. Customer Service 5.1. Customer Service – O&M For Test Year 2018, SCE forecasts $198.871 million (constant 2015 $) in operation and maintenance (O&M) expenses for Customer Service. This request is $9.07 million below SCE’s 2015 recorded adjusted base. Of the total, SCE forecasts $7.15 million in O&M costs related to SCE’s proposed Customer Service (CS) Re-Platform project based on an $8.90 million expense and benefits of $1.75 million.246 The adopted O&M forecast follows:247 Description ($ in millions) Meter Reading Operations (FERC 902) Test, Inspect & Repair Meters (FERC 586.400) Turn-On and Turn-Off Services (FERC 586.100) Installation and Energy Theft (FERC 587) Meter Services Operations and Management (FERC 580) Billing Services (FERC 903.500) Credit and Payment Services (FERC 903.200) Postage (FERC 903.100) Uncollectible Expenses (FERC 904) Customer Contact Center (FERC 903.800) Business Customer Division (FERC 908.600) Customer Programs and Services Division (FERC 905.900) Operating Unit Management and Support (FERC 901,907.6) Total 5.1.1. SCE ORA TURN 10.165  15.511  4.875  6.932  10.165  15.511  4.875  6.932  9.909  14.407  4.761  6.353  ADOPTED 9.909  15.438  5.164  6.506  5.826  5.826  5.671  5.671  27.084  25.190  23.548  16.125  15.792  14.418  15.496  15.309  14.371  0.216% 0.216% 0.211% 46.289  39.489  37.754  18.520  18.432  18.316  23.645  15.477  14.371  0.211% 43.779  18.790  24.442  24.442  24.326  24.656  7.609  7.609  0  6.887  198.871  189.572  173.834  190.293  The Impact of Customer Growth Although there is a link between the number of customers SCE serves and the cost of its Customer Service activities, the link between the growth of the number of customers and costs is less apparent. Based on 2016 246 SCE-03 RA2, at 8:7-10. 247 See, SCE-19, at 3, Table I-4. - 119 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 recorded/unadjusted expenses for 2016 which were below forecasts, TURN recommends against upward adjustments based on growth. We have recognized a link between customer growth and increased expenses in the past; however, due to automation and increasing efficiency, the link appears far more tenuous. 5.1.2. Metering Services 5.1.2.1. Meter Reading Operations – FERC Account 902 Based on a downward trending expense, TURN recommends a reduction of $256,000 from SCE’s proposal of $10.165 million by removing the projected increase due to growth.248 SCE criticizes TURN’s use of unadjusted 2016 expenses but does not present concrete, countervailing evidence.249 We accept the proposed reduction and authorize $9.909 million. 5.1.2.2. Test, Inspect, and Repair Meters – FERC Account 586.400 Again based on downward trending activity and expense, TURN recommends a reduction of $362,000 from SCE’s proposal of $15.511 million by eliminating the projected increase for customer growth.250 SCE has not established a clear correlation between customer growth and meter testing, inspection, and repair. TURN further recommends a reduction of $1.01 million251 based on a reduction of costs demonstrated by a comparison of adjusted 2015 data to 248 TURN-03, at 11. 249 SCE-19, at 10-11. 250 TURN-03, at 13. 251 Ibid., less a $25,000 offset for Operational Excellence. - 120 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 unadjusted 2016 data.252 SCE established however, that on an adjusted basis, 2015 recorded expenses would be similar to 2016 and we do not accept the additional reduction. Therefore, we eliminate the projected increase for customer growth of $362,000, and we exclude the CS Re-Platform benefit of $289,000. We authorize $15.438 million. 5.1.2.3. Turn-On and Turn-Off Services – FERC Account 586.100 SCE forecasts $4.875 million in Test Year 2018 for this account, after adding $114,000 for customer growth and subtracting $289,000 due to CS Re-Platform benefits.253 Although there is merit to TURN’s argument that a decline in activity is inconsistent with customer growth, SCE notes the decline is insignificant.254 We find SCE’s forecast to be reasonable and authorize it, however, we adjust it to $5.164 million to remove the CS Re-Platform benefit. 5.1.2.4. Customer Installation and Energy Theft Expense – FERC Account 587 SCE bases its $6.932 million forecast in FERC account 587 on 2015 recorded adjusted expenses of $6.779 million. SCE adjusted this base cost to include $153,000 in customer growth.255 TURN again argues declining recorded expenses support eliminating the adjustment for customer growth. We, however, recognize there may be a direct correlation between installations and other contributors to this account and 252 Ibid. 253 Id., at 15:4-11. 254 Id., at 16-17. 255 Id., at 17:12-17. - 121 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 customer growth. The adjustment for customer growth proposed by SCE is reasonable. TURN proposes a further reduction based on significant reductions in the level of activity for pick-up reads and exception orders. On this basis, TURN recommends using 2016 as the base year, resulting in a reduction of $426,000.256 The proposed reduction is consistent with declining recorded expenses for this account. Based on this reduction we authorize $6.506 million for this account in 2018. 5.1.2.5. Meter Services Operations and Management – FERC Account 580 SCE forecasts $5.826 million for this account based on 2015 recorded adjusted expenses of $6.852 million and adding $155,000 for customer growth and subtracting $1.181 million for savings from Operational Excellence.257 TURN proposes to eliminate the increase for customer growth based on declining costs in 2016 for this account.258 SCE argues TURN does not acknowledge SCE’s improving operational excellence and productivity which has led to declining costs and offset increases due to customer growth.259 Although the impact from improvements in operational excellence and productivity is apparent, SCE has not established the impact of customer growth on this account. We authorize $5.671 million. 256 TURN-03, at 14. 257 SCE-03 R, at 66-68 258 TURN-03, at 15. 259 SCE Opening Brief, at 100. - 122 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 5.1.3. Revenue Services Organization 5.1.3.1. Billing Services – FERC Account 903.500 The Revenue Services Organization conducts all billing, payment, credit, collection, and program operations.260 SCE’s 2015 recorded adjusted expenses for Billing Services were $27.420 million. SCE adjusted this base cost to include $619,000 in customer growth, $1.886 million for program changes (including policy adjustments, service guarantees, NEM, and community choice aggregator (CCA) programs), and $1.760 million for CS Re-Platform expenses. SCE also adjusted the base cost to remove $4.178 million in savings achieved through Operational Excellence initiatives and $423,000 in CS Re-Platform benefits. These adjustments result in SCE’s forecast for 2018 of $27.084 million for FERC account 903.500.261 ORA and TURN oppose $249,000 for service guarantees.262 SCE has – repeatedly over the span of several GRCs – sought to place this expense on ratepayers and we have – repeatedly – denied the request.263 In the most recent GRC we repeated a statement from SCE’s Test Year 2006 GRC Decision: Regarding the payments to customers, these are payments that result from the company not meeting its commitments to individual customers. If the company is unable to meet its commitments, the 260 SCE-03 R, at 69:6-7. 261 SCE-03 RA2, at 87, Table IV-22. 262 $244,000 for Service Guarantee Program and $5,000 for MSO Missed Appointments. SCE-03 R, at 81:18-21. See, ORA-12, at 14-18; TURN-03, at 16-19. 263 D.06-05-016 at 122; D.09-03-025 at 108; D.12-11-051 at 228; D.15-11-021 at 194. - 123 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 shareholders and not the ratepayers should be responsible for reimbursing the inconvenienced customer.264 Not only does the service guarantee provide some compensation to customers who are inconvenienced by SCE’s failure to meet its service goals, the service guarantee creates an incentive for SCE to meet these goals. That incentive is most effective when it is paid by the shareholders, not ratepayers. Therefore, we deny SCE’s request of $249,000 for the Service Guarantee Program. TURN proposes eliminating an increase of $619,000 for customer growth based on a decline of two percent in 2016 recorded costs from forecast costs. TURN contends this shows customer growth does not drive costs for this account. SCE counters that TURN fails to acknowledge SCE’s continuing productivity improvements and operational excellence and that these successes offset customer growth and other drivers of cost. We see no indication that TURN disregards the impact these improvements have on reducing SCE’s costs. SCE however, has not established that costs due to growth will not continue to be limited as a benefit of its productivity improvements and Operational Excellence. The increase of $619,000 for customer growth is not allowed. TURN recommends removing $40,000 from the forecast for policy adjustments for Net Energy Meeting expenses on the basis that SCE does not expect these expenses to recur. Although SCE acknowledges it does not expect these specific issues to recur, SCE contends it is “reasonable to assume that other unique events could occur.”265 We see this as an argument for speculation and do not agree it meets SCE’s burden for including the expense. Furthermore, 264 D.06-05-016 at 122. 265 SCE Opening Brief at 102. - 124 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s request for policy adjustments forecasts a total of $366,000. Policy Adjustments include “billing adjustments that may address customer issues related to field errors” and “can vary significantly.”266 SCE has established that the forecast amount is highly variable, but like the service guarantee, SCE has not established that ratepayers should pay for its errors. We do not authorize any amount for policy adjustments. SCE’s forecast also includes an increase of $568,000 for NEM application processing. These applications have experienced a downward trend both in number and expense. SCE has not established these costs will rise and we exclude the $568,000. TURN recommends reducing the forecast by $300,000, which it attributes to declining costs associated with the growth in e-bill enrollments during 2019 and 2020.267 Although continuing growth in e-bill enrollment may be expected, SCE has not established continuing growth is adequately reflected in its forecast and we accept TURN’s proposal to add $300,000 in savings to SCE’s forecasted savings of $1.257 million. Within this account SCE also proposes $1.760 million for CS Re-Platform expenses and $423,000 in CS Re-Platform benefits. TURN and ORA recommend denying the requests for CS Re-Platform and allowing SCE to track those costs in a memorandum account. We agree, in part, as is more fully discussed in Section 6.3 of this decision. 266 SCE-03 R, at 77:14-16. 267 TURN-03, at 19. - 125 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Based on the foregoing, and including the anticipated benefits of Operational Excellence of $4.178 million and an increased expense of $1.163 million for CCA account processing,268 we approve $23.645 million for FERC account 903.500. 5.1.3.2. Credit and Payment Services – FERC Account 903.200 SCE forecasts $16.125 million for FERC account 903.200 based on 2015 recorded adjusted expenses of $16.348 million. SCE adjusted this base to include $368,000 in customer growth, $333,000 for CS Re-Platform expenses and to remove $871,000 in savings achieved through Operational Excellence initiatives and $53,000 in CS Re-Platform benefits.269 As is more fully discussed in Section 6.3 of this decision we exclude the expenses and benefits of CS Re-Platform. We recognize SCE’s contention that the expenses recorded to this account are driven by customer growth; however, SCE has not fully supported its forecast in light of the declining costs for these services. We therefore, exclude the increase for customer growth and with the exclusion of CS Re-Platform expenses and benefits and the inclusion of savings for Operational Excellence, we approve $15.477 million for this account. 5.1.3.3. Postage – FERC Account 903.100 SCE forecasts $15.309 million in FERC account 903.100 following adjustments for program changes and Operational Excellence to 2015 recorded 268 SCE-03 RA2, at 80, Table IV-19. 269 SCE-03 at 97-103. - 126 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 expenses of $20.486 million.270 TURN recommends a further reduction to SCE’s forecast of $1.168 million due to an anticipated increase of three million electronic bills.271 SCE acknowledges its forecasted savings are through 2018 and “will continue to occur in the attrition years.”272 Although SCE acknowledges the savings which occur as of 2018 will continue into the future, SCE has failed to forecast any continued growth in electronic billing and the corresponding savings. We accept TURN’s proposed reduction. SCE, in its updated testimony, proposes an additional increase of $187,000 for a 2018 postal rate increase.273 TURN correspondingly adjusted their proposed reduction to $1.125 million; we adopt TURN’s proposed adjusted forecast of $14.371 million.274 5.1.3.4. Uncollectable Expenses – FERC Account 904 SCE recommends an Uncollectible Factor forecast of 0.216% based on a five-year recorded adjusted average from 2011 – 2015.275 In this instance we are persuaded to use 2016 unadjusted data as is proposed by TURN as it is consistent with the downward trend of the data.276 Therefore, based on a five-year average of 2012 – 2016, we adopt a forecast of 0.211%. 270 SCE-19, at 33. 271 TURN-03, at 21. 272 SCE-19, at 28:18, 28:10-21. 273 SCE-59, at 30:1-14. 274 TURN-15, at 6. 275 SCE-03, at 113-117. 276 TURN-03, at 23-24. - 127 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 5.1.4. Customer Contact Center – FERC Account 903.800 SCE forecasts $46.289 million for FERC account 903.800 based on 2015 recorded adjusted expenses of $43.457 million. SCE adjusted this base to include $980,000 in customer growth, $579,000 in program changes (to support CCAs, time-of-use rates, and critical-peak-pricing programs), $6.8 million for CS Re-Platform expenses, and to remove $5.429 million in savings achieved through Operational Excellence initiatives and $98,000 in CS Re-Platform benefits.277 Due to the steadily declining expenses since 2011 for this account, we decline to include the adjustment of $980,000 for customer growth. We remove $5.429 million in savings achieved through Operational Excellence initiatives. We also accept $322,000 for program changes (to support CCAs). We do not accept, at this time, adjustments for time-of-use rates, and critical-peak-pricing programs of $257,000 as it is anticipated implementation of these programs will be delayed, pending the CS Re-Platform. As discussed elsewhere, we also do not include $6.8 million for CS Re-Platform expenses and $98,000 in CS Re-Platform benefits. Therefore, we accept $43.779 million for this account. 5.1.5. Business Customer Division – FERC Account 908.600 SCE forecasts $18.520 million for the Business Customer Division following adjustments to 2015 recorded adjusted expenses for customer growth, program changes, Operational Excellence, and CS Re-platform.278 ORA proposes a reduction of $88,000 based on the difference between forecast costs and 277 SCE-03, at 126-133. 278 SCE-03, at 167-169. - 128 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 recorded costs for Outage Communications.279 Due to recent activity, which is consistent with the forecast, we deny the ORA proposal.280 We find the increase of $204,000 for customer growth to be reasonable. We adjust the forecast to remove the benefit of $270,000 for the CS Re-Platform and therefore accept a forecast of $18.790 million. 5.1.6. Customer Programs and Services – FERC Account 905.900 SCE forecasts $24.442 million for this account based on 2015 recorded adjusted expenses of $24.483 million. SCE adjusted this base expense to include $4.44 million in program changes and remove $4.151 million in savings achieved through Operational Excellence initiatives and $330,000 in CS Re-Platform benefits.281 We accept TURN’s proposal for a 50% reduction of the new product opportunities forecast in the amount of $116,000. These costs are properly placed on shareholders as they result in non-tariffed products and services for which related costs are not chargeable to customers.282 Accepting this reduction and removing the benefits of the CS Re-Platform, we adopt the forecast of $24.656 million for Customer Programs and Services. We find the recommendations of the NDC to be laudable, but we do not accept their recommendations to (1) dedicate at least 40% of SCE’s major marketing campaign budgets for targeting minority groups, (2) increase SCE’s 279 ORA-12, at 31. 280 SCE-19, at 45:1-16. 281 SCE-03RA, at 50. 282 See TURN-03, at 25. - 129 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 use of community-based organizations (CBOs), and (3) include an overview of SCE’s marketing planning process in testimony.283 SCE has demonstrated a commitment to outreach to its diverse communities which is consistent with NDC’s recommendations;284 we will not impose greater requirements. 5.1.7. Operating Unit Management and Support – FERC Accounts 901 and 907.600 SCE’s 2018 forecast for its Operating Unit Management and Support (OUMS) is $7.609 million ($5.122 million in FERC Account 901 and $2.487 million in FERC Account 907.600) based on 2015 recorded adjusted expenses of $8.817 million ($6.330 million in FERC Account 901 and $2.487 million in FERC Account 907.600).285 Account 901 non-labor expenses grew by over 460% from 2012 through 2015 reportedly due to the increased use of consultants for Operational Excellence activities.286 SCE’s forecast removes $1.208 million from Account 901 based on the reduced use of consultants.287 SCE uses the adjusted last recorded year for its forecasts due to the “trend” of the historic recorded expenses.288 We accept the forecasts for Account 907.600 and the labor forecast for Account 901 on this basis. SCE notes however, “If … expenses had exhibited significant fluctuations, an Averaging method is the 283 See NDC, at 24. 284 SCE-19, at 52. 285 SCE-03 R, at 216, Figure X-42. 286 SCE-03 R, at 216:8-217:2. 287 SCE-03 R, at 219:18-220:2. 288 SCE-03 R, at 218:5-220:13. - 130 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 appropriate basis for estimating Test Year expenses.”289 Therefore, due to the significant fluctuation in the non-labor expense for Account 901, we authorize a forecast of $4.4 million for Account 901, based on the average of the five-year non-labor expense of Account 901 of $2.669 million.290 This results in a further reduction for these accounts of $0.722 million and we adopt for FERC Accounts 901 and 907.600 a forecast of $6.887 million. 5.2. Customer Service – Capital SCE forecasts capital expenditures of $22.79 million in 2016, $28.04 million in 2017 and $38.84 million for Test Year 2018.291 ORA recommends capital expenditures of $16.328 million in 2016, $28.04 million in 2017, and $38.84 million for Test Year 2018. ORA relies on actual recorded capital expenditures for 2016. ORA does not dispute SCE’s 2017 and 2018 forecast.292 SCE has agreed to use the 2016 recorded capital expenditure of $16.328 million for 2016;293 it is adopted. TURN, like SCE, recommends using a three-year average to forecast meter replacements, but recommends using the most recent data available, averaging 2014-2016 instead of the average of 2013-2015 used by SCE to forecast the number of replacements. We agree use of the 2016 data is reasonable and reduce the capital forecast for replacement meters. These reductions reduce the 2017 289 SCE-03 R, at 219, fn. 225, citing D.04-07-022 and D.89-12-057. 290 SCE-03 R, at 216. 291 SCE-03 R, at 11, Table I-2. 292 ORA-12, at 34-35. 293 SCE-29, at 48, Issue title: SCE-002, ORA-SCE-TXB-108 Q2 Supplemental Revised. - 131 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 amount by $3.788 million to $24.251 million and 2018 by $3.883 to $34.956 million.294 5.3. Customer Service – Other Operating Revenue OOR are derived from service connection charges for the establishment of service and reconnecting service following disconnection for nonpayment of bills, returned check charges to offset costs associated with the processing of checks that are returned from the bank due to insufficient funds, other services associated with Direct Access and Community Choice Aggregation, and other special services. SCE estimates OOR to be $27.981 million in Test Year 2018 based on its proposed service fees, compared to $32.255 million in 2015 recorded OOR.295 We adopt the undisputed forecast. 5.4. Customer Service – Additional Issues SCE and SBUA entered into two joint exhibits and stipulations, SCE-SBUA–1 and SCE-SBUA-2. Pursuant to SCE-SBUA–1: SCE will continue to have a group of Business Customer Division (“BCD”) Account Managers who are available and responsible for consulting with Small Business customers and assist them on various programs, services, and provide support for SCE’s integrated demand-side management offerings. SCE will assign one Manager as the primary supervisor with the title and core responsibility to oversee SCE’s operations to engage and serve SCE’s small commercial customers with programs and services that meet their needs and enable them to be knowledgeable and involved in managing their energy usage. The parties recognize that this manager may engage in matters that serve to benefit other customer 294 TURN-03, at 27, Table 25. 295 SCE-03RA, at 12-13. - 132 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 classes as well. In addition, SCE’s call center energy advisors are also trained and available to handle commercial and industrial (“C&I”) calls that relate to the different C&I rate schedules and programs, and resolve concerns related to customers’ electricity usage. … SCE and SBUA agree that SCE will create a webpage specifically dedicated for Small Businesses (the “Small Business Webpage”) during the 2018 GRC Period. SCE will work in good faith to make the “Small Business Webpage” easily accessible and will identify SCE’s internal resources for Small Businesses, including training materials to educate small businesses on energy efficiency, distributed generation, and energy storage, and may also direct small business customers to third-party or external resources. SCE may leverage information and links from sce.com/business and the Economic Development Services resources page online. … SCE will work with local, regional and state officials and economic development organizations to enhance economic development programs that support and promote Small Business customers. SCE will provide testimony in its 2021 GRC on its efforts to promote the interests of Small Business customers through its business customer economic development program and services. SCE’s involvement in the above-described business customer Economic Development activities is contingent on CPUC-authorized funding for SCE’s forecast business customer economic development organization and activities. … Unless stated otherwise, for purposes of this Agreement, “Small Businesses” shall mean those businesses that are either on a GS-1 rate or, for purposes of aligning with SCE programs, who employ - 133 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 fewer than 500 employees (as defined by the United States Small Business Administration).296 Pursuant to SCE-SBUA-2: SCE will commit to sponsoring or attending at least four events per year and to promote outreach to small businesses as defined above. Further, SCE will notify SBUA of the above-referenced events at least 30 days in advance for sharing with its constituents who may wish to participate. Participation or registration will be managed on a first come first served basis, and may be limited due to event size or venue capacity restrictions. … SCE will commit to offering a variety of payment options that can help small businesses maintain positive cash flow to sustain their operations: i. SCE agrees to provide options of varying periods and discount values based on the particular needs of the small business suppliers and subject to SCE’s business requirements. ii. SCE agrees to offer potential electronic disbursement options, such as Automated Clearing House (ACH) and credit card, to expedite the timing of payment for small business suppliers upon request and subject to SCE’s business requirements. iii. SCE shall evaluate potential modifications of insurance requirements for small business suppliers, subject to the specific project requirements, the capabilities of the supplier, and the risk inherent to the work. iv. SCE shall post information concerning the foregoing matters on its dedicated Supplier page and include a link to the dedicated Supplier page on its new Small Business Webpage at SCE.com. The Small Business Webpage is the webpage specifically dedicated for Small Businesses (the “Small Business Webpage”) that SCE will create during the 2018 GRC Period and was 296 SCE-SBUA-1, Joint Exhibit Resolving Various Customer Service Issues [excerpts]. - 134 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 previously described in the Joint Exhibit and Stipulations Resolving Various Customer Service-Related Issues between SCE and SBUA (entered on the record on July 21, 2017). … SCE shall dedicate a section [of Testimony in 2021 GRC] detailing its compliance with the SCE-SBUA 2018 GRC settlement. … OUTREACH INITIATIVES FOR SMALL BUSINESS CUSTOMERS A. Education and Outreach on CPP[Critical Peak Pricing]. SCE agrees to meet and confer with SBUA after the Commission approves changes to SCE’s CPP and TOU [Time of Use] programs and at least 90 days (or as soon as practically possible in the case of accelerated outreach activities) in advance of implementing new outreach and education efforts on CPP for small commercial customers. The parties shall meet and confer around a CPP outreach plan and SCE agrees to reasonably consider SBUA’s requests for improvements or changes to CPP outreach. B. Spend for TOU and CPP. SCE agrees that at least half of the requested $1.98M for CPP and TOU initiatives, if approved by the CPUC, will be dedicated to initiatives to primarily serve small businesses, which includes customers designated on SCE’s GS-1 rate schedule. The parties recognize that the CPUC may issue compliance directives subsequent to this Agreement, which may impact SCE’s ability to meet this term. In the unexpected event this occurs, SCE will notify SBUA within 60 days of receiving such compliance requirements, including a revised amount SCE agrees to dedicate to customers designated on SCE’s GS-1 rate schedule. …297 297 SCE-SBUA-2, Joint Exhibit And Stipulations Resolving Various Small Business Contracting And Customer Service-Related Issues Between Southern California Edison Company And Small Business Utility Advocates. - 135 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The commitments agreed to by SCE within these stipulations are reasonable and further the interests of ratepayers generally and small business customers of SCE specifically; they are adopted. 6. Information Technology SCE’s Information Technology Operating Unit (IT) is responsible for managing SCE’s computing applications and technology infrastructure. SCE contends its IT O&M and capital expenditure request would support the safe and reliable planning and operation of the electric system, defend against growing cybersecurity threats, maintain and improve customer and IT service desk functions, and deploy critical enabling software applications for core business processes.298 Intervenors have proposed reductions to SCE’s O&M request. These recommendations include: (1) reducing SCE’s Hardware/Software License & Maintenance agreements forecast, (2) eliminating expenses related to Grid Modernization and grid planning and analytics efforts, and authorizing the tracking of these costs in a memorandum account, (3) eliminating expenses related to the HR Platform Modernization project, and (4) removing IT O&M expenses related to the CS Re-Platform project and tracking in a memorandum account. Intervenors have also proposed reductions to SCE’s capitalized software request. These include reductions to, and in some cases the complete elimination of: (1) contingency costs for capitalized software projects, (2) cybersecurity expenditures, (3) projects related to the improved planning and analysis of the 298 SCE Opening Brief, at 114. - 136 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 grid, and (4) the Vegetation Management, Comprehensive Situational Awareness Tool, and Enterprise Content Management applications. 6.1. 6.1.1. Information Technology – O&M and Hardware Hardware/Software Licenses & Maintenance The Hardware & Software Licenses & Maintenance account includes the costs to maintain SCE’s IT hardware and software assets through license and maintenance agreements. SCE forecasts $70.73 million for this account.299 ORA and TURN recommend we adopt the 2016 recorded expense for this account of $62.77 million, a reduction of nearly $8 million.300 SCE has met its burden to establish the forecast based on software support moving from capital to O&M and new and increased expenses for software support. Furthermore, SCE’s Operational Excellence savings for this account are significant – over $13 million – and undisputed, and SCE argues, if taken with ORA’s and TURN’s proposed reduction, would result in double counting. We adopt SCE’s forecast of $70.73 million and associated Operational Excellence savings of $13.10 million. 6.1.2. Business Integration & Delivery SCE’s forecast for Business Integration & Delivery (BID) is $44.643 million, based on 2015 recorded costs plus incremental O&M expenses for five project areas: (1) CS Re-Platform; (2) New Grid Planning & Analytics; (3) Grid 299 SCE-20, Vol. 1, at 8. 300 ORA-13, at 16; TURN-04, at 65. - 137 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Modernization; (4) HR Platform Modernization; and (5) Digital Experience SAS.301 As discussed below, O&M expenses for the CS Re-Platform shall be tracked by a memorandum account; we exclude the expenses of $7.682 million here. SCE states New Grid Planning and Analytics will provide required support for the Grid Interconnection Processing Tool, Grid Analytics Application, Long Term Planning Tool, and Grid Connectivity Model. We do not adopt the capital projects associated with these expenses of $2.547 million; therefore, we exclude the expenses here. By contrast, we adopt the SMT and the DRPEP projects302 associated with Grid Modernization and therefore approve the O&M expense of $1.3 million associated with these projects. SCE has reduced its original forecast from $2.9 million to $0.930 million for HR Platform Modernization based on the intention to implement only one module at this time.303 ORA’s contention that SCE may use funding for the existing SAP system O&M (eliminating the allocation entirely) is not persuasive. We find the existing system must continue to be supported in conjunction with incremental funding of the new system. We accept the adjusted estimate of $0.930 million. 301 SCE-20, Vol. 1, at 16. 302 See, Section 4.10. 303 SCE-20, Vol. 1, at 20-21; SCE-04, Vol. 1A2, at 47-48. - 138 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE proposes $0.167 million for its Digital Experience project. This expense is for cloud software enabling customers to perform secure online transactions. The expense is not disputed and we adopt it. We recognize SCE contends the CS Re-Platform will enable SCE to avoid costs of $3.01 million relating to legacy software and that if CS Re-Platform is not approved these costs should be added to this account.304 Although we do not approve the expenses for CS Re-Platform, we, also, have not disapproved of them. We have required the expenses be tracked in a memorandum account. We expect SCE will continue with the CS Re-Platform as planned, and that the costs relating to legacy software will continue to be avoided. Therefore, we do not allow them. Based on the foregoing, we adopt a 2018 forecast for BID of $37.196 million. 6.1.3. Grid Services SCE proposes a base forecast of 2015 recorded O&M of $29.456 million with increased funding of $14.85 million to support Grid Modernization capital projects, for a total of $44.304 million.305 Intervenors do not object to the base forecast; however, ORA and TURN object to Grid Modernization projects. Since we have approved Grid Modernization capital projects elsewhere, we approve the associated O&M of 304 SCE-04, Vol. 1, at 41, footnote 41. 305 SCE-04, Vol. 1, at 60-61; SCE-04, Vol. 1A, at 59; SCE-20, Vol. 1, at 21, Table II-6. - 139 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $5.046 here.306 Therefore, our total adopted amount for Grid Services for 2018 is $34.5 million. 6.2. Information Technology – Capitalized Software ORA proposed using SCE’s recorded capital expenditures in place of forecast expenditures for 2016 for several capitalized software projects. SCE did not object, provided “2016 recorded costs are used for all IT capital projects and cherry-picking is not utilized.”307 Except as noted below, we agree and adopt the 2016 recorded capital expenditures. 6.2.1. Contingency Amounts in Capitalized Software Forecasts SCE requests a total of $152.3 million in capital expenditures for Capitalized Software projects in 2016, $212.8 million for 2017, and $201.1 million for 2018.308 SCE has included contingencies on its capitalized software forecasts of up to 20%.309 SCE requests contingency funding for 2017 of $24.75 million and $23.86 million for 2018310 and “corrects” TURN’s testimony to reflect proposed contingencies of $23.94 million for 2017 and $22.763 for 2018.311 306 O&M is authorized based on the percentage of O&M requested with the percentage calculated from the associated capital authorized to capital requested. See e.g. SCE-20, Vol. 1, at 25:6-14. 307 SCE Reply Brief at 77. 308 SCE-04, Vol. 2 A2, at 1, Table I-1. 309 SCE-20, Vol. 1, at 27:11-12. See fn. 68, ibid., proposed contingency of 24% for the Customer Service Re-Platform is addressed separately. 310 SCE-20, Vol. 1, at 32, Table III-10. 311 SCE-20, Vol. 1, Appendix C-34. - 140 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE argues that the inclusion of contingency amounts in project cost estimates for information technology is “routine” and in line with industry practices and that the contingency is used to “account for uncertainties and variables that are unknown at the time SCE estimates the cost of a project.”312 ORA contends the full amount of the contingency sought by SCE has not been supported, but concedes some level of contingency may be needed to cover unknown risks.313 TURN, by contrast, urges we disallow all contingency allowances in the forecasts as these costs are speculative and place the risks of all cost overruns on ratepayers.314 We recognize, as SCE argues, that budgeting for contingencies may be routine for software projects. We, however, do not agree that budgeting for contingencies for software projects is necessarily appropriate in a general rate case. SCE’s contention that TURN is wrong and there is nothing different about a regulated utility reflects a lack of acknowledgement that this entire proceeding is taking place because SCE is a regulated utility. TURN aptly notes we have stated, “[i]n a normal general rate case, the utility must demonstrate the reasonableness of every dollar in its revenue requirement.”315 When considering these contingencies, SCE’s argument is that contingencies are necessary for the “uncertainties and variables that are unknown” demonstrates that the amounts are unpredictable and we therefore find SCE has not established these costs are reasonable. SCE further contends that it would be “unfair” and “results in poor 312 SCE Reply Brief, at 73. 313 ORA Opening Brief, at 171. 314 TURN Opening Brief, at 145-146. 315 Id., at 145, quoting D.96-12-066. - 141 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ratemaking policy” “[i]f TURN’s proposal prevails, and SCE cannot recover any of its forecast contingencies, it would lose the revenue requirement associated with that legitimate business expense.”316 As its witness testified, [i]n the three-year cycle when the utility spends above authorized levels, it forgoes earning the authorized rate of return from the time the capital additions were made until the next test year. To the extent the assets cost more than what the utility was authorized to collect between test years, the utility would effectively be providing free service to customers from these assets between GRC test years.317 This is, however, always the risk for SCE. By examining one test year out of every three, the Commission offers the utility an incentive to improve its productivity. Any savings the utility can generate between general rate cases belong to the shareholders. In exchange for this opportunity, the shareholders take on the burden of added expenses it may incur during a rate case cycle.318 SCE is required to forecast what it projects to be a reasonable expense. To the extent the forecast is high, SCE can be confident it will recover on its capital expenditures and benefit its shareholders; to the extent the forecast is low, SCE’s recovery may be deferred for review of the next test year. We have said before, Ratemaking is not, nor has it ever been, an exact science that guarantees perfect results from all perspectives. Ratemaking, whether in a general rate proceeding or by an attrition mechanism, is essentially the art of estimating future events based on judgment 316 SCE Reply Brief, at 75. 317 SCE-25, Vol. 3, at 3-4. 318 D.96-12-066, 69 CPUC2d 691, at 695. - 142 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 that is as fully informed as possible. We know in prospective test year ratemaking that our adopted estimates of revenues and expenses may be at variance with actual hindsight experience. But we do not view this as a problem, because we are extending to utility management an opportunity and incentive to find ways to conduct operations for less than projected. When it can do this it flows the benefit to the utility's bottom line, which means profit. In the short term, between general rate proceedings, the shareholders benefit when the company's management can 'do it for less,' and correspondingly, ratepayers ultimately benefit because the productivity improvement will be reflected periodically when there is a comprehensive review of the utility's revenue requirement. Keeping this incentive for utility management is a cornerstone of ratemaking, which leads us to look askance at proposals for immediate 'give backs' of all cost savings to ratepayers. If ratemaking ever becomes so conceptually upside down that utility management loses the economic incentive to exercise its business acumen, California will be in a sad posture and will suffer under utility management which is lethargic with a 'cost plus' mentality. Accordingly, we are not as concerned as some parties are about having ratemaking that is always perfect from the hindsight perspective. Rather, we will continue our practice of adopting sound, informed estimates with the hope that utility management accepts the challenge and can somehow 'do-it-for-less’.319 We see no benefit to the ratepayers in this instance of carving exceptions and creating ratemaking policy which is only applicable to software projects. We do not allow SCE’s request for 2017 of $24.75 million and $23.86 million for 2018 software contingencies. These reductions are reflected on a project basis in Table I of Appendix B to this decision. Consistent with ratemaking policy, disallowing these contingencies should motivate SCE to remain within its 319 D.85-03-042, 17 CPUC2d 246, at 254. - 143 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 forecast budgets for these projects. If additional funds become necessary, SCE may seek to establish that necessity in the next GRC. 6.2.2. Cybersecurity and Compliance SCE recorded $22.590 million for 2016 Cybersecurity and Compliance capitalized software (not including Grid Modernization Cybersecurity).320 These cybersecurity and compliance projects include: (1) Perimeter Defense, (2) Interior Defense, (3) Data Protection, (4) SCADA [Supervisory Control and Data Acquisition Cybersecurity, (5) Common Cybersecurity Services for Generator Interconnection, and (6) NERC CIP [North American Electric Reliability Corporation Critical Infrastructure Protection] Compliance for IT.321 SCE forecast, including contingencies, $42.170 million for 2016, $52.570 million for 2017, and $48.440 million for 2018. ORA proposed and SCE agrees to use the 2016 recorded expense of $22.590 million.322 ORA did not oppose the forecasts for 2017 and 2018 (excepting contingencies discussed above). Therefore, we adopt as reasonable and exclusive of contingencies, $22.590 million for 2016, $52.003 million for 2017, and $47.457 million for 2018.323 TURN recommends cybersecurity capital expenses be booked to a memorandum account and we establish a process to obtain information sufficient to review SCE’s expenditures.324 SCE argues, in response, that their showing is adequate, but that due to the importance of cybersecurity, a separate 320 SCE-20, Vol. 01, at 34, Table III-12. 321 SCE-20, Vol. 01, at 33, Table III-11 and at 34, Table III-12. 322 SCE Opening Brief, at 125.  323 See, SCE-20, Vol. 1, at C-29. 324 TURN-09, at 2-10. - 144 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 proceeding could provide a forum so that interested parties may have the opportunity to address how cyber-related information is shared during a GRC. We agree with SCE that their showing is adequate and a memorandum account is not needed. We also agree further review of how to address cyber-related information would be appropriate in another forum. 6.2.3. Grid Modernization Cybersecurity SCE forecast $5.250 million for 2016, $16.050 million for 2017, and $24.230 million for 2018. Recorded expenses in 2016 were $2.901 million.325 SCE argues at least 40-50% of its request must be authorized now, no matter how the Commission decides grid modernization issues generally.326 SCE has established the need for at least a portion of the proposed investment. We adopt the 2016 recorded expense of $2.901 million and authorize 40% of the forecasted expenses (less contingencies) for 2017 and 2018, $5.35 million and $8.076 million, respectively. 6.2.4. 6.2.4.1. Other Capitalized Software Vegetation Management Project In the 2015 GRC, the Commission authorized $9.7 million for SCE’s Vegetation Management Software project for 2014-2016.327 This project is intended to replace paper intensive management of 1.5 million trees and 600,000 to 700,000 annual tree trim records with a digitized map based system.328 Despite authorization in the last GRC, SCE revised its implementation approach. This 325 SCE-20, Vol. 01, at 43, Table III-13. 326 SCE Opening Brief, at 132. 327 SCE-04, Vol. 2, at 95, Table V-29. 328 SCE-04, Vol. 2, at 96:4-20. - 145 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 revision resulted in a reduced forecast of $2.0 million for 2016 and $5.7 million for 2017. SCE recorded $916,000 for 2016.329 The delay in implementation has resulted in a significant reduction in the proposed expense.330 We adopt the recorded expense for 2016 of $916,000 and the forecast (less contingency) for 2017 of $4.75 million for the Vegetation Management Project. 6.2.4.2. Comprehensive Situational Awareness for Transmission Comprehensive Situational Awareness for Transmission (CSAT) was known as Advanced Phasor Data Analytics when approved by D.15-11-021. The program is intended to provide Grid Control Operators the ability to assess the status of the entire transmission system at a glance and provide quick access to detailed data and robust analytics to make more informed decisions during critical operational periods.331 Although the Commission authorized $13.1 million for 2014-2016, the project was delayed and none of the authorized funding was used.332 SCE states the delay was necessary to ensure extended deployment and stabilization of the Phasor project which provides the wide area situational awareness data needed to make CSAT functional.333 The importance of real-time situational awareness is not questioned. ORA’s opposition to the project is only that funding was authorized in the 2015 GRC, none of the authorized funding was spent, and now SCE seeks $22 million 329 SCE-20, Vol. 01, at 52, Table III-14. 330 SCE-20, Vol. 01, at 53:3-21. 331 SCE-04, Vol. 2, at 111:1-4. 332 Ibid., at 110, Table V-36; SCE-20, Vol. 01, at 55, Table III-15. 333 SCE-04, Vol. 2, at 111:5-11. - 146 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 for 2017-2020 (an increase of $8.9 million from the original request) for the same project.334 ORA raises reasonable questions, but the delay in the project and the increased scope and forecast are not sufficient to controvert SCE’s showing in support of the project. SCE’s lack of transparency for how the previously approved funding was spent, however, does lead us to find the revised forecast is not fair and reasonable for ratepayers. Therefore, we approve only the additional $8.9 million (less contingency), but not the entire request of $22 million, and adopt $0 for 2016, $0.476 million for 2017, $0.951 million for 2018, $3.236 million for 2019, and $3.236 million for 2020. 6.2.4.3. Grid Planning & Analytics Software These projects consist of the Grid Interconnection Processing Tool (GIPT), Grid Analytics Application (GAA), Long-Term Planning Tools (LTPT), and Grid Connectivity Model (GCM).335 Each of these projects will aid SCE, it states, in planning and operation of the grid. SCE forecast $8.062 million for 2016 and recorded $9.371 million. It requests a total of $48.3 million going forward, which consists of $30.7 million for 2017 and $17.6 million for 2018.336 ORA suggests SCE should wait for open DER (Distributed Energy Resource) proceedings to conclude before implementing these projects. Although DER proceedings may provide guidance, it is during the GRC that SCE must demonstrate its proposed investments are reasonable and necessary. We find SCE has demonstrated a need for these various grid planning and operating 334 ORA-13, at 33-34. See, SCE-04, Vol. 2, at110, Table V-36. 335 SCE-20, Vol. 1, at 57-59. 336 SCE-20, Vol. 01, at 59, Table III-16. - 147 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 tools, but the question remains as to whether SCE has demonstrated that it needs these tools now. SEIA/Vote Solar are persuasive. SCE’s forecast of residential PV growth is significantly higher than what may be expected for the forecast period and it has underestimated the positive and exaggerated the negative impacts of DER resulting in unnecessary proposed capital expenditures, overstated need, and proposed grid modernization that is costly and fails to deliver net benefits.337 SEIA/Vote Solar however, have not established the link between these deficiencies and a lack of need for any of the Grid Planning & Analytics Software at issue here. Therefore, we find SCE has established some of these investments are reasonable and necessary but reduce the amount authorized based on SEIA/Vote Solar’s showing. We accept the recorded expense for 2016 for these projects of $9.371 million, and authorize 50% of SCE’s request (the forecast less contingencies), $12.796 million for 2017 and $7.332 million for 2018.338 6.2.4.4. Enterprise Content Management Project SCE requests $3.400 million for 2017 and $5.200 million for 2018 for the Enterprise Content Management (ECM) project. The project, SCE states, will implement a set of eight solutions: (1) Digital Signatures, (2) Centralization of Critical Records, (3) Records Management Enhancements, (4) Management of Email Records, (5) Automate Records Management, (6) Preserve Digital Records with Extended Retention, (7) Enterprise Search and (8) Manage Structured Data 337 SEIA/Vote Solar–01, at 6:17-26. 338 See, SCE-20, Vol. 1, at C-29. - 148 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Lifecycle, thereby “improving SCE’s capabilities to manage a diverse and complex set of business records.”339 ORA questions the need for this project and the overlap with the previously new system of Electronic Document Management Records Management (eDMRM). SCE has established the distinctions between ECM and eDMRM and that the ECM project is reasonable and necessary. We authorize the requests (the forecast less contingencies) of $2.833 million for 2017 and $4.333 million for 2018. 6.2.5. Operating System Software SCE was authorized $15.67 million for Operating System Software for 2015. It spent $29.93 million, $14.27 million more than authorized.340 SCE reports the overspend occurred due to a need to upgrade database software and avoid increased O&M and hardware expenses which would have resulted from extending the life of its current system. We accept the expense. The projects included in this account are: Operating System Software, Database Platform Upgrade, Business Intelligence Tools Upgrade, Enterprise Integration Tools Upgrade, and Enterprise Platform Core Refresh. The forecast capital expenditure for this account for 2016 is $8.75 million, $14.55 million for 2017, and $21.50 million for 2018.341 ORA does not object to these forecasts. SCE recorded $42.973 million for the overall Operating System Software account during 2016.342 Despite a lack of acceptance by ORA of this recorded 339 SCE-04, Vol. 2, at 192-193. 340 SCE-04, Vol. 02, at 12, 1-6, Figure II-2. 341 SCE-04, Vol. 02 A2, at 6, Table II-2 [column totals]. 342 SCE-29, at 48, Issue title: SCE-002, ORA-SCE-TXB-108 Q2 Supplemental Revised. - 149 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 expense,343 SCE acquiesced to the use of “all” its 2016 recorded IT capital expenditures.344 Although SCE provided testimony supporting spending $14.27 million more than authorized during 2015 for Operating System Software,345 it provided no explanation for spending $34.223 million more than forecast in this same account during 2016. We cannot accept this overspend based solely on an argument by SCE against “cherry-picking.”346 We accept the forecast capital expenditure for this account for 2016 of $8.75 million, and the forecast, less contingencies, of $13.113 million for 2017, and $19.80 million for 2018. 6.3. Information Technology – Customer Service Re-Platform SCE forecasts capital expenditures of $58.2 million for 2017 and $71.1 million for 2018 (and a total of $208.7 million from 2017 to 2020).347 SCE also forecasts Test Year 2018 O&M costs of $17.4 million to implement the CS Re-Platform.348 SCE’s total capital cost forecast includes $11.0 million for Program Complexities and $29.6 million for Delivery Contingencies. SCE makes the Program Complexities forecasts because “[w]e know [changes] will come, but we do not know when or the extent of impact on the project.”349 Similarly, a 343 ORA-13, at 28:1-3 and Table 13-14. 344 SCE Reply Brief at 77. 345 SCE-04, Vol. 02, at 12: 1-6 and Table II-2. 346 SCE Reply Brief at 77. 347 SCE-20, Vol. 2, at 2, Table I-1. 348 SCE-20, Vol. 2, at 9, (Table I-3). 349 SCE-4, Vol. 3, at 35:8-9. - 150 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Delivery Contingency is forecast because “there are many variables that cannot be predicted at the earliest stages of project planning that will affect project costs.”350 Despite acknowledging these variables and the impact they may have on forecasting costs, SCE has not similarly accounted for these variables in forecasting its schedule. SCE’s witness acknowledged the schedule may slip.351 Therefore and as discussed in section 6.2.1, above, concerning software projects generally, we find the projected O&M and capital forecasts and schedule to present numerous variables which call into question the reliability of SCE’s attempt to forecast either the costs, investments, or schedule. Similar criteria have been recognized for the establishment of a memorandum account in other proceedings. We have found a memorandum account may be warranted if the following factors are present: expenditures are caused by an event of an exceptional nature outside of the utility's control; not reasonably foreseen in the utility's last GRC; substantial in the amount of money involved; and, beneficial to the customers.352 SCE’s forecasted O&M and capital expenditures will be incurred due to the undertaking of an exceptional project. SCE’s request for a 24% contingency as well as contingencies relating to the capital expenditures establish that this project is outside of the utility’s control and the anticipated costs and timing cannot be reasonably foreseen. It is also established there is a substantial amount of money involved and the project is anticipated to be beneficial to customers. 350 Id. at at 35:13-15. 351 Webster, SCE, 8 RT at 890: 25 – 891: 16. 352 D.02-07-011 at 7. - 151 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Therefore, SCE shall establish a memorandum account to track these costs for review in the next GRC. For these same reasons and to avoid presenting an expense to ratepayers now for a project which may face changes and delays, we find it reasonable and proper for SCE to track its capital expenditures in the memorandum account as well. SCE projects $1.75 million in Customer Service O&M benefits related to CS Re-Platform process improvements and $3.63 million in IT O&M benefits. SCE contends these benefits should be removed from the forecast if the costs of the CS Re-Platform are removed to a memorandum account. SCE argues “[r]emoving these benefits is necessary to equitably account for SCE’s delayed cost recovery under ORA’s and TURN’s proposal.”353 We agree with SCE that the incremental benefits should be treated the same way as the incremental costs. Therefore, we require, in addition to tracking in a memorandum account the O&M and capital expenditures for CS Re-Platform, SCE shall track the corresponding benefits. 6.4. Information Technology – SCE’s Use of Managed Services Providers SBUA criticized SCE’s decision to transition to a new IT operating model involving the use of Managed Services Providers (MSPs) to provide day-to-day IT operations. SBUA argued that outsourcing these IT functions has had several harmful effects and that the Commission should require SCE to hire SCE employees or local businesses to provide IT service desk support before approving SCE’s request for this account.354 SBUA and SCE entered into a 353 SCE Opening Brief at 144. 354 SBUA, Michael Brown, at 35-37. - 152 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 stipulation resolving the issues between them during evidentiary hearings.355 SCE also explained in rebuttal testimony that SBUA’s criticisms were unfounded.356 No other party challenged SCE’s use of MSPs, and there is no evidence before the Commission that SCE’s use of MSPs has produced any harmful effects. The Commission approves SCE’s request for this account. 7. Generation SCE’s generation O&M expenses are, exclusive of Catalina, forecast for 2018 to be $186.364 million. These are expenses for SCE’s share of the Palo Verde Nuclear Generating Station and its own Energy Procurement, Hydropower, Peaker and other power generation, Solar Photovoltaic, and Fuel Cells. These expenses were not disputed.357 We find they are reasonable and approve them. ORA proposed using SCE’s recorded capital expenditures in place of forecasted expenditures for 2016 for SCE’s generation capital expenses. SCE has agreed with this recommendation. Except as noted below, we agree and adopt the 2016 recorded capital expenditures. 7.1. Generation – Nuclear Generation (Palo Verde) Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 355 SCE-SBUA-1; SCE-SBUA-2. 356 SCE-20, at 6-7. 357 SCE-21, at 13-14. - 153 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 7.2. Generation – Energy Procurement Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 7.3. Generation – Hydro Generation Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 7.4. 7.4.1. Generation – Catalina Catalina – O&M SCE’s Pebbly Beach Generating Station (PBGS) in Avalon on Santa Catalina Island provides electric service to the island’s permanent residents and visitors via a closed electric system relying on six diesel generators, twenty-three micro-turbines, and one battery.358 SCE’s 2018 forecast for O&M for this account is $4.374 million.359 ORA accepts this forecast. It is reasonable and we approve it. 7.4.2. Catalina- Pebbly beach Generating Station Automation SCE proposes for its PBGS Automation Project capital expenditures of $3.4 million for 2016 and $3.249 million for 2017. There are no additional forecast expenditures after 2017. Consistent with its other recommendations concerning generation capital expenses, ORA urges adoption of the recorded expense for 358 SCE-05, VOL. 5, Pt. 2, at 1:21-23. 359 SCE-05, VOL. 5, Pt. 2, at 2: Table I-1. - 154 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2016 of $3.386 million and does not oppose the forecast for 2017 of $3.249 million.360 TURN contends SCE should not be permitted to recover any additional funds for this project. In the last GRC we “largely” agreed with TURN and found that SCE was responsible for delay with the project and had not justified the project at the proposed level of expense. On that basis we approved $5.1 million in capital expenditures through 2013 and only allowed certain capital loadings through 2013, while denying any additional capital expenditures for 2014 and thereafter. At that time the proposed project expense totaled $9.261 million.361 SCE reports the project was initially estimated in 2007 to cost $2 million.362 By 2009, the cost was revised to $4.6 million and the scope expanded due to changes for Air Quality Management District compliance and other updates.363 By 2013, SCE had spent $5.1 million and reports that it had completed most physical installation of equipment and 90% of equipment purchases.364 SCE then put the “project on hold when we discovered drawing inconsistencies with existing field conditions.”365 Field surveys and verifications have resulted in over 6,000 drawing changes at an expense of $3.2 million from 360 ORA-14, at 34:3-6. 361 D.15-11-021 at 32-33; TURN-03, at 27. 362 SCE-05, Vol. 5, Pt. 2, at 8:6-8. 363 Id. at 8:8-11. 364 Id. at 8:12-17. 365 Id. at 8:18-19. - 155 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2015 through 2017.366 After a 2 ½ year break, the project was “restarted in 2015 under a fresh engineering management team. A new scope of the Distributed Control Systems (DCS) was added …”367 SCE now projects the project, at completion in 2017, would have a total cost of $17.196 million (nearly double the $9.261 million projection made in 2013, nearly four times the $4.6 million projection made in 2009, and nearly eight times the $2 million projection made in 2007). The current projection is based on $5.08 million recorded prior to 2013 and additional expenditures of $.074 million in 2014, $5.404 million in 2015, $3.386 million in 2016, and a forecast of $3.249 million for 2017.368 SCE has established the need for this project and the benefits of it, including eliminating obsolete technology, reducing the frequency, duration, and probability of outages, reducing complexity, improving efficiency and reduced diesel emission, and others.369 We recognize these are laudable goals and necessary accomplishments. We however, find that SCE’s application also establishes the project has suffered gross mismanagement, extensive delays, and significant cost overruns. SCE has correctly framed the discussion: “Whether a project should be included in rate base should be based on a determination of whether the facilities are used and useful, and whether the spending is warranted at the level forecast…”370 In these circumstances, although the spending may have resulted in used and useful facilities, we cannot agree that 366 SCE-21, at A-1. 367 SCE-05, Vol. 5, Pt. 2, at 8:21-24. 368 Id. at 14:1-4 and Figure II-3. 369 Id. at 7:16-8:2. 370 SCE-25, Vol. 3, at 8-9. - 156 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 the spending is warranted at the level it was forecast and is recorded and we do not allow it. We note TURN suggests recovery of $3.2 million for new drawings may be warranted. We recognize the drawings are necessary, and therefore consider them to be used and useful. No party contested whether the spending was warranted at the level forecast and recorded. SCE’s supporting testimony states, (2) Unavailability of As-built Documentation Another problem with the maintenance of equipment of this vintage is the need to draw and document system configuration accurately. About 4,600 station drawings reside on withering 70-year-old paper, upon which the hand-drawn information is fading and becoming illegible. Until the recent equipment upgrade projects, many have not been updated since their creation prior to SCE’s acquisition of the Catalina system six decades ago. This presented an immense challenge to the SCE design and construction team, and is one of the main drivers of the prolonged project and increased project cost over time. Additional field-verification, design modification, field change, as-build, and redrawing of these drawings using modern Computer Aided Design software were necessary for each system upgrade. Field verification and design is especially challenging throughout the entire process as workers have to constantly deal with energized equipment and wiring, and unknown field conditions. SCE is redrawing and updating approximately 900 drawings as part of the PBGS Automation project’s scope of work. This documentation cleanup effort will also lower design and construction contractor bidding prices and field change orders for future maintenance, which are high due to difficulty matching field conditions to hand drawn plans from the 1960s. Although this testimony supports a finding that the new drawings are used and useful and supports the significant expense required to create these new and updated drawings, whether or not the expense for these drawings is - 157 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 warranted is far less clear. SCE’s testimony establishes that after planning this project approximately a decade earlier, after making forecasts in multiple GRCs, and spending several million dollars, it was not until 2015 that SCE recognized the need to replace “4,600 station drawings resid[ing] on withering 70-year-old paper, upon which the hand-drawn information is fading and becoming illegible.” Although the expense may have been warranted if incurred in what would likely have been lesser amounts over time as earlier upgrades were made and equipment was maintained, SCE’s lack of care in maintaining usable plans will not be rewarded by approving this expense now. The costs for the PBGS Automation Project have not been established to be just and reasonable and therefore, we do not allow them. 7.4.3. Catalina – Other Capital Projects Under $3 Million SCE’s 2016-2018 forecast for all other capital projects on Catalina, under $3 million, is $7.1 million. These are various capital projects and include facility resurface paving, fence and gate replacements, air compressor replacements, PBGS plant seawall improvement, unit overhauls, and others. SCE’s forecast is $1.450 million for 2016, $3.2 million for 2017, and $2.450 million for 2018.371 ORA proposes the actual recorded expense of $.007 million be used for 2016 and that $0.448 million be adopted for 2017 and for 2018.372 The recommendation for 2017 and 2018 is based on using a five-year average of 2012-2016. 371 SCE-05, Vol. 5, Pt. 2, at 16, Figure II-4. 372 ORA-14, at 34. - 158 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE agrees to use the actual recorded expense for 2016.373 For 2017 and 2018, SCE proposes using a six-year average of 2011-2016, modified by removing costs of $1 million each for 2013 and 2014 associated with overhauling two diesel generator units (8 and 14) and adding the 2017 forecast expense for overhauling unit 15. This would result in a 2017 forecast of $2.207 million and $0.213 million for 2018.374 The use of averaging is consistent with Commission precedent, particularly when, as in this instance, the recorded costs fluctuate significantly (from $0.756 million in 2011 to $0.007 million in 2016). Modifying the average to account for capital intensive projects (the unit overhauls) would, however, be contrary to the purpose of averaging and SCE has not established this would improve the accuracy of its forecast. We rely on a forecast based on average recorded costs to account for historical fluctuations rather than trying to predict annual expenditures. Therefore, we find ORA’s recommendation is just and reasonable and adopt the 2016 actual recorded expense of $.007 million and the forecast of $0.448 million for each of the years 2017 and 2018. 7.5. Generation - Other 7.5.1. Mountainview Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 373 SCE-21, at 9. 374 SCE-21, at 10-12. - 159 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 7.5.2. Peakers Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 7.5.3. Mohave Closure Excepting ORA’s recommendation to use 2016 recorded capital expenditures, to which SCE agreed, no party disputed SCE’s O&M expenses or capital expenditures. We find they are reasonable and adopt them. 7.5.4. Solar Photovoltaic SCE owns and operates 25 solar generating plants with a total capacity of 67.5 MW (Alternating Current).375 SCE submits its 2013 and 2014 O&M expenses for reasonableness review in this GRC.376 SCE incurred $8.286 million for 2013 and $4.270 million for 2014.377 These expenses are not disputed and we find them reasonable and recoverable. SCE’s 2018 O&M forecast for Account 549 (labor and other expenses) is $1.510 million378 and $2.332 million in Account 550 (rent).379 SCE’s 2016-2020 capital forecast is $1.480 million based on a forecast of $0.680 million for 2016 and $0.2 million annually for 2017-2020. Excepting ORA’s recommendation to use 2016 recorded capital expenditures, no party disputed SCE’s O&M expenses or capital expenditures. 375 SCE-05, Vol. 5, Pt. 1, at 1. 376 D.09-06-049, at 57, Conclusions of Law 9 and 12. 377 SCE-05, Vol. 5, Pt. 1, at 19:8-10 and Figure VI-8. 378 SCE-05, Vol. 5, Pt. 1, at 13. 379 SCE-05, Vol. 5, Pt. 1, at 16. - 160 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We find they are reasonable and adopt SCE’s 2018 O&M forecast of $2.842 million and its 2016 recorded capital expenditure of $0.004 million and its forecasts of $0.2 million each for 2017 and 2018. 7.5.5. Fuel Cells SCE’s O&M forecast for its fuel cell program is $0.379 million. SCE did not make a capital request for this program. This amount was not disputed by any party. We find it is reasonable and adopt it. 8. Human Resources SCE’s human resources-related O&M forecast covers the costs of hiring, retaining, and managing SCE’s workforce. This includes the administrative costs of the human resources function, plus the costs of benefits and other non-base pay compensation for SCE employees across the utility. SCE presents its Human Resources (HR) testimony in three volumes:  Volume 1 presents SCE’s Test Year 2018 O&M forecast for its Human Resources Operating Unit, which includes salaries and a short-term incentive program for executive officers.  Volume 2 presents SCE’s Test Year 2018 forecast for its total compensation programs, other than base pay. Those programs include short-term incentives for non-officer executives, long-term incentives for executives, employee recognition awards, and other benefits such as pensions and health insurance.  Volume 3 presents SCE’s Total Compensation Study (TCS) As shown in the table below, SCE’s total forecasted HR O&M expenses for Test Year 2018 equal $582.370 million. - 161 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Human Resources Test Year 2018 O&M Forecast380 Constant 2015 $000 and Nominal $000 Activity 2018 Human Resources Department and Executive Officers 64,950 Benefits and Other Compensation381 517,420 Total 582,370 We note at the outset that we review SCE’s HR request in the context of several legislative developments that occurred after SCE filed this application. First, in October 2015 Assembly Bill (AB) 1266 became law and added Section 706 to the Public Utilities Code.382 Pub. Util. Code § 706(b) provides as follows: For a five-year period following a triggering event, no electrical corporation or gas corporation shall recover expenses for excess compensation from ratepayers unless the utility complies with the requirements of this section and obtains the approval of the commission pursuant to this section.383 380 SCE-22, at 1, Table I-1 (Human Resources/Executive Officers, O&M Forecast by FERC Account) and SCE-22, at 8, Table II-3 (Benefits and Other Compensation, Forecast by FERC Account). Activity 926 forecasts are presented in nominal $000 dollars. All other activity forecasts are presented in constant 2015 $000 dollars. 381 This benefits and other compensation amount is from SCE's June 2017 rebuttal testimony (SCE-22). Subsequent to rebuttal testimony, in December 2017 (SCE-59, at 32-35), SCE updated the forecasts for certain elements of benefits, including an accounting change. 382 Stats. 2015, ch. 599. 383 The terms in this Section are defined as follows: Pub. Util. Code § 706(a)(2) provides: “A ‘triggering event’ occurs if, after January 1, 2013, an electric corporation or gas corporation violates a federal or state safety regulation with respect to the plant and facility of Footnote continued on next page - 162 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Pub. Util. Code § 706(f) mandates that in every decision on a general rate case, [the Commission] shall require all authorized executive compensation to be placed in a balancing account, memorandum account, or other appropriate mechanism so that this section can be implemented without violating any prohibition on retroactive ratemaking. The Legislature directed the Commission to implement these provisions in GRC proceedings such as this one. However, we issued our decision in SCE’s 2015 GRC in November 2015, which left insufficient time to implement the legislation. Instead, SCE proposed in the instant application to establish a “SCE Officer Compensation Memorandum Account” (SOCMA) to track the amounts authorized by the Commission in SCE’s 2018 GRC decision over the GRC period related to all officer compensation including annual salary, bonus, benefits, or other consideration of any value. During the pendency of this proceeding, the requirements adopted in AB 1266 have already been superseded by legislation passed in 2018, Senate Bill (SB) 901.384 SB 901 repeals the language in Public Utilities Code § 706, and adds new language prohibiting an electrical or gas corporation from recovering from ratepayers any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of the electrical corporation or gas corporation, and the utility and, as a proximate cause of that violation, ratepayers incur a financial responsibility in excess of five million dollars ($5,000,000).” Pub. Util. Code § 706(a)(1) provides: “‘Excess compensation’ means any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of an electrical corporation or gas corporation that is in excess of one million dollars ($1,000,000).” 384 Stats. 2018, ch. 626. - 163 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 requires that compensation instead be funded solely by shareholders of the utility. Revised § 706 states: (a) For purposes of this section, “compensation” means any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of an electrical corporation or gas corporation. (b) An electrical corporation or gas corporation shall not recover expenses for compensation from ratepayers. Compensation shall be paid solely by shareholders of the electrical corporation or gas corporation. The Commission implemented these requirements in Resolution E-4963.385 This Resolution ordered affected utilities, including SCE, to establish “Officer Compensation Memorandum Accounts” (OCMA) with an effective date of January 1, 2019. SCE complied by filing Advice Letter (AL) 3927-E, which was approved by the Commission’s Energy Division on January 29, 2019. The OCMA established by SCE includes SCE’s description of the disposition and review procedures for the account: “SCE anticipates that the officer compensation amounts authorized by the Commission in the 2018 GRC decision, for 2019, will be refunded to customers when SCE implements the 2019 Post-Test Year revenue requirement in rates either on a stand-alone basis or through its first consolidated revenue requirement and rate change advice letter submitted in 2019.”386 385 Resolution E-4963, December 13, 2018. Commission Resolution to Establish Memorandum Accounts to Track Compensation Paid to an Officer of an Electrical or Gas Corporation Pursuant to SB 901. 386 Revised Cal. PUC Sheet No. 65678-E, Section N.20.c. (OCMA), Disposition and Review Procedures). - 164 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Our review of the legislative events recounted above and our review of the OCMA section of SCE’s Preliminary Statement confirms that only the Test Year 2018 officer compensation amounts adopted in this decision shall be collected from SCE’s ratepayers, and not the 2019 and 2020 compensation. This decision implements the provisions of SB 901 as follows: (1) we have removed the funding for 2019 and 2020 revenue requirements that would otherwise collect from ratepayers “salaries, bonuses, benefits, and all other consideration of any value paid to officers;” and (2) consistent with the disposition and review procedures described by SCE in its Preliminary Statement, we have included an Ordering Paragraph directing SCE to refund to customers any amounts tracked in the OCMA, as part of SCE’s revenue requirement and rate change advice letter implementing this decision. 8.1. Human Resources Department and Executive Officers The first portion of SCE’s Test Year 2018 forecast is for $64.950 million for administrative and general (A&G) expenses to support its HR department and for certain costs related to executive officers, primarily SCE’s Executive Incentive Compensation (EIC) Plan. The table below presents the details of SCE’s request. - 165 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Human Resources and Executive Officers – Combined Summary of 2018 Forecast (Constant 2015 $000) FERC ACCOUNT 920/921 923 926 920/921 923 8.1.1. ACTIVITY Human Resources A&G Salaries / Office Supplies and Expenses Human Resources Outside Services Employed Human Resources Employees (Pensions and Benefits-related) Salaries / Office Supplies and Expenses Subtotal: Human Resources Operating Unit Executive Officers A&G Salaries / Office Supplies and Expenses Executive Officers Outside Services Employed Subtotal: Executive Officers Total O&M Expense 2018 31,729 6,954 5,109 43,792 19,611 1,547 21,158 64,950 Human Resources Operating Unit For Test Year 2018, SCE forecasts $43.792 million of expenses for the Human Resources Operating Unit (HR Department) in FERC accounts 920, 921, 923 and 926. The HR Department consists of four groups: (1) Talent Solutions; (2) Business Partners; (3) Total Rewards & Services; and (4) Strategy & Workforce Insights. No parties contested the reasonableness of SCE's forecast for HR Department O&M expenses, and we approve SCE’s Test Year 2018 forecast of $43.792 million, as summarized in the table above. 8.1.2. Executive Officers For Test Year 2018, SCE forecasts $21.158 million for executive officer cash compensation (salaries and short-term incentives), non-labor expenses, and outside services. SCE's forecast is based on the five-year average of recorded costs from 2011 to 2015. As shown in the table below, most of the forecast costs consist of funds for the executive officer portion of the EIC Plan, which is included in FERC Account 920 (other non-officer executive EIC costs are - 166 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 included in SCE’s Short-term Incentive Program (STIP), which we discuss below). Executive Officers Salaries and Short-term Incentives Summary of 2018 Forecast (Constant 2015 $000) FERC ACTIVITY ACCOUNT Executive Officers A&G Salaries/EIC Plan 920 Office Supplies and Expenses 921 Executive Officers Outside Services Employed 923 Subtotal: Executive Officers 2018 17,222 2,389 1,547 21,158 SCE describes its EIC Plan as “part of the market-competitive total compensation package for SCE’s executive workforce.”387 Payouts are based on SCE’s annually-determined performance goals, which are the same as the goals for the STIP. Individual executives’ performance ratings vis-a-vis these goals are determined at the end of the year, with each executive’s “target bonus” subject to modification by the officer to whom that executive reports, as well as at the corporate level by the Chief Executive Officer of Edison International. TURN makes two recommendations to reduce the Test Year 2018 EIC forecast. First, TURN recommends that the Commission base SCE's forecast on a five-year average of target incentive levels, rather than the historically higher actual payouts. This reduces the test year labor forecast by $0.979 million. Second, TURN recommends that the Commission deny rate recovery of 40% of the resulting forecast, in order to remove the costs of incentives tied to "core 387 SCE-06, Vol. 2, at 29. - 167 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 earnings" and utility financial performance. This reduces the forecast by an additional $1.694 million, for a total reduction of $2.673 million.388 NDC recommends a $4.249 million reduction by calculating the average of SCE's 2013-2015 EIC expenses and then applying a 62.5% EIC goal-related reduction. In rebuttal, SCE contends that the level of EIC payouts fluctuates significantly from year to year due to the relatively small number of employees in the executive officer population and the varying performance levels on a year- to-year basis, and that its five-year averaging methodology followed Commission guidance to provide the most reasonable estimate of labor costs in the Test Year.389 In D.15-11-021 we reached a number of findings regarding SCE’s EIC payouts: We agree with SCE that financial performance may benefit ratepayers, however, the ratepayer benefit is much less direct than the shareholder benefit. Further, in some instances, financial performance may be achieved at the detriment of ratepayers. Accordingly, we adopt 40% of SCE’s EIC forecast for rate recovery and approve the non-EIC portions of SCE’s executive compensation request.390 We also suggested that “if SCE seeks rate recovery of higher portions of the EIC in its next GRC, it should provide substantially more evidence that the 388 SCE-22 at 2, Table I-2 (Executive Officers – FERC Account 920/921, Recorded 2011-2015/2018 Forecast, Summary of SCE, ORA, TURN and NDC Positions, Constant 2015 $000) and SCE-29 at 308. 389 SCE Opening Brief at 152, citing D.89-12-057, 34 CPUC2d 199. 390 D.15-11-021 at 261, and Findings of Fact 337-339. - 168 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 EIC awards incent executives to achieve ratepayer benefits.”391 In the instant proceeding, SCE included testimony asserting that EIC awards will lead to customer benefits, because 60% of the performance metrics relate to results such as operating in a safe and reliable manner and improved customer satisfaction (the other metric, accounting for 40% of results, is tied to whether SCE meets its Core Earnings Target for the year). SCE’s additional testimony, while informative, is not evidence that the EIC awards incent executives to achieve ratepayer benefits. We remain unconvinced that ratepayers should fund 100% of SCE’s EIC program. To calculate this adjustment to our adopted revenue requirement, we begin with TURN’s recommended starting point for SCE's forecast, the five-year average of target incentive levels, rather than actual payouts. This value is $4.235 million.392 It would be illogical to base our forecast on SCE’s recorded above-target payouts, as this ignores the very fact that the payouts were more than we authorized. We then subtract 40% of TURN’s forecast, or $1.694 million, from that amount. As shown in the table below our authorized amount for FERC Account 920, Executive Officers A&G Salaries, in Test Year 2018 is $14.549 million. 8.1.3. Adopted Forecasts for SCE’s Human Resources Department and Executive Officers The table below summarizes our adopted forecasts for SCE’s HR Department and Executive Officers: 391 Id., at 261. 392 TURN-01, at 16. - 169 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Human Resources and Executive Officers – Combined Adopted 2018 Forecast (Constant 2015 $000) FERC Account 920/921 923 926 920 921 923 8.2. Activity Requested Human Resources A&G Salaries / Office Supplies and Expenses Human Resources Outside Services Employed Human Resources Employees (Pensions and Benefits-related) Salaries / Office Supplies and Expenses Subtotal: Human Resources Operating Unit Executive Officers A&G Salaries / Office Supplies and Expenses Executive Officers Outside Services Employed Subtotal: Executive Officers Total O&M Expense Authorized Variance 31,729 31,729 0 6,954 6,954 0 5,109 5,109 0 43,792 43,792 0 17,222 2,389 14,549 2,389 (2,673) 0 1,547 1,547 0 21,158 64,950 18,485 62,277 (2,673) (2,673) Benefits and Other Compensation The second portion of SCE’s Test Year 2018 forecast is for $517.420 million for Benefits and Other Compensation.393 As noted earlier, SCE’s total compensation program comprises base pay, short-term incentives, long-term incentives, recognition awards, and benefits. We addressed base pay for SCE’s executive officers in the preceding section of this decision. Base pay for non-officer executives is included in SCE’s testimony regarding the respective Operating Units of those executives. The remainder of this section, therefore, addresses SCE’s forecast for all other benefits and compensation programs. SCE states in testimony that its compensation programs “target the market median and reward employees for individual, Operating Unit and Company 393 This amount for benefits and other compensation is from SCE's June 2017 rebuttal testimony (SCE-22). Subsequent to rebuttal testimony, in December 2017 (SCE-59, at 32-35), SCE updated the forecasts for certain elements of benefits, including an accounting change. - 170 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 performance. To attract and retain the workforce essential to the Company’s operations, SCE offers a market-competitive compensation package.”394 The table below presents the details of SCE’s request. Benefits and Other Compensation – Combined395 Summary of 2018 Forecast (Constant 2015 $000 and Nominal $000) FERC Account 920/921, 905, 500, 588 920/921 926 926 926 926 926 926 926 926 926 926 Activity Short-term Incentive Program 2018 132,905 Long-term Incentives 13,726 Pension Costs 97,474 401(k) Savings Plan 79,190 Medical Programs 110,719 Dental Plans 15,035 Vision Service Plan 3,443 Post-Retirement Benefits Other Than Pensions (PBOP) Costs 36,823 Group Life Insurance 1,426 Miscellaneous Benefit Programs 5,592 Executive Benefits 21,087 Third Party Billing & Non-Utility Affiliates P&B Credits 0 Total O&M Expenses 517,420 Specific items within SCE’s requests are opposed by ORA and TURN. ORA, having reviewed the entirety of SCE’s request, noted in testimony that it does not oppose SCE’s Test Year 2018 forecasts for the following programs:396  Pension Costs 394 SCE-06, Vol. 2, at 1. 395 SCE-06, Vol. 2A2, at 3, Table I-1 (Benefits and Other Compensation – Combined, Summary of 2018 Forecast). 396 ORA-15, at 17. - 171 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2  401(k) Savings Plan  Dental Plans  Vision Service Plan  Post-Retirement Benefits Other Than Pensions (PBOP) Costs  Group Life Insurance  Miscellaneous Benefit Programs (with the exception of Recognition Programs) We address parties’ recommendations on the remaining contested items in the following sections. 8.2.1. Short-Term Incentive Program SCE states that its Short-term Incentive Program (STIP) is the company’s “annual variable pay program that provides employees an opportunity to earn a cash bonus based on achieving Company goals”397 related to public and workplace safety, customer service, system reliability, cost control, and productivity.398 The STIP bonuses were historically awarded with respect to goals and budgets of the overall company and each individual Operating Unit. In 2015 SCE modified the basis for STIP funding to include a company-wide safety goal based upon a “Days Away, Restrictions and Transfers” (DART) injury rate target, with a no fatalities requirement. Initially, this metric was tied to 10% of STIP funding. In 2016, SCE revised the STIP again to remove any Operating Unit-specific goal component from the payout calculation. SCE states that this 397 SCE-06, Vol. 2, at 23. 398 Ibid. - 172 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 aligned the STIP and the EIC by using the same set of measurable performance goals. The current goals for STIP (and for EIC) are provided in the table below, along with the respective weights assigned to each goal (totaling 100, or 100%): - 173 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Company Goals Included in STIP 2016 Plan Year399 Strategic Focus Area Goal Category Safety Safety & Compliance Goals  Employee, Worker and Public Safety  Compliance (No significant non-compliance events) Target 10  Improve customer satisfaction through improving ranking in J.D. Power Customer Satisfaction Survey  Achieve Grid Reliability three-year rolling average targets for SAIDI, SAIFI and MAIFI Customer Relationship/ Operational & Service Excellence Operational & Service Excellence  Protect critical infrastructure that supports SCE’s ability to safely and effectively serve customer needs and protects customer information 20  Control costs in support of affordable customer rates  Achieve capital spending target that supports safe, reliable and affordable infrastructure and also lays the groundwork for a modernized grid that enables customer technology choices  Achieve Diverse Business Enterprise (DBE) Spend greater than/equal to 40% Grid of the Future High Performance Organization Affordability Strategic Initiatives People and Culture  Advance SCE’s Grid Modernization effort in order to support customer choices regarding technology and the manner in which they interact with the grid 20  Advance key regulatory proceedings that support customer rates and the safe and cost-effective retirement of SONGS  Diversify our leadership pipeline including the representation of historically under-represented groups to further broaden our perspectives and better reflect our customers’ viewpoints  Advance a High Performance Organization by enhancing the decision-making process and encouraging employee engagement Financial  Achieve Core Earnings target Performance Total 10 40 100 SCE forecasts $132.905 million of expenses for the STIP for Test Year 2018.400 SCE states STIP costs are driven by a combination of factors, including 399 SCE-06, Vol. 2A2, at 22. 400 SCE-22, at 9, Table II-4 (Short-term Incentives (STIP)). - 174 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 the number of eligible employees, target award levels, labor expense, and Company performance. SCE prepared its 2018 forecast using an “itemized forecast” methodology, starting with 2015 recorded costs, then escalating that value to adjust for various factors intended to reflect the current composition of SCE’s labor force.401 ORA recommends $70.672 million for the STIP in the 2018 Test Year, a reduction of $62.233 million. First, ORA recommends full funding for the portions of the STIP that ORA views as directly tied to goals that benefit ratepayers (i.e., safety, customer relationships and operational excellence, and “Grid of the Future”). Second, ORA recommends equal sharing between shareholders and ratepayers of the funding related to “High Performance Organization,” because ORA finds that some of these goals either do not clearly provide ratepayer benefits or do not appear to be transparent or readily quantifiable. Finally, ORA recommends no ratepayer funding for the portion of the STIP related to financial goals, contending that these incentives are clearly shareholder-oriented.402 TURN recommends $57.592 million for the STIP in the 2018 Test Year, a reduction of $75.313 million. First, TURN adjusts SCE’s forecast of total STIP spending to equal 12.11% of labor expense, rather than the 15.97% SCE proposes (TURN’s recommendation is the same ratio authorized by the Commission in the 2015 GRC decision). This reduces SCE’s forecast by $37.861 million. Second, TURN joins ORA in recommending no ratepayer funding for 40% of the 401 SCE-06, Vol. 2, at 28. 402 ORA-15, at 10. - 175 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 resulting forecast, in order to remove the costs of incentives tied to “core earnings” and utility financial performance. This reduces SCE’s forecast by an additional $38.395 million, to the level of $57.592 million recommended by TURN.403 In its rebuttal testimony, SCE faults ORA and TURN for their failure to properly acknowledge the results of the 2018 TCS.404 SCE notes that the Commission has directed SCE to submit the TCS and has relied upon these studies in past GRCs to show how SCE's workforce compensation compares to the market. SCE further notes that SCE's variable pay programs (including STIP and long-term incentives) are all included in the 2018 TCS, and the TCS results show SCE's total compensation is 1.9% below market. Based on these TCS results, SCE concludes that its STIP forecast should be adopted in full. In our decision on the STIP in SCE’s 2015 GRC application, we noted that in recent GRCs for all utilities we adopted reductions to short term incentives to account for payouts that are driven by shareholder benefits rather than ratepayer benefits. We found that “significant portions of the payout criteria are directly related to shareholder benefits,” including achieving decisions in Commission proceedings (GRC, cost of capital) with outcomes or adopted policies that may or may not provide secondary benefits to ratepayers.405 We also found that although SCE bears the burden of proving that incentive programs are a 403 TURN-01, at 10-12. 404 SBUA served testimony critical of SCE's STIP (see SBUA-02 at 46-47) and SCE submitted rebuttal testimony addressing SBUA's recommendations (see SCE-22 at 11-12). However, SBUA and SCE entered into stipulations resolving the issues between them during the evidentiary hearings (see Exhibits SCE-SBUA-1 and SCE-SBUA-2). 405 D.15-11-021 at 264. - 176 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 reasonable cost-of-service, it had not demonstrated that costs related to these criteria are reasonable.406 Nevertheless, we also stated that we do place weight on the results of the TCS, and we declined to adopt what we described as “deep cuts proposed by TURN and ORA.” Our decision adopted a STIP forecast based on labor factors consistent with ORA and TURN recommendations, as well as an overall reduction of 10% “to account for STIP payout criteria that are not appropriate to charge to ratepayers.” Turning to the instant proceeding, TURN observes in its opening brief that the Commission acted somewhat inconsistently in the 2015 GRC decision: “it is not clear to TURN why the Commission only adopted a 10% reduction for the authorized STIP amount in the 2015 GRC based on the financial performance metric, given the recognition in the same decision that a 40% reduction was warranted for the Executive Incentive Compensation associated with the same financial performance metric.”407 We remedy that inconsistency in this decision: we adopt a forecast equal to $57.592 million408 using TURN’s recommended methodology to calculate that level of Test Year 2018 STIP expenses. We agree with TURN’s use of the same ratio of total STIP spending to labor expense (12.11%) as we adopted in D.15-11-021. We also agree that 40% of the resulting value should be removed from SCE’s 2018 STIP expenses in order to remove the costs of incentives tied to "core earnings" and utility financial performance. 406 Id., at 264-265. 407 TURN Opening Brief at 172. 408 This adopted amount is illustrative and may not match the final amount because it is dependent on the number of employees/labor expenses approved by this decision. - 177 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 8.2.2. Long-Term Incentives SCE describes its Long-Term Incentives (LTI) program as “an integral part of the total compensation package for executives, […] provided in the form of non-qualified stock options, restricted stock units, and performance shares.”409 SCE states that the LTI target for each executive is determined based upon the market data applicable for that executive’s position, and is targeted at the market median.410 SCE forecasts expenses of $13.73 million for LTI compensation costs in Test Year 2018.411 SCE prepared its forecast using the same itemized forecast methodology it used with the STIP, by starting with recorded costs, then escalating that value to adjust for various factors intended to reflect the current composition of SCE’s executive population.412 In presenting its forecast, SCE also “acknowledges that the Commission has not viewed with favor past requests for rate recovery of its LTI program and has admonished SCE for continuing to do so.”413 SCE states that it “has buttressed its showing to reinforce the benefits to customers of funding this essential component of the total market-based compensation package for SCE’s leadership team.”414 409 SCE-06, Vol. 2, at 34. 410 Ibid. 411 SCE-22, at 16, Table II-5 (Long-term Incentives). 412 SCE-06, Vol. 2, at 37. 413 Id., at 33. 414 Id., at 33. - 178 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA, TURN, NDC and SBUA all recommend that the Commission continue its practice of denying ratepayer funding for LTI. Each party contends that SCE has offered no material evidence that ratepayers benefit from the program. In rebuttal, SCE defends the LTI program on bases similar to its defense of the STIP, citing the results of the 2018 TCS and its conclusion that overall compensation (including LTI) is at market. The positions of both sides of this issue are essentially unchanged since SCE’s 2015 GRC. In our decision in that proceeding, we concluded that LTI does not align executives’ interests with ratepayer interests, and continued “our consistent practice” and denied SCE recovery for its LTI program. Our review of the record in the instant proceeding leads us to conclude that our approach should remain unchanged, and we again deny SCE recovery of its Test Year 2018 forecast LTI program expenses. 8.2.3. Recognition Programs SCE describes its recognition programs as “low-cost tools that reward individual and team achievement.” SCE has two recognition programs: Spot bonuses and Awards to Celebrate Excellence (ACE). Spot bonuses are cash awards for achievements such as promoting safety or leading programs that improve efficiency. ACE is a points-based program for participants in safety efforts. SCE requests approval of its 2018 forecast of $1.456 million for Recognition Program expenses. In our decision on SCE’s 2015 GRC, we agreed with SCE that the types of behaviors (e.g., a focus on safety) that these programs reward do further the provision of safe and reliable service at just and reasonable rates, and that program costs appear reasonable relative to the benefits. However, we also - 179 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 noted that we shared ORA’s concern regarding the lack of transparency in SCE’s forecast. We declined to specifically authorize SCE’s request, and considered these programs in our review of individual Operating Unit budgets.415 We also directed SCE to “present a clear and coordinated showing on its forecast for these recognition programs in its next GRC direct testimony.”416 ORA served testimony opposing approval of SCE’s Test Year 2018 request, concisely demonstrating that SCE had again failed to provide the transparency needed to justify ratepayer funding of these programs.417 We have reviewed SCE’s direct testimony as well, and we also find that SCE failed to heed our direction. However, clearly in response to ORA’s critique of its direct showing, SCE did provide thorough support for its forecast in its rebuttal testimony. Based on our review of that information, we approve SCE request for $1.456 million in Test Year 2018 Recognition Program expenses. 8.2.4. Pension Costs SCE’s Retirement Plan provides eligible employees with income after their employment has ended. In its September 2016 application, SCE forecast $97.474 million for pension costs in the Test Year 2018 and $161.726 million and $162.895 million, respectively, for the 2019 and 2020 attrition years.418 415 D.15-11-021 at 267. We did not, as SCE suggests in its Opening Brief in this proceeding, “approve” SCE’s 2015 request (SCE Opening Brief at 161: “Other recent Commission decisions have also approved rate recovery of similar recognition programs offered by other utilities with short-term incentive programs.” Emphasis added.) 416 Ibid. 417 ORA-15, at 14-15. 418 SCE-22, at 44. - 180 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA supported SCE’s 2018 forecast in testimony, but recommended that the Commission deny SCE’s request for the 2019 and 2020 increases. Instead, ORA recommended authorization of the 2018 amount, $97.474 million, annually for 2019 and 2020 as well.419 ORA cited SCE’s testimony regarding upcoming Retirement Plan changes, which SCE stated will reduce the plan’s long-term cost structure. ORA also supported the continuation of the two-way Pensions Cost Balancing Account in order to protect both ratepayers and SCE from pension cost volatility. In rebuttal testimony, SCE states that while it “respectfully disagrees with ORA and maintains the material reduction in the pension plan’s cost structure will not be fully realized until years after the current GRC cycle” it accepts ORA’s proposal regarding 2019 and 2020.420 In December 2017, SCE updated its Test Year 2018 request to $57.741 million based on a three-year average of the updated Pension forecast costs for 2018, 2019, and 2020 of $57.0 million, $57.4 million, and $58.819 million, respectively.421 We approve SCE’s updated proposal and authorize an annual pension cost forecast equal to $57.741 million for 2018, 2019 and 2020. 8.2.5. Medical Programs SCE states that its medical program includes costs for the Company’s medical programs for active employees, as well as a Preventive Health Account, and an Employee Assistance Program. 419 ORA-21, at 11, citing ORA-15 for general support. 420 SCE-22, at 27. 421 SCE-59, at 33. - 181 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE forecasts $110.719 million for medical programs costs for Test Year 2018.422 SCE's forecast is based on applying escalation rates (0% for 2016, 7% for 2017, and 7% for the 2018 Test Year) to the 2015 recorded/adjusted costs. ORA's Test Year 2018 forecast is $101.478 million, $9.241 million less than SCE's forecast. Although ORA did not challenge SCE's forecast methodology, ORA uses a medical escalation rate of 4.58% in the Test Year 2018 (vs. SCE’s 7%). ORA also recommends using the same escalation rate for post-test year escalations.423 ORA relied upon three sources of healthcare cost statistics to calculate its recommended medical escalation rate: (1) the 2016 Milliman Medical Index; (2) the California Employer Health Benefits Survey; and (3) the Kaiser Family Foundation’s Medical Expenditure Panel Survey. ORA calculated the average of the three insurance premium rate increases cited in these three sources – 4.7%, 5.6%, and 3.45%, respectively – to arrive at a proposed medical escalation rate of 4.58%.424 In rebuttal, SCE faults ORA’s use of general survey data to determine SCE’s medical escalation rate. SCE states that its own estimates are based on cost increase projections that it requested directly from its medical plan carriers’ underwriters, with a trend rate lower than what its medical carriers projected. SCE emphasizes that these underwriters used data that is specific to SCE’s actual population demographics and the health conditions and plan utilization patterns of that population. 422 SCE-22, at 63. 423 ORA-21, at 11. 424 ORA-15, at 18-20. - 182 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 In our decision addressing medical escalation in SCE’s 2015 GRC, we stated that “we give significant weight to SCE’s reference to escalation rates provided by its plan administrators, and find this preferable to relying on a broader public study as proposed by ORA.” ORA has not demonstrated that a different approach is warranted in this proceeding, and we again adopt SCE’s forecast based on SCE’s escalation rate, $110.719 million for Test Year 2018. In future GRCs we will reconsider this approach if presented with evidence that SCE’s forecast resulted in a significant over- or under-collected balance in the Medical Programs Balancing Account. 8.2.6. Executive Benefits Program SCE states that its Executive Benefits Program offers a non-qualified Executive Retirement Plan that provides benefits to certain highly-paid management employees who are subject to federal compensation and contribution limits in the retirement plans which are offered to all other SCE employees.425 For the Test Year 2018, SCE forecasts Executive Benefits Program costs of $21.087 million.426 ORA recommends disallowing 50% of SCE's Test Year 2018 forecast for Executive Benefits based on past Commission precedent and ORA’s position in prior GRCs that ratepayers should not bear the full cost of these supplemental benefits, which are in excess of federal limits and which serve to further enhance benefits to already highly-compensated employees.427 425 ORA-15 at 20, citing SCE-06, Vol. 2, at 101. 426 SCE-22 at 32. 427 ORA-15, at 21. - 183 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 We continue to follow the precedent established in SCE’s 2009, 2012 and 2015 GRCs,428 and allow 50% rate recovery of SCE’s forecast. As we noted in D.15-11-021, these Executive Benefits are, in part, based on bonuses received by the executives. As discussed above, these bonuses may not be appropriate for rate recovery. Accordingly, benefits based on those bonuses are also not appropriate. We adopt ORA’s recommended amount for Executive Benefits, $10.135 million.429 8.2.7. Adopted Forecasts for Benefits and Other Compensation The table below summarizes our adopted forecasts for Benefits and Other Compensation: 428 D.12-11-051 at 476-477. 429 ORA’s forecast is not equal to one-half of SCE’s forecast because ORA relies on its own reduced labor forecast. SCE notes that differences between ORA’s and SCE’s forecast labor expense will be addressed when the authorized labor expense is determined and reflected in the Results of Operation model. See SCE-22, at 32, footnote 91. - 184 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Benefits and Other Compensation – Combined430 Illustrative Adopted 2018 Forecast (Constant 2015 $000 and Nominal $000) Short-term Incentive Program 920/921, 905, 500, 588 920/921 926 926 926 926 926 926 926 926 926 926 SCE Proposed Adopted Difference Short-term Incentive Program 132,905 57,592431 (75,313) Long-term Incentives Pension Costs 401(k) Savings Plan Medical Programs Dental Plans Vision Service Plan PBOP Costs Group Life Insurance Miscellaneous Benefit Programs Executive Benefits Third Party Billing & Non-Utility Affiliates P&B Credits Total O&M Expenses 13,726 97,474 79,190 110,719 15,035 3,443 36,823 1,426 5,592 21,087 0 57,741 79,190 110,719 15,035 3,443 32,973 1,426 4,136 10,135 (13,726) (39,733) 0 0 0 0 (3,850) 0 (1,456) (10,952) 0 0 0 517,420 344,723 (172,697) 430 SCE-06, Vol. 2A2, at 3, Table I-1 (Benefits and Other Compensation – Combined, Summary of 2018 Forecast) for SCE proposed amounts. SCE updated the forecasts for certain elements of benefits, including an accounting change in SCE-59 at 32-35. The adopted amounts are illustrative and may not match the final amounts because they are dependent on the number of employees/labor expenses approved by this decision. 431 TURN-01, at 15. - 185 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 8.3. Human Resources – Total Adopted Forecast Human Resources Test Year 2018 Illustrative Adopted O&M Forecast Constant 2015 $ 000 SCE Request Adopted Variance Human Resources Department and Executive Officers Benefits and Other Compensation Total 9. 64,950 517,420 582,370 62,277 (2,673) 344,273 (172,697) 407,000 (175,370) Operational Services SCE’s testimony on Operational Services presents its Test Year 2018 forecasts for a number of organizations that support the utility’s operations on a daily basis. As summarized in the tables below, SCE requests approval of Test Year 2018 capital expenditures totaling $230 million and O&M expenses totaling $113 million. Operational Services Operating Unit Business Resiliency Corporate Environmental Services Corporate Real Estate Corporate Health and Safety Corporate Security Supply Management Transportation Services Total 2018 Capital Expenditure Forecast (Excluding IT) (CPUC Jurisdictional Nominal $000) 17,301 672 180,215 0 22,380 365 9,257 230,190 2018 O&M Expense Forecast (Total Company 2015 Constant $000) 7,964 12,120 50,987 5,470 26,906 9,475 0 112,904 *Due to rounding, subtotals may not sum to totals. 9.1. Business Resiliency SCE states that its Business Resiliency organization provides company-wide governance and program management for business continuity, disaster recovery, assessment and mitigation, and emergency planning and - 186 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 response programs. SCE forecasts $7.964 million in O&M expenses for the organization in Test Year 2018.432 ORA contests $74,000 of that amount, which SCE requests to fund one analyst position to better support Emergency Management Operations training and exercise activities. SCE explains that it has added approximately 300 new members to Incident Support Teams and Incident Management Teams and the existing analyst could not support the expanded teams. We find SCE’s request reasonable and we approve SCE’s Test Year O&M forecast of $7.964 million. SCE forecasts $17.3 million (CPUC Jurisdictional) for Test Year 2018 capital expenditures.433 No party opposes SCE’s request. We approve SCE’s unopposed request. 9.2. Corporate Environmental Services SCE states that its Corporate Environmental Services (CES) organization is responsible for coordinating activities involving various public, private, and governmental agencies and organizations on environmental matters and issues that affect company operations, including legislative, regulatory, compliance trends, and policies. CES also supports non-capitalized project services such as environmental siting, licensing, permitting, project construction mitigation, monitoring, and reporting activities. 432 SCE-23, Vol. 1 at 2, Table I-1 (Business Resiliency 2018 O&M Forecast by FERC Account, Constant 2015 $000). 433 SCE-206, SCE Response to ALJ-Verbal-005 Q.01 (Second Supplemental response to ALJ Verbal-001): “The number in [SCE-23, Volume 01, Page 7, Table I-5, Summary of Business Resiliency Capital Expenditures] shows $33.921 million for 2018 which includes FERC jurisdictional capital. The forecast was not jurisdictionalized in testimony. - 187 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE forecasts $12.120 million in Test Year 2018 O&M expenses.434 SCE’s request is unopposed, and we approve this amount. SCE’s CES forecast for capital expenditures consists of a project on well decommissioning.435 SCE’s 2016-2018 forecast originally included $651,000 for 2016. In its rebuttal testimony, SCE accepted ORA’s recommendation to adjust the 2016 value to correspond with 2016 recorded capital expenditures of $532,000 which results in a downward adjustment of $119,000. We approve that updated value for 2016. We approve SCE’s otherwise unopposed CES capital expenditure forecast for 2016-2018 equal to $1.864 million. Finally, SCE also supports the request made by SDG&E in this proceeding for recovery of SDG&E’s costs relating to the San Dieguito Wetlands and Wheeler North Reef.436 We approve SDG&E's proposed calculation of its 20% share and overhead costs for marine mitigation with escalation, which is $991,000, $1.015 million, and $1.038 million (all nominal dollars) in 2018, 2019, and 2020, respectively.437 9.3. Corporate Real Estate SCE states that its Corporate Real Estate (CRE) organization plans, manages, and maintains SCE’s electric and non-electric real estate assets across SCE service territory. Prior to 2014, CRE’s area of responsibility included only 434 SCE-23, Vol. 1, at 12, Table II-8 (“Summary of Corporate Environmental Services O&M by FERC Account”). 435 SCE-07, Vol. 2, at 21, Table V-2 (Well Decommission Project 2016-2020 Forecast). 436 Pursuant to a Coastal Development Permit granted by the California Coastal Commission SCE must mitigate environmental impacts on marine life and maintain and monitor the San Dieguito Wetlands and Wheeler North Reef. 437 SDG&E-01, at 4-5. - 188 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 non-electric facilities, approximately 229 buildings. Beginning in 2014, CRE’s scope expanded to planning and managing buildings at electric facilities as well. Today, the CRE-managed portfolio includes approximately 1,300 buildings covering more than 7.3 million square feet across SCE’s 50,000 square mile service territory.438 9.3.1. CRE O&M SCE forecasts $50.987 million in CRE O&M expenses for Test Year 2018, for labor, rents, and maintenance activities.439 No parties contested SCE’s forecast. We approve SCE’s request. 9.3.2. CRE Capital SCE forecasts Test Year 2018 capital expenditures for three major programs within CRE: (1) Service Center Modernization Program, (2) Operational Support Program, and (3) Blanket Capital Program. As shown in the table below, SCE requests authorization of a total 2016-2020 forecast equal to $448.049 million.440 438 SCE-07, Vol. 3, at 17. 439 SCE-23, Vol. 2, at 1, Table I-1 (Corporate Real Estate 2018 O&M Forecast by FERC Account, Summary of SCE, ORA, and TURN Positions, Constant 2015 $000) 440 SCE-23, Vol. 2, at 2, Table I-2 (Corporate Real Estate 2016-2018 Capital Expenditures Forecast Summary of SCE, ORA, and TURN Positions, Nominal $000) Line Nos. 1-3 exclude 2016 recorded capital expenditure update (See ORA-SCE-108-TXB, Q2 Supplemental Revision 2 and SCE-29 at 49. - 189 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Corporate Real Estate 2016-2018 Capital Expenditures Forecast Summary of SCE, ORA, and TURN Positions441 Nominal $000 Description Variance from SCE Forecast Forecast SCE Application Service Center Modernization Program Operational Support Program Blanket Capital Program IT Infrastructure and Equipment Total ORA 121,826 79,271 205,381 164,244 25,713 517,164 151,179 118,806 22,296 371,552 TURN ORA TURN (42,555) (75,058) 108,756 153,950 (54,202) (51,431) 106,700 (45,438) (57,544) 10,628 (3,417) (11,669) 318,046 (145,612) (195,701) 160,315 155,847 23,131 448,049 46,768 ORA recommends a uniform 29% reduction of SCE’s CRE capital forecast for 2017 and 2018, resulting in CRE capital forecasts of $117.164 million in 2017 and $156.903 million in 2018. ORA recommends this reduction because SCE spent 29% less than forecast on CRE capital projects in 2016. ORA also notes that the highest level of CRE capital expenditures from 2011-2016 was $125.505 million in 2014.442 SCE describes ORA’s approach as an arbitrary blanket reduction that “fails to address the particular needs for the projects that SCE discusses in its testimony.”443 SCE notes that ORA takes no issue with SCE's justification for CRE capital projects or the reasonableness of the forecasts for those projects, nor does ORA dispute that the SCE’s proposed CRE capital projects are necessary to 441 SCE-23, Vol. 2, at 2, Table I-2 (Corporate Real Estate 2016-2018 Capital Expenditures Forecast Summary of SCE, ORA, and TURN Positions, Nominal $000) 442 ORA-16 at 30 and SCE-23, Vol. 2, at 5. 443 SCE Opening Brief at 167. - 190 - SCE Rebuttal Position PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 support occupant safety, business and operational needs, compliance requirements, and facility preservation.444 The Commission has at times found an approach such as ORA’s proposed across-the-board reductions to SCE’s request to be appropriate (e.g., when a request has no explainable relationship to well-established and stable recorded costs). In this instance, however, that is not the case for recorded costs, and we have the benefit of TURN’s testimony on the same matters. TURN reviewed each of the four major programs in the CRE organization, and conducted a project-specific analysis of SCE’s numerous proposals. That analysis informs our decisions below. 9.3.2.1. Service Center Modernization Program SCE operates 37 service centers across the SCE service territory. Each service center houses multiple Operating Units, with T&D being the primary occupant. SCE states that depending on the location of the site, the service center can also host multiple other SCE occupants, such as Customer Service, Regional Public Affairs, and Transportation Services. Service centers function as the operational base for crews in steady-state, storm, and emergency conditions. The facilities at each service center include the following:  general administrative offices,  logistics buildings (i.e., shop),  materials storage areas and structures (such as paved surface lots, canopied areas, and warehouses),  vehicle maintenance facilities (i.e., garages), and  interior and outside training areas. 444 Ibid. - 191 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE states that it considers the dependability and operability of SCE’s service centers to be critical to safely and efficiently delivering reliable service to SCE’s customers.445 In support of its forecast capital expenditures, SCE explains that its CRE organization employs an Asset Management Methodology to prioritize facility and capital work based on evaluation of three widely used and standardized metrics:446 1. Facility Condition Index (FCI): assesses conditions (e.g., age and wear of the building and its systems), and compares the cost to improve them against the cost to replace the building or site. The lower the FCI, the better condition of the asset. 2. Asset Priority Index (API): rates the relative importance of a facility among the network of facilities required to service SCE’s customer base. 3. Fitness for Purpose: where the FCI and API focus on the condition and criticality of a facility, this factor considers how the facility supports changes to business operations, such as regulatory pressures, work functions, staff levels, work processes, and equipment (e.g., data processing equipment, vehicles, and storage systems). Using this methodology to prepare its forecast for this GRC cycle, SCE identified 10 of its 37 service centers as having priority for modernization. SCE states that those locations have FCI values between 13% and 35%. SCE further contends that the building configuration, property size, and other physical site limitations of those service centers do not properly support current work processes and equipment. 445 SCE-07, Vol. 3, at 51. 446 Id., at 38, and accompanying footnotes. - 192 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s requested expenditures are summarized in the table below. SCE forecasts $176.306 million in 2017-2020 capital expenditures for this program (excluding associated IT Infrastructure and Equipment forecasts where applicable). TURN recommends reduced funding for five projects, no funding for two projects, and does not oppose three of the projects on SCE’s list. TURN’s recommendations result in proposed capital expenditures totaling $55.429 million, a reduction of $120.877 million from SCE’s requested amount. Corporate Real Estate Service Center Modernization Capital Expenditures 2017-2020 Forecast (Contested Service Centers) Summary of SCE and TURN Positions (excluding IT) Nominal $000 TURN Forecast 2017-2020 Barstow Service Center 6,036 6,036 Bishop Service Center 12,789 7,527 Blythe Service Center 7,992 7,992 Kernville Service Center 13,608 8,264 Redlands Service Center 24,801 4,435 Ridgecrest Service Center 15,627 6,500 San Joaquin Service Center 21,108 12,527 Santa Ana Service Center 26,612 0 Santa Barbara Service Center 45,585 0 Shaver Lake Service Center 2,148 2,148 Total* 176,306 55,429 *Due to rounding, subtotals may not sum to totals. Service Center Modernization SCE Application 2017-2020 Variance SCE Rebuttal Position 0 (5,262) 0 (5,344) (20,366) (9,127) (8,581) (26,612) (45,585) 0 (120,877) 6,036 12,789 7,992 13,608 24,801 15,627 21,108 26,612 45,585 2,148 176,306 As we explain in detail below, in this decision we direct SCE to proceed with each of the Service Center Modernization projects proposed in its testimony: SCE shall complete each project as scoped in that testimony and, we hope, within its forecasted budgets. However, SCE shall record all the costs of the 6 projects discussed below (including the IT Infrastructure and Equipment), from their dates of inception through completion, below the line. It is our intent - 193 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 that SCE’s shareholders pay all costs of these projects, and ratepayers pay nothing. Based on the table above, the total projected responsibility for shareholders for the 2017-2020 period is $114.546 million for the projects (excluding IT). We take this action based on TURN’s meticulously researched and documented testimony, which shows that for the past ten years, over the course of three GRC cycles, SCE has repeatedly requested and received significant funding to modernize its service centers, but has not used significant portions of those funds for that purpose. Instead, SCE explains that the funds were “reallocated at the corporate level to projects that were deemed more critical for the delivery of safe and reliable service to SCE’s customers.”447 The purpose, need for, and cost of those projects remains a mystery to this Commission because SCE declined to provide this information in response to pointed challenges by TURN in SCE’s 2012 rate case, its 2015 rate case, and now in this 2018 rate case as well. Instead, SCE provides one or two sentences that invoke the general principal that “utilities must retain flexibility in spending funds authorized in GRC decisions.” In support of this oversimplified concept, SCE cites the testimony of its policy witness in its 2012 GRC, which is more of a rebuke to the Commission for its decision in the 2009 GRC than the promised explanation of the workings of “forecast test year ratemaking” that would justify SCE’s repeated diversion of modernization funds. We have repeatedly authorized these funds to address what we believed to be significant modernization needs, on the basis of SCE’s testimony that the funding was 447 SCE-23, Vol. 2 at 16. - 194 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 “critical to fostering safe and effective environments for its workforce”448 and would address “severe and pressing needs.”449 Given that SCE finds it unnecessary to explain to this Commission its management of the funds that we authorized in our prior decisions, we order SCE to complete its list of prioritized projects, but deny cost recovery from ratepayers. Like TURN, we “agree that Edison service centers should be appropriately maintained to be functional and in good condition.”450 We have no evidence in this proceeding that “corporate level” executives at SCE share that commitment. Ironically, as we discuss below, SCE’s justification of the need to modernize its identified service centers is generally sound, which is consistent with our willingness to fund these projects in the past. That said, SCE’s explanations for its failure to initiate and/or complete these supposedly urgent projects that have previously received funding are completely unconvincing and unsupported. 9.3.2.1.1. General Disagreements between SCE and TURN This section summarizes TURN’s program-wide critiques, and SCE’s responses in rebuttal. First, TURN extends its analysis of SCE’s past spending to SCE’s 2016 recorded costs. TURN lists the projects included in SCE’s 2015 GRC request and 448 See for example SCE-23, Vol. 2 at 7. 449 D.15-11-021 at 346-347. In that decision, we stated that we remained doubtful that SCE will implement funding at the full level requested, particularly based on SCE’s past re-prioritization practices. We “quantified” our caution by approving only 50% of SCE’s requested funding, explaining “[i]n this manner, while we provide some funding for a worthwhile program, we mitigate the risks that ratepayers may be charged for funding programs that are not implemented as planned.” 450 TURN-02, at 10. - 195 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 questions SCE’s commitment to these projects based on SCE’s minimal recorded spending in 2016. In rebuttal, SCE acknowledges TURN’s observation but explains that it is renewing these requests because SCE did not receive authorized funding at the level requested in the 2015 GRC. Next, TURN and SCE engage in a dispute over the proper definition, meaning and interpretation of the FCI scores used by a consultant engaged by SCE in 2013 to prepare an assessment of SCE’s facility conditions, Parsons Environment and Infrastructure Group (Parsons). In that report, Parsons provides FCI estimates that are calculated using the standard methodology. However, Parsons recommended that SCE interpret those results in a different manner: Although current industry “standards” consider a building with an FCI of 0 to 5% good; 6 to 10% fair and 10% and above poor, in practice few, if any, inventories of public buildings ever achieve an overall rating of 10% or below. These FCI guidelines are general guidelines that are under almost constant debate within the building ownership communities because they do not take into account either modernization improvements, or expired systems’ capital renewal costs; they only address ordinary maintenance items that have been deferred through a normal funding cycle. Parsons has routinely found existing average building conditions throughout the United States to fall within the range of 25%-35% FCI, and we propose the following guides used in this report:451 451 TURN-2-A-1 (Attachment 1 to TURN Testimony on Corporate Real Estate, and Local Public Affairs Issues in Southern California Edison’s 2018 General Rate Case – Corporate Real Estate) at 23 of 187, emphasis added. - 196 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Rating Industry Standards Good Fair Poor Critical 0 — 5% 5 — 10% 10 — 30% 30 — 100% Parsons Standards Recommended to SCE 0 — 15% 15 — 30% 30 — 100% Not Used We understand that the characterization of an identical FCI value of, for example, 35% as indicating that a facility’s condition is either “poor” or “critical” may be used to strategic advantage by TURN or SCE, respectively. However, the salient point made by Parsons is that average building conditions throughout the United States fall within the range of 25%-35% FCI. SCE does not rebut this, nor does SCE explain why it disregards the advice of its own chosen expert. As will be seen below, the projects that SCE seeks to prioritize in this GRC cycle have FCIs either at the low end of Parson’s “average” building condition range of 25%-35%, or lower than 25% and are therefore in better than average condition. Next, TURN demonstrates that SCE has significantly increased its forecasts for previously proposed service center projects, compared to the levels in SCE’s 2015 GRC application. This is illustrated in the table below from TURN’s testimony: - 197 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN-02, Figure 8 Service Center Modernization Project 2015-2018 Cost Evolution452 Nominal $000 Service Center Bishop San Joaquin Redlands Kernville Ridgecrest Santa Ana Total 2015 GRC Forecast 2018 GRC Forecast 8,400 11,000 3,400 8,000 6,500 4,170 41,470 20,054 22,415 36,059 19,638 25,015 28,167 151,348 In its rebuttal testimony, SCE responds that its current service center modernization forecasts consider current levels of building deterioration and requirements to support long term operational needs. As we will discuss below, for various reasons SCE’s new cost estimates are essentially consistent with the significantly broader scopes of work that SCE has developed for each project for this GRC. TURN also faults SCE because SCE began incurring costs on the costlier versions of these projects before the Commission published its 2015 GRC decision. Again, as discussed below for various projects, while we don’t find SCE’s explanations to be very clear or direct, given that shareholders will be funding these expanded projects, to the benefit of SCE’s front-line employees and 452 2015 GRC forecast values from TURN-02, at 9, citing 2015 GRC SCE-08, Vol 3, Pt. 2, at 69, 2018 GRC SCE-07, Vol. 3 at 62, 66, 68, 70, 72, 74. 2018 GRC forecast values from SCE-23, Vol. 2. These values have been updated from SCE-07, Vol. 3 to include final 2016 recorded expenditures, rather than the estimates in SCE-07. - 198 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s customers, we will not fault SCE across the board for acting prior to receiving authorization. We note exceptions to this approach below. Finally, TURN states that it is unclear which parts of SCE’s service center design standards have changed and indicates that SCE began using certain standards contained in the revised service center design standards before they were adopted at the corporate level. TURN also contends that SCE does not provide sufficient evidence that the new standards are necessary or provide benefit to customers. In its rebuttal testimony, SCE responds that its revised Service Center Design Standards reflect efforts to meet current operational needs, and will better support safe and productive operations. As noted above, TURN’s careful review of SCE’s past spending and its forecasts for this GRC, including SCE’s justifications for its approach to this program, have been extremely helpful in our own review of SCE’s request. We return to TURN’s critiques in our review of each proposed modernization project below. For each project, we review SCE’s reasons for prioritization, then TURN’s analysis and recommendation, and finally SCE’s rebuttal to TURN. For those “repeat” projects where TURN recommends reduced funding (rather than outright denial of funding), it will be seen that TURN typically recommends approval of expenditures equal to the sum of recorded amounts through 2016 plus the lower level that SCE forecast in its 2015 GRC for 2017 and 2018. 9.3.2.1.2. Bishop Service Center SCE states that the Bishop Service Center is 66 years old, is located on a “very small” 1.42 acre site with an unsatisfactory garage facility, and has a FCI score of 35%. SCE began construction of a new service center on nearby SCE-owned property in 2013. As noted above, total project cost has increased - 199 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 from $8.4 million in the 2015 GRC to a forecast of $20.054 million in this proceeding. TURN agrees that the Bishop Service Center must be relocated, but recommends reducing SCE’s request because SCE did not spend funds on this project after it was authorized in SCE’s 2015 GRC, and because SCE’s direct testimony provided no explanation for the three-fold increase in SCE’s funding request. TURN recommends authorization of $13.7 million for all past and future spending.453 This represents the sum of SCE’s recorded spending through 2016 plus the amount SCE requested in the 2015 GRC, escalated for inflation. SCE responds in rebuttal that although spending on the Bishop Service Center project began in 2013, “SCE’s 2015 capital expenditures exceeded the authorized service center modernization funding levels and were insufficient to complete the additional work necessary.”454 SCE also states that the increased costs reflect its recent actual experience with other service center modernization projects as well as “fitness for purpose deficiencies and regulatory requirements” identified after the 2015 GRC.455 The expanded scope of the project now includes the following:  Constructing a pre-fabricated logistics building for efficient pre-assembly of parts and materials;  Constructing a vehicle garage, a wash bay, a fuel station, and a metal truck canopy for the safety of SCE crews while loading and preparing vehicles; and 453 As calculated and explained by SCE in SCE-23, Vol. 2, at 23. 454 SCE-23, Vol. 2, at 25. 455 Id., at 24. - 200 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2  Installing a canopied hazardous material storage area to meet safety and compliance requirements.456 The table below shows the total Bishop-related expenditures requested by SCE and recommended by TURN. Bishop Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast457 Nominal $000 3 Bishop Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 Recorded Prior 2016 4,042 1,213 2017 12,789 Forecast 2018 2019 2020 0 0 0 Total 18,044 194 229 1,483 104 0 0 2,010 4,236 1,442 14,272 104 0 0 20,054 4,236 1,070 8,400 0 0 0 13,706 We find that SCE’s proposed modernization of the Bishop Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 9.3.2.1.3. Kernville Service Center SCE states that the Kernville Service Center is 65 years old, is located on a small site in a residential neighborhood, and has an FCI score of 18% which as 456 Id., at 24. 457 Id. at 23, Table II-9 (Corporate Real Estate, Bishop Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000) and Appendix A at A-81. - 201 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 we noted above, SCE labels as “poor” while Parsons considers this “fair” condition. SCE began construction on nearby SCE-owned property in 2013. As noted above, total project cost has increased from $8.0 million in the 2015 GRC to a forecast of $19.638 million in this proceeding. TURN recommends reducing SCE’s request because SCE did not spend funds on this project after it was authorized in SCE’s 2015 GRC, and because SCE’s direct testimony provided no explanation for the significant increase in SCE’s funding request. TURN recommends authorization of $12.074 million for all past and future spending. This represents the sum of SCE’s recorded spending through 2016 plus the amount SCE requested in the 2015 GRC, escalated for inflation. SCE’s response to TURN in rebuttal is similar to its justification for the higher costs of the Bishop project. SCE states that the increased costs reflect the results of a post-2015 GRC Fitness for Purpose review such that the expanded scope of the project now includes the same projects listed above for Bishop:  Constructing a pre-fabricated logistics building;  Constructing a vehicle garage, a wash bay, a fuel station, and a metal truck canopy for the safety of SCE crews; and  Installing a canopied hazardous material storage area.458 The table below shows the total Kernville-related expenditures requested by SCE and recommended by TURN. 458 Id., at 28. - 202 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Kernville Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast459 Nominal $000 3 Kernville Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 Recorded Prior 2016 3,601 598 2017 13,607 Forecast 2018 2019 2020 0 0 0 Total 17,806 15 3,616 229 827 1,483 15,091 104 104 0 0 0 0 1,831 19,638 2,682 592 4,400 4,400 0 0 12,074 We find that SCE’s proposed modernization of the Kernville Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 9.3.2.1.4. Redlands Service Center SCE states that the Redlands Service Center is 58 years old, is located on a small site, and has an FCI score of 20% which SCE considers “poor” while Parsons considers this “fair” condition. SCE began construction on nearby SCE-owned property in 2013. As noted above, total project cost has increased tenfold, from $3.4 million in the 2015 GRC to a forecast of $36.059 million in this proceeding (in fact, TURN notes that the Redlands project dates to SCE’s 2012 GRC, where SCE requested $4.69 million for a combined service center and 459 Id., at 27, Table II-11 (Corporate Real Estate, Kernville Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000) and Appendix A at A-81. - 203 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 garage modernization). This proceeding is the first instance where SCE has proposed relocating the service center instead of modernizing the existing facility. TURN recommends reducing SCE’s request because SCE has essentially presented the Commission with a fait accompli, having already purchased the land for the new service center and largely completed design work, at a combined cost of $8.6 million.460 TURN faults SCE for neglecting to bring this to the Commission’s attention while the 2015 GRC was still pending. TURN also questions SCE’s assumptions about population growth in the region. TURN recommends authorization of $13.5 million for all past and future spending.461 This represents the sum of SCE’s recorded spending through 2016 plus the $4.9 million authorized in the 2015 GRC. SCE’s response to TURN in rebuttal focuses on defense of its forecast population growth and further explanation of the deficiencies of the current service center, which SCE states were still being evaluated during the 2015 GRC. SCE also asserts that the exiting service center has Fitness for Purpose deficiencies related to facility age, building condition, property size, and vehicle maintenance facility size.462 SCE concludes by restating its firm belief that “the scope of work for the Redlands Service Center Modernization project is essential to support safe and reliable service to the Redland District.”463 460 TURN-02, at 16. 461 As calculated and explained by SCE in SCE-23, Vol. 2, at 30. 462 SCE-23, Vol. 2, at 32. 463 Id., at 35. - 204 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The table below shows the total Redlands-related expenditures requested by SCE and recommended by TURN. Redlands Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast464 Nominal $000 3 Redlands Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 Recorded Prior 2016 8,167 453 2017 7,469 Forecast 2018 2019 2020 9,902 7,429 0 Total 33,424 0 8,167 23 476 512 1,042 7,980 10,945 1,061 8,491 0 0 2,635 36,059 8,176 429 1,633 1,633 0 13,504 1,633 We find that SCE’s proposed modernization of the Redlands Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 9.3.2.1.5. Ridgecrest Service Center SCE states that the Ridgecrest Service Center is 59 years old, is located on a small site given its scope of work, and has an FCI score of 25% which once again SCE considers “poor” while Parsons considers this “fair” condition. As noted above, total project cost has increased from $6.5 million in the 2015 GRC to a forecast of $25.015 million in this proceeding. SCE has changed its position since 464 Id., at 30, Table II-13 (Corporate Real Estate, Redlands Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000) and Appendix A at A-81. - 205 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 the 2015 GRC, when it described the existing site as “adequate” in size, such that SCE now proposes to expand the service center onto an adjacent site. TURN recommends reducing SCE’s request because SCE is well into the expansion but never informed the Commission of its new plans.465 TURN faults SCE for neglecting to bring this to the Commission’s attention while the 2015 GRC was still pending. TURN recommends authorization of $14.981 million for all past and future spending.466 This represents the sum of SCE’s recorded spending through 2016 plus the $6.5 million authorized in the 2015 GRC. SCE’s response to TURN in rebuttal contends that although SCE determined that there was a need for a larger site prior to the issuance of the 2015 GRC Decision, “the full scope of the expanded plan for the Ridgecrest Service Center modernization was still under consideration until after that time.”467 SCE also asserts that the need for a larger site is warranted by consideration of API and Fitness for Purpose evaluations and the deficiencies identified in those analyses. SCE concludes that “the combination of FCI, API and Fitness for Purpose analysis support the need to increase the size of the Ridgecrest site in support of safe and efficient service over the projected life of the facility.”468 The table below shows the total Ridgecrest-related expenditures requested by SCE and recommended by TURN. 465 TURN-02, at 18. 466 As calculated and explained by SCE in SCE-23, Vol. 2, at 36. 467 SCE-23, Vol. 2, at 38. 468 Ibid. - 206 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Ridgecrest Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast469 Nominal $000 3 Ridgecrest Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 Recorded Prior 2016 6,101 2,277 2017 8,384 Forecast 2018 2019 2020 7,243 0 0 24,005 Total 91 6,192 292 2,569 122 8,506 505 7,748 0 0 0 0 1,010 25,015 6,192 2,289 3,250 3,250 0 0 14,981 We find that SCE’s proposed modernization of the Ridgecrest Service Center is necessary to support of safe and efficient service over the projected life of the facility. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 9.3.2.1.6. San Joaquin Service Center SCE states that the San Joaquin Service Center is 47 years old and has an FCI score of 25% which once again SCE considers “poor” while Parsons considers this “fair” condition. As noted above, total project cost has doubled from $11.0 million in the 2015 GRC to a forecast of $22.415 million in this proceeding. TURN notes that the San Joaquin project also dates to SCE’s 2012 GRC, where SCE requested $10.54 million to modernize the facility. TURN states that the Commission authorized 90% of SCE’s request, but the utility did not 469 Id. at 36, Table II-17 (Corporate Real Estate, Ridgecrest Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000) and Appendix A at A-81. - 207 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 spend the funds, then returned in the 2015 GRC with a new request for $11.9 million. TURN states that its analysis and discovery indicate that the significant increase in forecast expenditures since 2015 is due to expected population growth in the region. TURN recommends reducing SCE’s request because SCE has repeatedly failed to proceed with the project after being authorized to do so. TURN recommends authorization of $13.339 million for all past and future spending.470 This represents the sum of SCE’s recorded spending through 2016 plus the $6.5 million authorized in the 2015 GRC. SCE’s response to TURN in rebuttal repeats its defense that funds authorized in the 2012 GRC for the San Joaquin Service Center were reallocated at the corporate level to cover important T&D reliability expenditures, and the level of funding authorized by the Commission for the Service Center Modernization Program in the 2015 GRC was substantially less than the amount requested by SCE. SCE also defends its growth forecasts and states that the current scope of the project will address increased Fitness for Purpose operational requirements, such as adding a service bay at the existing garage and constructing new wash bays and new canopies to improve crew safety and meet compliance requirements.471 Altogether, SCE emphasizes that “the capital work identified in SCE’s 2018 testimony for San Joaquin remains critical to foster a safe and effective work 470 As calculated and explained by SCE in SCE-23, Vol. 2, at 39. 471 SCE-23, Vol. 2, at 41. - 208 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 environment and to addresses new operational methods and equipment requirements.”472 The table below shows the total San Joaquin-related expenditures requested by SCE and recommended by TURN. San Joaquin Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast473 Nominal $000 3 San Joaquin Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 Recorded Prior 2016 238 0 2017 921 Forecast 2018 2019 2020 6,254 6,368 7,565 21,346 Total 0 238 0 0 0 921 261 6,515 106 702 6,474 8,267 1,069 22,415 238 0 921 4,060 4,060 4,060 13,339 We find that SCE’s proposed modernization of the San Joaquin Service Center is necessary to foster a safe and effective work environment and to addresses new operational methods and equipment requirements. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 9.3.2.1.7. Santa Ana Service Center SCE states that the Santa Ana Service Center is 56 years old and has an FCI score of 20% which once again SCE considers “poor” while Parsons considers 472 Id., at 40. 473 Id., at 39, Table II-19 (Corporate Real Estate, San Joaquin Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000). - 209 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 this “fair” condition. As noted above, total project cost has increased almost seven-fold from $4.170 million in the 2015 GRC to a forecast of $28.167 million in this proceeding. TURN highlights that that the Santa Ana project dates back 10 years to SCE’s 2009 GRC, where the Commission authorized $13.5 million for the project. After spending none of the authorized funds, SCE brought the project back in its 2012 GRC, where the Commission authorized $4.170 million for SCE to start again. SCE did not spend those funds on the project either, so it brought the project back for a third time in its 2015 GRC, again seeking $4.170 million to initiate the project. TURN recommends that the Commission deny all requested funding because SCE has been repeatedly authorized funding for modernization of this service center in the past, and has never seen fit to undertake the project. SCE’s response to TURN asserts that “the Commission has acknowledged that utilities have flexibility in allocating authorized funding” and the funds authorized in the 2009 and 2012 GRC for the Santa Ana Service Center were reallocated for other urgent spending needs.474 SCE also repeats that the reduced funding authorized by the Commission in the 2015 GRC “was insufficient to initiate all of the service center modernization work requested, including the modernization of the Santa Ana Service Center.”475 SCE also defends the significant increase in the cost of the project by noting that in this GRC SCE is proposing more extensive changes to the service center, including:  Constructing a new Administration Building in a different location for safer, more efficient site circulation and parking; 474 Id., at 45. 475 Ibid. - 210 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2  Constructing a new logistics building for assembly and staging of parts and materials that is currently performed outdoors;  Constructing an improved outdoor laydown area, for safer, more effective staging of materials; and  Installing building systems, furnishings, voice/data infrastructure, and security systems.476 The table below shows the total Santa Ana-related expenditures requested by SCE and recommended by TURN. Santa Ana Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast477 Nominal $000 2017 1,023 Forecast 2018 2019 4,169 10,614 2020 10,806 26,612 0 0 0 1,023 156 4,326 318 10,932 1,081 11,886 1,555 28,167 4 TURN 0 0 Due to rounding, subtotals may not sum to totals. 0 0 0 0 0 Line No. 1 2 3 Santa Ana Service Center Service Center IT Infrastructure and Equipment Total Recorded Prior 2016 0 0 0 0 Total We find that SCE’s proposed modernization of the Santa Ana Service Center is necessary to foster a safe and effective work environment. We direct SCE to proceed with the project as described in its testimony, and at the funding levels shown on lines 1-3 in the table above. SCE shall record all the costs of this project, from the date of inception through completion, below the line. 476 Id., at 46. 477 Id., at 44, Table II-23 (Corporate Real Estate, Santa Ana Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000). - 211 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 9.3.2.1.8. Santa Barbara Service Center The final contested project on SCE’s list of service center proposals is SCE’s request for funding to relocate its Santa Barbara Service Center. This proposal differs from the others on SCE’s list because SCE believes it is necessary to relocate its service center from its present location to the north of Santa Barbara to a new location south of the city. SCE states that the new location will be closer to its customer base and the area where the majority of outages occur, and closer to the labor base from which SCE draws its own employees. SCE’s forecasted cost of this relocation is $48.6 million. TURN recommends that the Commission deny funding for SCE’s proposed relocation. TURN contends that SCE has not provided clear evidence that relocating the service center would solve either problem that SCE cites as justification for the project, or even that the problems are severe enough to abandon the existing facility. TURN also believes that SCE did not adequately consider alternatives to relocation. Finally, TURN recommends that if the Commission approves SCE’s request, it should nevertheless ensure that ratepayers do not pay for the abandoned plant that results by requiring SCE to write off the abandoned service center. SCE responds to TURN in its rebuttal testimony by providing a more thorough explanation of its analysis and review of options than it provided in direct testimony. The table below shows the total Santa Barbara-related expenditures requested by SCE and recommended by TURN. In this instance, we find that SCE has justified its proposal to relocate its Santa Barbara Service Center. We agree that the reduction in employee travel time will result in the dual benefits of shorter outages in the Santa Barbara area, as well as higher retention rates for - 212 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s employees. We approve SCE’s request and its forecasted levels of expenditures, as shown on lines 1-3 in the table below. That said, we emphasize that we expect this project to go forward as planned, without the diversion of funds that TURN documented in its testimony for other projects. In the event that SCE does divert these funds, we will consider whether the financial responsibility for this project should be placed on SCE’s shareholders. Santa Barbara Service Center Modernization Capital Expenditures Prior and 2016 Recorded, and 2017-2020 Forecast478 Nominal $000 3 Santa Barbara Service Center Service Center IT Infrastructure and Equipment Total 4 TURN Line No. 1 2 9.3.2.1.9. Recorded Prior 2016 0 0 0 0 0 0 0 0 Forecast 2017 2018 2019 2,046 15,635 10,614 2020 17,289 45,585 0 261 2,046 15,896 53 10,667 2,701 19,991 3,015 48,600 0 0 0 0 0 Total Barstow Service Center SCE’s Barstow Service Center modernization proposal is uncontested, and we approve SCE’s forecasted capital expenditures, as shown in the table below: 478 Id., at 47, Table II-25 (Corporate Real Estate, Santa Barbara Service Center Modernization Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000). - 213 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Barstow Service Center Modernization Prior Recorded/2016-2020 Forecast Capital Expenditures479 Nominal $000 Line No. 1 2 3 Barstow Service Center Service Center IT Infrastructure and Equipment Total Prior 233 2016 376 2017 6,036 0 233 425 801 215 6,251 Forecast 2018 2019 0 0 0 0 2020 0 0 0 Total 6,645 0 0 640 7,285 9.3.2.1.10. Blythe Service Center SCE’s Blythe Service Center modernization proposal is uncontested, and we approve SCE’s forecasted capital expenditures, as shown in the table below: Blythe Service Center Modernization Prior Recorded/2016-2020 Forecast Capital Expenditures480 Nominal $000 Line No. 1 2 3 Blythe Service Center Service Center IT Infrastructure and Equipment Total Prior 105 2016 62 2017 0 4 109 0 62 0 0 Forecast 2018 2019 4,065 3,927 417 4,482 334 4,261 2020 0 Total 0 0 8,159 755 8,914 9.3.2.1.11. Shaver Lake Service Center SCE’s Shaver Lake Service Center modernization proposal is uncontested, and we approve SCE’s forecasted capital expenditures, as shown in the table below: 479 SCE-07, Vol. 3 at 60, Table V-18 (Barstow Service Center Modernization 2016-2020 Forecast Capital Expenditures) and SCE-23, Vol. 2, Appendix A at A-81. 480 Id., at 64, Table V-20 (Blythe Service Center Modernization, Prior Recorded/2016-2020 Forecast Capital Expenditures) and SCE-23, Vol. 2, Appendix A at A-81. - 214 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Shaver Lake Service Center Modernization Prior Recorded/2016-2020 Forecast Capital Expenditures481 Nominal $000 Shaver Lake Service Center Prior 2016 1 Service Center 3,733 2,424 IT Infrastructure 2 and Equipment 125 234 3 Total 3,858 2,658 Due to rounding, subtotals may not sum to totals. Line No. 9.3.2.2. 2017 2,148 358 2,507 Forecast 2018 2019 0 0 0 0 0 0 2020 0 0 0 Total 8,305 717 9,022 Operational Support Program SCE states projects in the Operational Support Program address changing operational needs and the associated building deficiencies uncovered in Fitness for Purpose evaluations. These projects include improvements to building systems, reconfigurations of facilities, and improvements to sites, and fall within the four categories shown in the table below, which summarizes SCE’s capital expenditure forecast:482 481 SCE-07, Vol. 3A2, at 78, Table V-27 (Shaver Lake Service Center Modernization, Prior Recorded/2016-2020 Forecast Capital Expenditures) and SCE-23, Vol.02, Appendix A at A-81. 482 SCE originally requested funding for a fifth category, “Future Anticipated Projects,” with forecasted capital expenditures of over $100 million for the 2018-2020 period. TURN opposed SCE’s request, and SCE withdrew its proposal in its rebuttal testimony. See SCE-23, Vol. 2, at 57-59. - 215 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Operational Support Program Capital Expenditure Forecast Prior and 2016 Recorded/2017-2020 Forecast ($000 Nominal) Recorded Line No. 1 1.1 1.2 2 2.1 2.2 3 3.1 3.2 4 4.1 4.2 Prior Infrastructure Upgrade Projects IT Infrastructure & Equipment Subtotal: Infrastructure Upgrades Substation Maintenance and Test Buildings IT Infrastructure & Equipment Subtotal: Substations Facility Repurpose Projects IT Infrastructure & Equipment Subtotal: Facility Repurpose Projects Projects less than $3 million IT Infrastructure & Equipment Subtotal: Projects less than $3 million Total Operational Support Programs Total IT Infrastructure & Equipment Total Program Request Forecast Total 2016 2017 2018 2019 2020 35,345 15,537 11,868 43,779 44,577 23,233 174,339 2,981 2,025 614 2,199 3,725 2,172 13,716 38,326 17,562 12,482 45,978 48,302 25,405 188,055 1,162 30,465 8,176 3,160 5,592 48,555 61 2,184 78 81 2,404 1,223 32,649 8,254 3,160 5,673 50,959 350 27,960 1432 6,567 4,246 40,555 8 4,541 521 208 212 5,490 358 32,501 1,953 6,775 4,458 46,045 361 7,590 256 5,524 557 256 361 8,147 512 5,524 36,056 52,249 44,021 64,046 2,989 7,184 3,575 39,045 59,433 47,596 1,621 15,352 432 1,245 2,053 16,597 51,983 30,446 278,801 2,485 3,937 2,685 22,855 66,531 55,920 33,131 301,656 Due to rounding, subtotals may not sum to totals. 9.3.2.2.1. Infrastructure Upgrade Projects - 216 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE states that infrastructure upgrade projects address deficiencies of existing facilities based on poor Fitness for Purpose evaluation outcomes with respect to new business operational requirements. SCE forecasts capital expenditures for nine projects during the 2018-2020 GRC period, including $45.978 million for Test Year 2018. SCE’s request is unopposed, and we authorize SCE’s requested spending levels for infrastructure upgrade projects, as shown in the table at the end of this section. 9.3.2.2.2. Substation Maintenance and Test Buildings (Substation Reliability Upgrades) SCE states that the T&D crews that perform maintenance and testing at SCE’s 900 substations are strategically located throughout the service territory, in order to best access these substations. SCE’s Substation Maintenance and Test Building Program is designed to replace temporary and outdated facilities at certain substation locations, in order to improve the productivity of its crews. SCE forecasts $8.254 million in Test Year 2018 expenditures for this program, which will fund improvements at six substations identified as high priority projects. SCE’s request is unopposed, and we authorize SCE’s requested spending levels for these substation upgrades, as shown in the table at the end of this section. 9.3.2.2.3. Facility Repurpose Projects SCE states that Facility Repurpose projects are major renovations of existing SCE facilities to address new or changed operational requirements. SCE lists five projects in its testimony, and forecasts $6.775 million in Test Year 2018 expenditures for this program. TURN opposes one program that accounts for most of the test year expenditures, the Storage of Critical Electrical Equipment Spares Project. - 217 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The scope of this project includes the construction of an environmentally controlled and secured warehouse at an existing storage location where equipment and materials are stored for the Chino Hills Underground segment of SCE’s transmission system. SCE states that in addition to providing improved storage for Chino Hills equipment, the project will also respond to a broader need for “centralized, secure, and well-organized storage of spare equipment and material.”483 SCE states that this need was identified in a 2011 “Critical Spares Workstream” joint project of T&D and Supply Chain Management to evaluate improvements to SCE’s storage and inventory control model.484 SCE estimates total cost of the project is $11.314 million, including forecast 2018 Test Year expenditures of $6.775 million.485 TURN recommends no funding for this project, other than forecast IT infrastructure and equipment expenditures.486 In Exhibit TURN-02, cross-examination at hearing, and in briefing, TURN effectively demonstrated that SCE’s stated justifications for the project were not convincing. Therefore, we adopt TURN’s recommendation to deny SCE’s request to proceed with this project. Consistent with TURN’s support for recovery of forecast IT 483 SCE-07, Vol. 3, at 122. 484 Ibid. 485 SCE-23, Vol. 2, at 54, Table II-28 (Corporate Real Estate, Storage of Critical Electrical Equipment Spares Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000). 486 TURN-02, July 25, 2017 Errata at 28. - 218 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 infrastructure and equipment expenditures, we authorize the spending shown below:487 Storage of Critical Electrical Equipment Spares Project Requested and Authorized Capital Expenditures ($000 Nominal)   Recorded   Prior Project IT     Total IT Total       2016 81 81 Forecast 2017 2018 2019 Requested 6,567 4,246 208 212 6,775 4,458 Authorized 208 212 208 212 2020 Total 10,893 421 11,314 421 421 9.3.2.2.4. Projects Less Than $3 Million The fourth and final category in SCE’s Operational Support Program is “Projects Less Than $3 Million.” SCE states that this category consists of fifteen capital projects with a specifically-defined and planned scope, with total recorded and forecast expenditures that sum to under $3 million per project. SCE requests approval of total expenditures for 2016-2020 of $16.236 million, of which $5.524 million falls within the 2018 Test Year.488 SCE’s request is unopposed, and we authorize SCE’s requested spending levels for Projects Less Than $3 Million, as shown in the introductory table above. 487 SCE-23, Vol. 2, at 54, Table II-28 (Corporate Real Estate, Storage of Critical Electrical Equipment Spares Capital Expenditures, Prior and 2016 Recorded / 2017-2020 Forecast, Summary of SCE and TURN Positions, Nominal $000). 488 SCE-07, Vol. 3, at 131, Table V-50 (Operational Support Program – Projects Less Than $3 million, Prior Recorded/2016-2020 Forecast Capital Expenditures). - 219 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 9.3.2.3. Blanket Capital Program SCE’s GRC applications typically include a request for a Blanket Capital Program. SCE describe the program as “an effective and efficient process for ongoing expenditures of similar types of work”489 characterized by a high volume of relatively small, routine projects (e.g., fire systems, Heating, Ventilation and Air Conditioning (HVAC), roof, lighting, and furniture modifications).490 These projects fall within the five categories shown in the table below, which summarizes SCE’s capital expenditure forecast: Blanket Capital Programs SCE Requested 2016-2020 Forecast Capital Expenditures491 Nominal $000 2016 Non-Electric Capital Maintenance 21,588 Substation Capital Maintenance 8,070 Energy Efficiency 2,724 Ergonomic Equipment 1,311 Ongoing Furniture Modifications 2,018 Various Major Structures 807 Total 36,519 2017 22,303 13,300 2,762 1,330 3,172 15,960 58,828 2018 23,140 15,635 2,919 1,355 3,961 21,889 68,899 2019 24,093 15,920 2,972 1,380 4,776 22,288 71,429 2020 Total 24,962 116,086 16,209 69,135 3,134 14,510 1,405 6,781 5,619 19,545 22,692 83,637 74,020 309,695 SCE requests authorization of $309.695 million for capital expenditures over the 2016-2020 period, including $68.899 million for the 2018 Test Year (prior to updating for recorded 2016 expenditures). 489 SCE-07, Vol. 3, at 132. 490 Id., at 36. 491 Id., at 36, at 132, Table V-51 (Blanket Programs, 2016-2020 Forecast Capital Expenditures). This table excludes updated 2016 recorded amounts. - 220 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN opposes several of SCE’s requests, and we review these disputed items below. 9.3.2.3.1. Non-Electric Capital Maintenance This category of capital maintenance involves activities to “preserve the value of SCE’s buildings, equipment, and grounds, making them as safe and productive as reasonably possible.”492 As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $116.086 million, of which $23.140 million is forecast for the 2018 Test Year. SCE states that its forecast is based on historical expenditures. TURN recommends using recorded 2016 expenditures of $14.305 million as the basis for the 2017 and 2018 forecasts, deriving values of $14.49 million for 2017 and $15.215 million for 2018. TURN supports its approach by reviewing SCE’s recent history of SCE’s Non-Electric Capital Maintenance program:493  In SCE’s 2012 GRC, the utility proposed increased funding for its capital maintenance activities for the stated purpose of reducing its overall FCI score.  The overall score for SCE’s facilities had worsened from 25% in 2006 to 31% in 2009, and SCE’s goal was to achieve an FCI score of 16%.  SCE’s efforts proved successful, as the utility was able to bring its FCI score down, first to 19.8% based on a 2013 review, and then to 16% by the end of 2015. 492 SCE lists seven categories of maintenance work at SCE’s non-electric facilities: (1) Electrical/Fire Systems, (2) Fencing and Walls, (3) Flooring, (4) HVAC, (5) Paving, (6) Roof Repairs, and (7) Other Repairs. SCE Opening Brief at 177. 493 TURN Opening Brief at 186. - 221 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2  SCE achieved that goal despite reducing its capital maintenance spending from the heights that were achieved in the 2013-2014 period.  In 2015, SCE recorded $26.517 million.  The forecast for 2016 spending in SCE’s 2015 GRC direct testimony was $21.6 million, but SCE recorded $14.305 million.  Thus from the high point of spending recorded in 2013, SCE has reported steadily declining spending levels, even as it marked the achievement of its target goal in 2015. TURN concludes that its recommendation is “premised on the recognition that the added costs incurred while addressing deferred maintenance in order to improve the FCI score should not go on forever, particularly after SCE reported achieving its goal.”494 In rebuttal, SCE asserts that the reduced level of funding recommended by TURN “would cause SCE’s non-electric portfolio to deteriorate resulting in an increase to SCE’s overall portfolio FCI, an increase in potential failures of facility systems and components and associated operational disruptions, and, ultimately, an increase in future maintenance and repair costs.”495 SCE notes that its annual average spending for the 2011-2015 period was $31.503 million, versus its average request in this application of $21.761 (2016 recorded and forecast 2017-2020) and TURN’s lower annual average for 2016-2020, $15.251 million. We find TURN’s approach to be more logical and reasonable than SCE’s request. SCE fails to explain why it would require $21 million annually for this program when it forecast the same amount for 2016 but only recorded 494 TURN-02, at 36. 495 SCE-23, Vol. 2, at 62. - 222 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $14 million.496 As TURN observes in its reply brief, SCE’s contentions here are at odds with its recent actions.497 We authorize TURN’s recommended funding levels for Non-Electric Capital Maintenance, as shown in the table at the end of this section. 9.3.2.3.2. Substation Capital Maintenance The category of substation capital maintenance involves maintenance of physical buildings and grounds at SCE’s approximately 900 substations and 285 hydro facilities. As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $69.134 million (prior to updating for recorded 2016 expenditures), of which $15.635 million is forecast for the 2018 Test Year. SCE’s forecast for substation capital maintenance is a combination of historical expenditures and a zero-based budget, considering fluctuations in the maintenance activity.498 TURN recommends using recorded 2016 expenditures ($10.766 million) as the basis for the 2017 and 2018 forecasts. TURN supports its recommendation by reviewing the transition of responsibility for managing this program from the T&D organization to CRE, which generally took place in 2014 and 2015. Following several years of overlapping responsibilities where spending was higher than average, CRE assumed full responsibility in 2016 and recorded expenditures equaled $10.766 million, approximately $2.5 million below SCE’s 496 Compare SCE-23, Vol. 2, Table II-32 (showing forecast 2016 expenditures) with Table II-33 (showing recorded 2016 expenditures). 497 TURN Reply Brief at 32. 498 SCE-07, Vol. 3, at 137. - 223 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 forecast. Based on its observations and analysis, “TURN submits that the pattern reflects a substantial effort to address deferred maintenance in 2014, and the recorded costs since then indicate the remediation work is tailing off.”499 TURN calculates its recommended values for 2017 and 2018 by starting with the recorded 2016 figure, but reducing it by 20% to account for SCE’s indication in a response to a TURN data request that the recorded figure includes unspecified and unquantified costs not related to this program.500 In rebuttal, SCE confirms that the 2014-2015 spending addressed initial planned capital maintenance work for SCE’s occupied substations and emergent maintenance needs on the unoccupied portion of the substation portfolio. SCE then states that the below-forecast recorded expenditures in 2016 were due to a second transition in responsibilities, this time from SCE’s CRE organization to an outside service provider. As such, SCE disagrees with TURN’s suggestion that the lower spending indicated that the amount of necessary maintenance is “tailing off.” SCE contends that as work increases on its 900 unoccupied substations its requested annual budget of $15.266 million per year from 2017-2020 will prove to be justified. Just as we found for non-electric capital maintenance, we again find TURN’s analysis to be thorough, logical, and convincing. We also conclude that a measured approach to SCE’s forecasts in this area are warranted, given the multiple transitions in responsibility for SCE’s capital maintenance programs. We adopt forecasts based on TURN’s analysis, but we do not impose the 20% 499 TURN Opening Brief, at 188, citing TURN-02, at 37. 500 TURN-02, at 38. - 224 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 reduction from 2016 recorded costs that TURN recommends, nor do we escalate the recorded 2016 value for future years. Both sides of this contested matter will have an opportunity to present a more stable forecast in SCE’s 2021 GRC. We authorize the 2016-2020 funding levels for Substation Capital Maintenance shown in the table at the end of this section. 9.3.2.3.3. Energy Efficiency SCE states that its Energy Efficiency Program supports projects that improve the environmental impact of SCE facilities by reducing water or energy consumption. For the 2016-2020 period, SCE plans projects to upgrade exterior lighting, install smart irrigation controllers, and research and develop projects based on emerging technologies. As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $14.510 million (prior to updating for recorded 2016 expenditures), of which $2.919 million is forecast for the 2018 Test Year. SCE’s request is unopposed, and we authorize SCE’s requested spending levels for energy efficiency projects, as shown in the table at the end of this section. 9.3.2.3.4. Ergonomic Equipment SCE states that its Ergonomic Equipment Program addresses ergonomic furnishings and equipment prescribed by SCE’s Disability Management program or recommended by SCE Corporate Health and Safety as a result of an ergonomic evaluation process. The program seeks to prevent and respond to work-related injuries. As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $6.781 million (prior to updating for recorded 2016 expenditures), of which $1.355 million is forecast for the 2018 Test Year. SCE’s request is unopposed, and we authorize SCE’s requested spending - 225 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 levels for ergonomic furnishings and equipment, as shown in the table at the end of this section. 9.3.2.3.5. Ongoing Furniture Modifications SCE states that its Ongoing Furniture Modifications Program provides funding, outside of other capital projects, to provide adequate and efficient office furniture and equipment for employees in SCE’s workspaces. As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $19.545 million (prior to updating for recorded 2016 expenditures), of which $3.961million is forecast for the 2018 Test Year. SCE’s request is unopposed, and we authorize SCE’s requested spending levels for its Furniture Modifications Program, as shown in the table at the end of this section. 9.3.2.3.6. Various Major Structures SCE states that its Various Major Structures (VMS) Program provides funding for projects that are unplanned, or emergent, and, therefore unpredictable. Such projects may include those triggered by regulatory changes, environmental changes, or significant facility failures. As shown in the table above, SCE requests authorization for 2016-2020 capital expenditures totaling $83.637 million (prior to updating for recorded 2016 expenditures), of which $21.889 million is forecast for the 2018 Test Year. SCE states that its forecast is based on historical spend, plus an increase to account for the additional facilities within CRE’s area of responsibility. TURN notes that SCE has not supported its significantly higher forecasts with evidence that unforeseen, necessary capital spending will rise to those - 226 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 levels, or even is likely to do so.501 TURN recommends authorization of an annual forecast based on the average of recorded spending from 2011-2016, $7.894 million. As we have discussed elsewhere in this decision, we disagree with SCE regarding the extent of discretion its managers should have to redirect funds authorized for one purpose to an entirely different purpose. Given SCE’s position that this discretion is near-absolute, we find it illogical to authorize significant additional funding here, for what is essentially another contingency fund. TURN demonstrated in its testimony that in the past SCE has used VMS funds for projects that could have been planned in advance and presented to us for our review and approval. We understand that CRE’s responsibility has expanded since SCE’s last GRC, but beyond that SCE has provided little actual analysis to back up its significantly higher expenditure forecasts for the 2017-2020 period. We adopt TURN’s recommendation to authorize an annual forecast based on the average of recorded spending from 2011-2016, $7.894 million. However, we see no reason to escalate what is essentially a rough estimate to begin with, and leave that amount constant through 2020. 9.3.2.3.7. Conclusion: Approved Recorded and Forecast Blanket Capital Expenditures 501 TURN-02, at 40. - 227 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Blanket Capital Programs Approved 2016-2020 Recorded and Forecast Capital Expenditures Nominal $000 2016 2017 Non-Electric Capital Maintenance 14,305 14,490 Substation Capital Maintenance 10,766 10,766 Energy Efficiency 1,175 2,762 Ergonomic Equipment 320 1,330 Ongoing Furniture Modifications 685 3,172 Various Major Structures 870 7,894 Total 28,121 40,414 9.4. 2018 15,215 10,766 2,919 1,355 3,961 7,894 42,110 2019 15,975 10,766 2,972 1,380 4,776 7,894 43,763 2020 Total 16,774 76,759 10,766 53,830 3,134 12,962 1,405 5,790 5,619 18,212 7,894 32,446 45,592 199,999 Corporate Health and Safety SCE states that its Corporate Health and Safety (CHS) organization provides guidance, governance, and oversight of the company’s safety program and activities, including public, contractor, and worker safety activities. This includes developing and managing programs that meet regulatory requirements outlined in the Occupational Safety and Health Act (OSHA), leading all major safety incident investigations, tracking and analyzing the company’s safety data and records, managing and implementing the Enterprise Safety Program, as well as managing all other office safety programs and standards. CHS also partners with other operating units (OUs) so that each OU’s activity-specific safety programs meet the requirements outlined in OSHA. The primary objective of CHS is to mitigate safety risks based on observation, data collection, and analysis.502 502 SCE-07, Vol. 4, at 1. - 228 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE forecasts $5.470 million in CHS O&M expenses for Test Year 2018. TURN did not contest CHS’s O&M Forecast. ORA proposes a reduction of $700,000 associated with SCE’s participation in the Electric Power Research Institute’s (EPRI) Program 60 (Electric and Magnetic Fields and Radio-Frequency Health Assessment and Safety) research.503 ORA’s proposal to exclude EPRI funding reflects its misunderstanding of D.15-04-020, which was the Commission’s decision on SCE’s application for approval of proposed research projects in the Commission’s EPIC program. In that decision, the Commission denied SCE’s request to fund EPRI Program 60 research using EPIC funds, but the Commission did not take any action that extended beyond the EPIC program. Here, SCE states that it seeks renewed GRC-authorized funding because it was denied EPIC-authorized funding in D.15-04-020. There is nothing improper about SCE’s request. Indeed, the Commission previously approved SCE’s request for EPRI funding in its 2012 GRC decision, D.12-11-051,504 so it is logical and reasonable for SCE to seek this funding in this GRC proceeding. We approve SCE's 2018 O&M forecast of $5.470 million for Account 925 expenses associated with SCE's Corporate Health & Safety organization. 9.5. Corporate Security SCE states that its Corporate Security Operating Unit supports the reliability of the electric system by physically protecting SCE’s workforce, 503 SCE-29 at 315. 504 D.12-11-051 at 107, where the Commission approved SCE’s request for RD&D funding that included working with EPRI, stating “the Commission finds that the role RD&D plays in facilitating the [Advanced Technology Organization’s] mission justifies an expanded role [for RD&D].” - 229 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 customers, facilities, and infrastructure from threats, disruptions, intrusions, theft, and property damage. SCE forecasts $26.906 million in Corporate Security O&M expenses for Test Year 2018.505 SCE’s O&M forecast was uncontested, and we approve it here. SCE’s original capital expenditure forecast for the 2016-2018 period included a preliminary estimate for 2016 recorded expenditures of $24.414.506 In its rebuttal testimony, SCE agreed with ORA to use final 2016 recorded capital expenditures of $19.261 million. This brings all parties into agreement. We approve the uncontested recorded and forecast capital expenditure values shown in the table below: Adopted 2016-2020 Recorded and Forecast Corporate Security Capital Expenditures Nominal $000s Project Title NERC CIP-014 NERC CIP V6 Low BES Sites Physical Security Systems Non-Electric Facilities (Blanket) Physical Security Systems Electric Facilities (Blanket) Asset Management Total Project No COS-00-CS-CS-782000 2016 2,183 COS-00-CS-CS-745700 COS-00-CS-CS-SS 2017 16,494 2018 2019 2020 Total 18,677 8,525 811 9,477 9,755 10,034 10,320 56,652 1,000 1,000 1,000 1,000 4,000 12 4,169 10,814 11,065 11,832 37,892 19,261 39,666 22,380 22,098 23,153 126,558 17,066 CIT-00-DM-DM-000067 COS-00-CS-CS-745400 9,336 COS-00-CS-CS-745600 505 SCE-23, Vol. 1, at 24, Table IV-16 (Corporate Security 2018 O&M Forecast by FERC Account, Summary of SCE, ORA, and TURN Positions, Constant 2015 $000). 506 SCE-07, Vol. 5, Table V-2 (Corporate Security Capital Expenditures Forecast Summary, Nominal $000s). - 230 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 9.6. Supply Management SCE’s Supply Management (SM) organization provides materials procurement, logistics, and support services for the utility. The organization also commissions a wide variety of services that directly or indirectly serve construction, generation, transmission, distribution, substation, customer service, administration and other support activities. SCE states that although most of the expenses associated with SM are allocated to the Operating Units via internal processes, several SM departments are supported through O&M. SCE’s 2018 Test Year O&M forecast for the SM organization is $6.1 million, which represents no change from 2015 spending levels (in constant 2015 dollars). This request is uncontested, and we adopt it here. SCE’s 2016–2020 capital expenditure forecast for the SM organization equals $2.2 million, of which $365,000 is for Test Year 2018. These expenditures will support warehouse improvements, technology application hardware, and more sustainable and economical materials-handling equipment. SCE’s original capital expenditure forecast for the 2016–2020 period included a preliminary estimate for 2016 recorded expenditures of $555,000.507 In its rebuttal testimony, SCE agreed with ORA to use final 2016 recorded capital expenditures of $198,000. This brings all parties into agreement. We approve the uncontested recorded and forecast capital expenditure values shown in the table below: 507 SCE-07, Vol. 6, at 18, Table VII-1 (Warehouse Equipment and Materials Management Capital Projections, 2016-2020 Forecast). - 231 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Adopted 2016-2020 Recorded and Forecast Supply Management Capital Expenditures Nominal $000s Project No. 2016 2017 2018 2019 2020 Total COS-00-SC-SC-FE 198 563 365 371 378 1,875 9.7. Supplier Diversity SCE’s Supplier Diversity and Development Department (SDD) manages the Company’s efforts to procure materials and services from diverse business enterprises (DBEs). This encompasses women, minority, disabled veteran (WMDV), and lesbian, gay, bisexual and transgender (LGBT) owned business enterprises, as well as the Company’s efforts to comply with the CPUC’s General Order 156 (GO 156). The Department is also responsible for the Company’s initiatives and programs to foster the success of DBEs. SCE’s 2018 Test Year O&M forecast for the SDD organization is $3.387 million.508 This request is uncontested, and we adopt it here. The NDC recommends that SCE set aspirational goals of 42.9% for outside contracting and procurement spend from DBEs and 25.5% for minority business enterprises (MBEs), based on SCE's three-year average (2013-2015) performance.509 SCE responded in rebuttal that pursuant to Section 8 of GO 156, each utility (rather than the Commission or another party) shall determine its short-, 508 SCE-07, Vol. 8 for FERC Accounts 920/921 and 923. 509 NDC-01, at 24-28. - 232 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 mid-, and long-term goals for the use of DBEs.510 We agree and therefore decline to direct SCE to set additional aspirational goals as NDC recommends. 9.8. Transportation Services SCE’s Transportation Services Department (TSD) manages the SCE vehicle and equipment fleet, which includes passenger cars, vans, pick-up trucks, forklifts, heavy-duty trucks with aerial equipment (buckets and cranes), loaders, tractors, stringing equipment, trailers, and helicopters. 9.8.1. Operating Costs TSD's operating costs fall into four categories: Fleet Ownership, Fleet Maintenance, Fuel, and Aircraft Operations. These costs are charged back to other SCE OUs that require and utilize fleet support and embedded within the O&M and capital forecasts of those OUs. TSD's testimony does not separately request recovery for these costs. 9.8.1.1. Non-Fuel Operating Costs SCE forecasts $109.381 million (nominal) in Test Year 2018 for TSD's non-fuel operating costs comprising the following categories: Fleet Ownership, Fleet Maintenance, and Aircraft Operations.511 TURN recommends a 2018 forecast of TSD's non-fuel operating costs by using a four-year average of SCE's recorded costs in nominal dollars from 2013-2016 as TSD's non-fuel operating costs have held relatively steady. In rebuttal, SCE agreed to accept TURN's recommendation, subject to the use of constant dollars. TURN utilized nominal dollars to yield a forecast of 510 SCE-23, Vol. 1, at 31-32. 511 SCE-23, Vol. 1A, at 37A (Table VII-25). - 233 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $102.420 million. As TURN's recommendation applies an averaging methodology to historical operating costs, such a methodology should be applied to constant dollar historical expenses because those costs are normalized for comparison. Specifically, converting the historical costs to 2015 constant dollars normalizes escalations in spend due to inflationary pressures. When TSD's historical non-fuel operating costs are normalized to constant dollars, a four-year average of $103.072 million (2015 constant dollars) is derived from years 2013-2016. SCE requests that the Commission conclude that SCE's modified forecast of $103.072 million in TSD non-fuel operating costs for Test Year 2018 is reasonable. 9.8.1.2. Fuel Operating Costs TSD's fuel operating costs consist of costs to procure gas, diesel, oil, propane and fuel pumping services. These fuel costs are also charged back to other SCE OUs, and TSD's testimony does not separately request recovery for them. In its direct testimony, SCE utilized the 2015 version of the Department of Energy's Energy Information Administration (EIA) Annual Energy Outlook to forecast gas and diesel fuel costs. This supported a total combined gas and diesel fuel cost forecast of $18.353 million. In its rebuttal testimony, SCE accepted TURN's recommendation to use the 2016 version of the EIA Annual Energy Outlook to update projections of its forecast gas and diesel fuel costs. This reduced the total combined fuel cost forecast to $15.654 million.512 512 SCE-23, Vol. 1A at 36A, Table VII-24. - 234 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN also recommends reduction of SCE’s forecast Test Year 2018 fuel costs by the amount of outside fuel pumping service costs, $1.55 million, which would result in a total forecast equal to $14.101 million. We see no need to delve this deeply into SCE’s day-to-day frontline operations, and approve SCE’s forecast amount for outside fuel pumping service costs. Therefore, we approve the total value jointly calculated by SCE and TURN for Test Year 2018 fuel operating costs, $15.654 million. 9.8.2. Capital SCE states that TSD’s capital request is driven by the activities of vehicle electrification program, electric vehicle (EV) fleet chargers, vehicle leasehold capital improvements, garage tools and equipment, aircraft operations, and helicopter lease buyouts. SCE’s capital expenditure forecast for those categories is summarized in the table below: Transportation Services Department Capital Forecast513 (Nominal $000) 2016 Vehicle Electrification Program Electric Vehicle Fleet Chargers Vehicle Leasehold Capital Improvements Garage Tools and Equipment Aircraft Operations Program Helicopter Lease Buyout Total COS-00-TS-TS-VP6943 2017 2018 2019 2020 Total 384 339 292 216 1,230 COS-00-TS-TS-FE0000 20 138 160 166 173 658 COS-00-TS-TS-VP6942 148 3,053 1,989 1,181 1,208 7579 COS-00-TS-TS-TS0001 410 781 464 482 502 2,639 COS-00-TS-TS-AIR001 883 956 1,351 1,261 460 4,911 1,614 4,955 3,185 6,925 9,257 6,568 COS-00-TS-TS-267202 1,461 513 9,754 2,558 26,770 SCE-07, Vol. 7, at 14, Table V-5 (Transportation Services Department Capital Forecast). This table includes updated recorded 2016 capital expenditures - 235 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s original capital expenditure forecast for the 2016-2018 period included a preliminary estimate for 2016 recorded expenditures of $2.504 million. In its rebuttal, SCE agreed with ORA to use final 2016 recorded capital expenditures of $1.461 million. This brings all parties into agreement. We approve the uncontested recorded and forecast capital expenditure values shown in the table above. 10. Administrative & General 10.1. Ethics and Compliance SCE forecasts A&G expenses for Ethics and Compliance for 2018 of $9.863 million.514 ORA reviewed and analyzed SCE’s proposed Ethics and Compliance A&G expense and has no objection to SCE’s $9.863 million request. We find the request to be reasonable, and approve it. 10.2. Regulatory Affairs 10.2.1. Regulatory Affairs Labor: FERC Account 920/921 SCE forecasts $15.214 million of Test Year 2018 expenses for its Regulatory Affairs Department in FERC Accounts 920/921, a decrease of $0.881 million over recorded 2015 cost levels.515 SCE contends the decrease results from SCE’s efforts to achieve efficiencies, optimize spending, and reduce costs.516 TURN proposes an additional reduction of over $2 million based on removing funding for 18 purportedly vacant positions.517 SCE however, has 514 SCE-24, Vol. 1, at 27, Table IV-13. 515 SCE-24, Vol. 01, at 1-6. 516 Id. 517 TURN-07, at 5, lines 12-21. - 236 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 established the forecast is based on actual, recorded costs, and does not include funding for vacant positions.518 We adopt as reasonable SCE’s forecast of $15.214 million of Test Year 2018 expenses for its Regulatory Affairs Department in FERC Accounts 920/921. 10.2.2. Regulatory Affairs – Integrated Planning Power Procurement: FERC Account 557 SCE forecasts $10 million for Test Year 2018 for Integrated Planning Power Procurement, FERC Account 557.519 SCE used the Last Recorded Year as the forecast method. TURN proposes to reduce the forecast by $1.590 million based on the contention these costs are associated with SCE’s discontinued Project Development Division (PDD).520 SCE, however, has established these costs are for continuing activity related to electric system modeling and not a discontinued division.521 We adopt SCE’s forecast. 10.3. Corporate Communications 10.3.1. Corporate Communications Operations Labor: FERC Account 920/921 SCE forecasts $5.071 million of Test Year 2018 expenses for its Corporate Communications Operations Department in FERC Accounts 920/921, a decrease of $2.684 million over recorded 2015 cost levels.522 TURN proposes an additional reduction of over $0.349 million based on removing funding attributed to four purportedly vacant positions.523 SCE 518 SCE-24, Vol. 1, at 2:24-26 and at 6:14-16. 519 SCE-24, Vol. 1, at 7:2-3. 520 TURN-07, at 7-8. 521 SCE-24, Vol. 1, at 8:13-26. 522 SCE-24, Vol. 01, at 10, lines 3-6. - 237 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 however, has established the forecast does not include vacant positions and we adopt it as reasonable. 10.3.2. Corporate Communications – Outside Services: FERC Account 923 SCE forecasts $1.689 million for FERC Account 923 for: 1) ethnic media services; 2) communications measurement; and 3) communications quality assurance.524 The forecast is based on 2015 recorded costs, less a decrease of $1.134 million due to Operational Excellence reductions.525 After review and analysis of SCE’s rebuttal, TURN withdraws its recommendation to disallow all costs in this account.526 We find the forecast to be reasonable and approve it. 10.4. Local Public Affairs 10.4.1. Local Public Affairs – FERC Account 920/921 SCE forecasts $7.904 million for Test Year 2018 for Local Public Affairs, FERC Account 920/921. These activities include engagement with governments and stakeholders throughout SCE territory.527 The amount is not disputed; we approve the forecast. NDC however, urges we require SCE to host at least five capacity building workshops annually for community-based organizations. These workshops were intended to inform and educate customers and community organizations 523 TURN-07, at 5, lines 12-21. 524 SCE-24, Vol. 01, at 12: 13-19. 525 Id. at 13, lines 1-2. 526 TURN Opening Brief, at 203. 527 SCE-08, Vol. 2, at 53: 1-13. - 238 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 about company programs and initiatives.528 SCE discontinued these workshops in 2015 following a reorganization and determination that the workshops are not core to the Local Public Affairs’ function.529 Although NDC establishes the workshops were well attended and inexpensive and would likely continue to be,530 NDC does not establish a basis for requiring these workshops; we decline to order them. 10.4.2. Corporate Membership Dues and Fees – FERC Account 930 SCE forecasts $1.920 million of non-labor expenses for FERC Account 930 for the ratepayer funded portion of dues and memberships costs, based on the last recorded year, after making limited concessions.531 SCE’s “concession” removed fees and memberships totaling $52,595 for California Foundation on the Environment and the Economy, California Small Business Association, and Committee Encouraging Corporate Philanthropy.532 ORA recommends $1.177 million, the same funding level adopted in the Test Year 2015 GRC, a 40% reduction from SCE’s request, based on the last recorded year of membership fees and dues.533 ORA’s limited rationale does not undermine SCE’s showing. 528 NDC-01 Attachment, at 26, NDC-SCE-004, Question 02. 529 Ibid. 530 NDC-01, at 29-30. 531 SCE-24, Vol. 01, at 21:7-18 and Table III-11. 532 SCE-24, Vol. 01, at 21:9-18. 533 ORA-17, at 14-15. - 239 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN recommends a reduction of $1.805 million (to $168,701) based on eliminating funding of memberships dues and fees for: the Edison Electric Institute (EEI), California Taxpayer Association, Business Roundtable, California Small Business Association, and California Small Business Roundtable.534 SCE provides a description of EEI activities and relies on the EEI invoice to support its contention that SCE is properly seeking recovery of $1,552,609 from ratepayers of the EEI invoice which totals $1,916,700.535 We agree with SCE that EEI may provide some beneficial services. We recognize the EEI invoice provides guidance to its members as to an allocation between shareholders and ratepayers for payment and that SCE allocated less to ratepayers than what is suggested by the EEI invoice. The EEI invoice however, is insufficient evidence to establish the portion of the invoice which should be recovered from ratepayers. SCE has failed to present supporting evidence which would enable us to determine how much EEI’s beneficial services should cost ratepayers. We find SCE has not met its burden to establish any portion of the EEI dues are recoverable from ratepayers. TURN also recommends removing funding for California Taxpayer Association, Business Roundtable, California Small Business Association, and California Small Business Roundtable. SCE has not established the ratepayer benefits of supporting these organizations and therefore we do not authorize ratepayer funding for them. Accordingly, we approve a forecast of $168,701 534 TURN-02, at 42-47. 535 SCE-24, Vol. 01, at 21-23. - 240 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 FERC Account 930 for the ratepayer funded portion of dues and memberships costs. 10.5. Financial Services SCE’s 2018 forecast for the Financial Services Department includes: $43.3 million for Accounts 920/921 and $20.9 million for Accounts 923/930.536 Generally, intervenors did not oppose SCE’s forecasts for Financial Services, excepting TURN’s proposals for these accounts. SCE’s Financial Services labor costs (Accounts 920/921) have been steadily declining, from $64.0 million in 2011 to $42.9 million in 2015. SCE forecasts a further decline to $38.5 million for its 2018 Test Year forecast.537 TURN proposes an additional reduction of $2.308 million. TURN bases this proposal on the value it proscribes to 22 purportedly vacant positions in the department.538 Although SCE acknowledges there have been vacancies, SCE establishes that its forecasts are based on actual costs and reflect reductions that have already taken place from implementing its Operational Excellence efforts.539 Financial Services Accounts 923/930 encompass three primary functions: outside services in support of accounting, financial institution fees, and accounts payable vendor discounts. SCE’s forecast of $20.9 million represents a 58% reduction from its 2015 recorded expense of $49.2 million.540 SCE’s reduced forecast is reportedly due to reduced consulting needs for Operational 536 Table I-1, SCE-08, Vol. 3, at 2. 537 Table II-2, SCE-24, Vol. 2, at 3. 538 TURN-07, at 15-16. 539 SCE-24, Vol. 2, at 3-7. 540 Table II-4, SCE-24, Vol. 2, at 8. - 241 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Excellence, increasing internal expertise of the Tax department, and an increase in Accounts Payable vendor discounts.541 TURN proposes a further reduction of $7.665 million to $13.251 million, based on the five year average of expenses for this account and application of SCE’s proposed reduction to TURN’s forecast. TURN uses the five-year average due to the wide variation between the Outside Services entries for 2011-2015, from a low of $23.814 million in 2014 to a high of $56.025 million in 2015.542 SCE insists its adjustment may only be applied to 2015 recorded expenses; however, SCE repeatedly discusses the variations in its historical expenses, averages and outliers.543 SCE’s arguments against a baseline based on the five-year average are not persuasive. Furthermore, averaging varying expenses is consistent with our practice. Therefore, we adopt TURN’s recommendation of $13.251 million for Financial Services Accounts 923/930. 10.6. Audits SCE forecasts $8.657 million for Account 920/921, which is based on $5.873 million for labor expenses and $2.784 million for non-labor expenses for the Audit Service Department in 2018.544 The forecast includes a nominal increase in the labor forecast over 2015 recorded expenses of $5.617 million. TURN 541 SCE-24, Vol. 2, at 9:9-17. 542 TURN-07, at 17; SCE-24, Vol. 2, at 9-10. 543 SCE-24, Vol. 2, at 9:7-8, “Included in SCE’s recorded amounts are consulting services to support our OpX program, which averaged $28.2 million over the last 5 years.” Id., at 9:12-15, OpX expenses of the past six years will not continue. SCE-08, Vol. 3, at 19:2-4, “Expenses related to outside consultants … were relatively flat from 2011-2014, with an increase of $5 million in 2015. 544 SCE-08, Vol. 3, at 40, Figure III-10. - 242 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 proposes a further reduction in the labor forecast of 50%, to $2.937 million. TURN, again, proposes this reduction based on eliminating 28 vacancies in a department of 56 employees. SCE, again, as it has in opposition to similar proposals from TURN, argues the forecast is based on recorded expenses and forecasted needs and not a “headcount.” SCE has met its burden; TURN’s argument is not persuasive. We adopt the SCE forecast of $8.657 million for the Audit Service Department in 2018. 10.7. Enterprise Risk Management The Commission’s Safety and Enforcement Division (SED) Staff analyzed and evaluated the risk-informed decision framework used by SCE to identify major risks and determine potential mitigation plans and programs and concluded that these methods and processes have not been particularly well described or effectively used to inform the 2018 GRC Test Year budget request. SCE admitted in testimony that it did not use risk assessment in the identification of its top risks, or to select programs to address those risks, but mostly after-the-fact as a way to measure risk reduction associated with the programs or projects proposed. Further, the funding allocation for risk mitigations was not based on risk analysis. These two admissions, by themselves, have made it very difficult for SED to provide a positive evaluation of risk assessment in this GRC application. At this time, it would be unwise to accept SCE’s risk assessment methods as a basis for determining reasonableness of safety-related program requests; indeed, we have found that SCE is classifying major categories of spending as safety related, even though they relate to issues of customer satisfaction or electric service reliability than safety. Additionally, much more could be done in the future to - 243 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 assist decision makers and intervenors in following the trail from risk assessment to budget request. The current GRC, although partly subject to the new risk-informed decision-making approach, is essentially a transitional case. We anticipate the risk assessment in the next GRC cycle will reflect considerable improvement. 10.8. Legal SCE proposes total costs for 2018 for SCE’s Legal Organization of $104.331 million, an increase of $20.884 million over 2015 recorded costs. The legal expenses include: $44.791 million for the Law Department (including Corporate Governance), $24.373 million for the Claims Department, $14.594 million for the Workers’ Compensation Department, and $20.573 million for Disability Management.545 10.8.1. Removal of Costs Resulting from Alleged Imprudence TURN recommends removing over $12 million of Legal Organization costs in the Law Department forecasts purportedly relating to five incidents TURN identifies as involving alleged imprudence. These incidents are the San Onofre Nuclear Generating Station (SONGS) replacement steam generator project, the 2007 Malibu wildfire, 2015 outages in Long Beach, 2011 fatalities in San Bernardino (Acacia), and the 2011 San Gabriel windstorm.546 We agree conceptually that ratepayers should not be charged for the defense of claims involving imprudence.547 Likewise, we are troubled by the idea 545 SCE-24, Vol. 3, at 3, Table I-2. 546 TURN-13, at 25-26. 547 D.14-06-007, at 31-32. - 244 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 of the utility being provided a blank check, paid by ratepayers, funding the defense of a claim, the defense of which is aimed, in part, at establishing the ratepayers are responsible. Nevertheless, we agree with SCE that we should not intrude “after-the-fact” into “matters that have already been finally resolved in Commission-approved settlements.”548 Each of these matters was resolved by an approved settlement.549 The agreements concerning San Bernardino and San Gabriel, despite being “complete and final resolution” of the issues did not assess shareholders with responsibility for attorneys’ fees. The Malibu settlement has been interpreted by SCE to require removal of outside counsel costs from its GRC but not in-house Legal or claims expenses and intervenors have not sought to exclude these costs.550 Although we question the merit of that interpretation, these in-house expenses were largely included and approved as part of the 2015 GRC and therefore, we will not re-open review of these expenses now.551 Likewise, a settlement of SONGS was adopted and legal expenses have been addressed separately. Given the status of the proceedings identified by TURN we do not agree (excepting regarding Malibu) that exclusion of those legal expenses would be proper at this time. Whether or not these legal expenses should be part of a forecast going forward however, is a different question.552 We find no benefit to ratepayers 548 SCE Opening Brief, at 193. 549 SCE-04, Vol. 03, at 8:3-9:9 [re.: Malibu, San Bernardino, and San Gabriel]. D.17-09-024 [re.: Long Beach]. 550 SCE-04, Vol. 03, at 8-9, fn. 12. 551 See SCE-04, Vol. 03, at 9:2-7 and fn. 13. 552 We note SCE has made adjustments to remove at least some costs it recognizes as “not appropriately included in customer rates.” SCE Reply Brief, at 123, fn. 849. - 245 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 requiring they support the defense of litigation which seeks to impose shareholder liability due to imprudence. We agree with TURN that costs incurred due to imprudent operations are not just and reasonable and are therefore, not recoverable.553 SCE criticizes TURNs methods but provides no alternative. We recognize TURN’s proposal to deduct 18.2% from forecast expenses for Outside Counsel and one-third from the forecast for In-House Counsel may be more of a shave than a reasonable haircut. We also recognize that defense costs may arise in cases in which the allegations of imprudence are unfounded or are mixed with potential liability despite prudent management. Therefore, we approve as reasonable a 10% reduction of the forecast for Outside Counsel. As for In-House Counsel, we also note SCE has, in a number of instances, renewed previously denied arguments without providing an explanation as to what has changed to warrant a different outcome in the present case.554 Therefore, we reduce the In-House forecast an additional 5% for a total of 15%. TURN further proposes SCE modify its internal guidance to require removal of costs due to imprudence. Although we agree SCE should not seek recovery of costs incurred due to imprudence, we are neither certain that TURN’s current proposal is an effective remedy nor do we find SCE to be persuasive in its discussion disavowing tracking attorney time and its refusal to consider anything other than incremental in-house costs.555 Although we decline to order changes to SCE’s internal guidance concerning the removal of costs for 553 TURN Opening Brief, at 215 and 220, citing D.14-06-007, at 31. 554 See, e.g., section 10.8.2.3, below. See also, D.12-11-051 at 494 and D.15-11-021, at 306-307. 555 SCE Opening Brief, at 197. - 246 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 imprudent activities, we consider greater transparency to be warranted and recognize recalcitrance by SCE in regards to this issue may undermine its showing in meeting its burden of proof in future GRCs. We therefore urge the parties meet and confer to explore this proposal further. During this process the parties should consider means to accurately determine the portion of In-House Counsel costs and other expenses which are incurred in connection with findings of utility imprudence. This consideration should include timekeeping or other means to accurately evaluate the allocation of expenses, notwithstanding our previous rejection of ORA’s predecessor the Division of Ratepayer Advocate’s suggestion that SCE be required to have a timekeeping system.556 10.8.2. Law SCE forecasts $44.791 million for the Law Department, consisting of $25.397 million for In-House, $15.292 million for Outside Counsel, and $4.102 million for Corporate Governance.557 10.8.2.1. In-House, FERC Accounts 920/921 SCE forecasts $25.397 million for FERC Accounts 920 and 921 based on declining expenditures due to Operational Excellence.558 ORA does not contest the forecast. TURN, as it has in other instances, recommends a reduction based on alleged vacancies and employee headcounts.559 Again, as we have concerning similar arguments, we find SCE’s forecast – regarding its basis on actual costs 556 D.09-03-025, at 151. 557 SCE-24, Vol. 03, at 4, Table II-3. 558 SCE-24, Vol. 03, at 13:1-2 and Table II-8. 559 TURN-13, at 19, in support of a $3.669 million reduction. - 247 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 and forecasted needs as reduced by Operational Excellence achievements – to be reasonable and supported by the evidence. Therefore, we apply the 15% reduction discussed in section 10.8.1, above, and we adopt a forecast of $21.587 million for In-House. 10.8.2.2. FERC Accounts 923/925/928 Outside Counsel SCE’s adjusted forecast for Outside Counsel is based on a five-year average of recorded costs for 2011-2015.560 ORA recommends removing 2013 costs as an outlier, and averaging the remaining four years, 2011-2012 and 2014-2015.561 TURN proposes using the last recorded year based on an alleged downward trend. The past five years, however, demonstrate unpredictability and not a downward trend. As we have in the past, we find there is inadequate support for including the outlying year and consequently we regard 2013 as an outlier and exclude it.562 Using SCE’s updated recorded history (in millions) of $16.299 (2011), $13.087 (2012), $14.197 (2014), and $12.118 (2015), provides a four-year average of $13.925 million.563 Applying the further 10% reduction discussed in section 10.8.1, above, we adopt a forecast of $12.532 million. 560 SCE-24, Vol. 03, at 4-5. 561 ORA-17, at 16-18. 562 D.15-11-021, at 306-307. ORA Opening Brief, at 211-212. 563 SCE-24, Vol. 03, at 13, Table II-8. - 248 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 10.8.2.3. FERC Account 930 Corporate Governance SCE’s forecast for this account is $4.1 million.564 As it has in past rate cases, SCE includes in its forecast, equity compensation. Also, as in past rate cases, we deny that portion of the request.565 TURN also challenges this forecast based on a misallocation of costs arising from unregulated activities.566 SCE has established its allocation of costs is proper. On the foregoing bases, we adopt a forecast of $3.1 million. 10.8.3. Claims SCE forecasts $24.373 million for the Claims Department. This forecast consists of $3.025 million for Administrative Expenses (FERC Accounts 920/921/924) and $21.348 million for Claims Reserves (FERC Account 925).567 The forecast for Administrative Expenses is based on the 2015 recorded costs. ORA does not dispute this forecast. TURN proposes a $0.957 million reduction due to imprudence.568 Although we have recognized the merit of TURN’s argument in other instances, we find the Claims Department responsibility for investigating and evaluating accidents and other events supports adopting the entirety of SCE’s Administrative Expense forecast of $3.025 million. 564 SCE-24, Vol. 03, at 16:1-2 and Table II-9. 565 D.15-11-021, at 308-309. D.12-11-051 at 494. See, ORA-17, at 16 recommending disallowance of $997,726. 566 TURN-03, at 30. 567 SCE-24, Vol. 03, at 18:1-8 and Table III-10. 568 TURN-13, at 22-24, Tables 4 and 6. - 249 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The $21.348 million forecast for Claims Reserves is based on a five-year average of historical costs from 2011-2015. During that time the recorded costs have varied wildly (in millions): $8.750 (2011), $18.901 (2012), $36.869 (2013), $35.244 (2014), and $6.978 (2015). Given the wide variation, it is doubtful a simple average is a reliable predictor. SCE describes these reserves as representing “the Company’s estimate of potential exposure on known events.”569 SCE has not established it is fair and reasonable to rely on a five-year average of historical costs to establish its forecast for Claims Reserves. ORA recommends normalizing the average by eliminating large claims in 2013 and 2014, resulting in a forecast of $14.948 million.570 TURN recommends using 2015, the last recorded year, and imposing an additional reduction for imprudence, resulting in a forecast of $4.978 million. This proposal generates a forecast less than any actual recorded expense from 2006 through 2015, except one.571 We find ORA’s proposal to be the most fair and reasonable based upon the evidence presented, including consideration of a reduction for imprudence as advocated by TURN, and we adopt a forecast of $14.948 million for Claims Reserves. 10.8.4. Workers’ Compensation SCE forecasts $14.594 million for the Workers’ Compensation Department. This forecast consists of $6.783 million in administrative expenses and $7.811 569 SCE-08, Vol. 04, at 25:3-6. 570 ORA-17, at 18. 571 SCE-24, Vol. 3, at 22, Table III-13. - 250 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 million in Workers’ Compensation reserves.572 Neither ORA nor TURN challenge the forecasted administrative expense. SCE bases the reserve expense on a three-year average of 2013-2015. TURN agrees to the exclusion of 2011 and 2012 (recorded costs were significantly higher in those years) but recommends a four-year adjusted average which includes 2016.573 The adjustment, a reduction of $.117 million for Four Corners is not objected to by SCE. SCE does contend the use of 2016 is inappropriate as the costs were unusually low and have not been adjusted. We accept SCE’s contention and average the Workers’ Compensation Reserve expense, as adjusted by TURN for 2013-2015 (in millions): $8.5, $9.641, and $5.178. Therefore, we adopt a forecast of $7.773 million. 10.8.5. Disability Program SCE’s forecast of $833,000 for Disability Administration is not disputed and is adopted.574 SCE forecasts $19.74 million for its Disability Program for 2018.575 The disability program provides income protection if an employee becomes ill or injured and unable to work and assistance for employees who are not totally disabled but are unable to return to their prior positions. The program costs include payments made to employees and reserves for the Comprehensive 572 SCE-24, Vol. 03, at 26:4-6 and Table IV-14. 573 TURN-03, at 33. 574 SCE-24, Vol. 03, at 29:1-30:6. 575 SCE-08, Vol. 04A, at 35, Table V-11. - 251 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Disability Plan (short-term disability), Long-Term Disability Plan, the Return to Work Program, Paid Family Leave, and external administration costs.576 This forecast is based on forecast labor costs, employee counts, recorded benefit programs expenses and escalation rates following recognition of the reasonableness of this approach in the last rate case decision.577 ORA forecasts $16.9 million for the Disability Program, based on SCE’s 2015 Recorded Year.578 TURN’s forecast is $17.6 million based on a five-year average.579 TURN contends SCE’s forecast for the disability program has not rendered accurate projections and we are inclined to agree. SCE’s testimony establishes SCE has consistently overstated the number of its employees in its forecast.580 From 2012-2016 SCE overstated its authorized number of employees over recorded by no less than 12%. Therefore, we accept SCE’s methodology but we find a 10% reduction for the 2018 forecast for the Disability Program (due to the overstating of employees) to be reasonable and adopt a forecast of $17.766 million.581 576 Id. at 37-38. 577 SCE-24, Vol. 03, at 32:1-5; D.15-11-021, at 274. 578 ORA-17, at 20-21. 579 TURN-07, at 27-28. 580 SCE-24, Vol. 3, at 33, Tables V-20 and V-21. 581 This adopted amount is illustrative and may not batch the final amount because it is dependent on the number of employees and labor expenses approved by this decision. - 252 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 10.9. Property and Liability Insurance 10.9.1. Property Insurance SCE accepts ORA’s and TURN’s recommended property insurance expense forecast of $14.070 million for Test 2018 (a reduction of $2 million from SCE’s original forecast)582 and we adopt it as reasonable. 10.9.2. Liability Insurance SCE forecasts $92.427 million for total liability insurance expense in Test Year 2018. SCE states its forecast is based on premium estimates from its insurance broker and reflect expected market conditions and SCE’s loss history.583 ORA and TURN base their recommendations on the last year recorded. We find SCE’s continuing reliance on an expert forecast is reasonable and adopt the forecast of $92.427 million. 11. Ratemaking Proposals SCE requests approval of several GRC-related ratemaking proposals related to its Commission-jurisdictional base-related revenue requirement. We address the proposals contested by other parties here. In addition, SCE provided a list in its opening brief of its memorandum account and balancing account proposals that are uncontested, and requests approval of each of the uncontested proposals. 11.1. Establishment of the DER Deferred Project Memorandum Account (DERDPMA) SCE has withdrawn its request to establish the DERDPMA.584 582 SCE-24, Vol. 4, at 4:1-6. 583 SCE-24, Vol. 4, at 5:3-6. 584 SCE-25, Vol. 1, at 6. - 253 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 11.2. Establishment of the Public Utilities Code § 706 SCE Officer Compensation Memorandum Account (SOCMA) As we discussed in the HR section of this decision, SCE’s request to establish this memorandum account has been mooted by statutory changes enacted after SCE made this proposal in its September 2016 application. 11.3. Modification of the Pole Loading and Deteriorated Pole Programs Balancing Account (PLDPBA) The PLDPBA is a two-way balancing account established pursuant to D.15-11-021. This account records the difference between: (1) recorded capital-related revenue requirements for the Pole Loading Program and the Deteriorated Pole Program, (2) Operation and Maintenance (O&M) expenses for the Pole Loading Program, and (3) the authorized Pole Programs revenue requirement as adopted in D.15-11-021. The level of expenditures to be recovered in the PLDPBA in 2016 and 2017 is capped at 15% above the authorized levels. SCE requests authorization to continue the two-way PLDPBA over the 2018 GRC period, but without a cap on expenditures. ORA opposed removing the cap, while TURN recommended eliminating the 15% headroom and changing the account to a one-way account. We addressed SCE’s request earlier in this decision, in the Poles sub-section of the T&D section. We determined that the current account structure should continue for this GRC cycle, with no changes in its structure. 11.4. Modification of the Safety and Reliability Investment Incentive Mechanism (SRIIM) In its direct testimony, SCE proposed to maintain the SRIIM over the 2018 GRC cycle, with certain modifications to portions of the capital spending categories and staffing components. CUE proposed certain changes to SRIIM, - 254 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 which SCE addressed in its rebuttal testimony. We resolved the differences between SCE and CUE in the T&D section of this decision, where we also authorized SCE to make the necessary modifications to Preliminary Statement Part LL to include the new authorized SRIIM program capital-related and staffing target amounts, besides other necessary changes to the tariff.585 11.5. ORA’s Proposal to Establish a One-Way Storms Balancing Account In the section of this decision addressing T&D Distribution Construction and Maintenance, we denied ORA’s proposal to create a one-way balancing account for Distribution Storm Expenses (FERC Sub-Account 598.170). 11.6. ORA’s Recommendation to Establish a Grid Modernization Memorandum Account In this proceeding, ORA recommends that the Commission deny SCE’s requests for Grid Modernization funding entirely. However, ORA also recommends that the Commission establish a Grid Modernization Memorandum Account whereby any related costs incurred by SCE would be tracked and could be funded in subsequent rate cases based on a determination that SCE’s expenditures were reasonable. We find that ORA’s proposal is moot because this decision addresses the details of SCE’s Grid Modernization proposals, specifically authorizing some while denying others, so there is no need to track SCE’s expenditures for possible future recovery. 585 See SCE-09, Vol. 1, at 40. - 255 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 11.7. ORA’s Recommendation to Establish a DER Memorandum Account A recurring theme throughout ORA’s testimony is that SCE’s requests for funding for DER -related projects is premature because a number of open policy-making proceedings at the Commission have yet to provide definitive direction to the utilities to guide their investments. For this reason, ORA recommends that SCE’s spending on DER-related projects be recorded in a memorandum account created for that purpose (ORA suggests that, alternatively, these costs could be tracked in its recommended Grid Modernization memorandum account). We find that ORA’s proposal is moot because we have addressee SCE’s funding requests for DER-related projects directly, as part of our discussion of distribution automation, where we adopted TURN’s recommendation for lower funding levels for DER-related distribution. Therefore, there is no need to order SCE to track these authorized expenditures in a memorandum account. 11.8. ORA’s Recommendation to Establish a Customer Service (CS) Re-Platform Memorandum Account ORA does not object to SCE’s implementation of its CS Re-Platform project, but questions some funding requests as well as the overall timing for completion of the project. ORA recommends that that SCE be required to track costs for the CS Re-Platform in a memorandum account. In the section of this decision addressing SCE’s Information Technology forecasts, we directed SCE to establish a memorandum account to track its CS Re-Platform project costs for review in the next GRC. - 256 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 11.9. CALSLA’s Recommendation to Establish a Balancing Account to Record Tax Losses and Profits from Street Light Sales In section 24 of this decision, we address all the contested issues between SCE and CALSLA, including CALSLA’s recommended balancing account. 11.10. Uncontested Proposals for Memorandum Accounts and Balancing Accounts SCE provided a list in its opening brief of its memorandum account and balancing account proposals that are uncontested, and requests approval of each of the uncontested proposals. We approve each of the proposals listed below. - 257 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Southern California Edison 2018 GRC Uncontested Balancing and Memorandum Account Proposals Line Account Medical Programs Balancing Account (MPBA) SCE Proposal ORA Position Retain 2-way account Uncontested 2 Pension Costs Balancing Account (PCBA) Retain 2-way account Supports continuation of the account (ORA-21) 3 Post-Employment Benefits Other than Pensions Costs Balancing Account (PBOP BA) Retain 2-way account Uncontested 4 Results Sharing Memorandum Account (RSMA) Retain 1-way account / rename “STIPMA” and Capitalize using SCE's proposed P&B capitalization rate Uncontested 1 5 6 7 8 9 10 11 12 13 Does not oppose continuation of the account (ORA-02) Recover 12/31/17 balance; Does not object to Residential Rate SCE's proposal Implementation Memorandum 2018-2020 annual recovery in (ORA-22) Account (RRIMA) for TOU Pilot ERRA Review proceeding Does not object to Energy Data Request Program Eliminate account and recover SCE's proposal Memorandum Account 12/31/17 balance (ORA-22) (EDRPMA) Marine Corps Air Ground Eliminate account and allocate Does not object to Combat Center Memorandum $1M after-tax gain to SCE's proposal Account (MCAGCCMA) shareholders (ORA-22) Project Development Division Does not object to Memorandum Account Eliminate account SCE's proposal (PDDMA) (ORA-22) Does not object to Residential Service Eliminate account and recover SCE's proposal Disconnection Memorandum 12/31/17 balance (ORA-22) Account (RSDMA) Does not object to SmartConnect Opt-Out Eliminate account and recover SCE's proposal Balancing Account (SOBA) 12/31/17 balance (ORA-22) Does not object to Bark Beetle CEMA Recover $10M in 2012- 2014 costs SCE's proposal (ORA-22) Does not object to Customer Data Access (CDA) Cease entries to BRRBA SCE's proposal Costs (ORA-22) Tax Accounting Memorandum Account (TAMA) Retain 2-way account through 2018 GRC period - 258 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 12. Jurisdictional Issues In GRC proceedings such as this one, SCE presents its forecasts and spending requests at either a “total company” or “CPUC-jurisdictional” level. Total company costs include some FERC-jurisdictional transmission-related operating and capital costs, which are recovered through rates authorized by the FERC.586 In order to determine the CPUC-jurisdictional revenue requirement to be recovered through CPUC-authorized rates, SCE uses a Commission-approved methodology to calculate factors to allocate total company costs between CPUC and FERC jurisdiction.587 SCE presents those allocation factors in SCE-09, Table IV-6. SCE’s calculations are unopposed. We adopt SCE’s uncontested jurisdictional allocation factors. 13. Sales and Customer Forecast SCE provides three separate but related forecasts for the 2016-2020 period in its testimony: retail electricity sales, customer accounts, and new meter connections.588 The Commission’s determination regarding the appropriate level of these forecasts indirectly affects a number of SCE’s revenue requirement requests. In SCE’s Test Year 2015 GRC, the Commission adopted a reduction to SCE’s forecast for new meter connections. The Commission then applied that 586 The FERC has jurisdiction over the California Independent System Operator (CAISO) controlled portion of SCE’s T&D system. The CPUC has jurisdiction over the remaining T&D system as well as all the generation facilities owned by SCE. See ORA-02 at 1. 587 D.04-07-022. The Commission subsequently adopted jurisdictional factors derived from this methodology in the four SCE GRC proceedings prior to the instant proceeding (SCE-09, Vol. 1, citing D.06-05-016, D.09-03-025, D.12-11-051, and D.15-11-021). 588 SCE-09. - 259 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 reduced meter forecast to SCE’s original forecast of customers, thereby reducing that forecast as well. Finally, the Commission stated “assuming that energy sales per customer are the same as in SCE’s retail sales forecast, we calculate [a reduced] forecast of energy sales, based on [our adopted] forecast of customers. We adopt [that] forecast.”589 13.1. Retail Electricity Sales SCE provides the following sales forecast in its direct testimony.590 Annual Retail Sales by Customer Class (GWh) 2015 2016 2017 2018 2019 Residential 30,093 29,100 28,527 27,722 27,245 Agricultural 1,869 1,416 1,466 1,499 1,542 Commercial 42,396 41,039 41,567 42,086 42,705 Industrial 7,623 8,054 8,059 7,888 7,731 Public Authorities 4,875 4,702 4,634 4,377 4,248 Total Retail Sales 86,856 84,312 84,253 83,572 83,470 2020 26,584 1,565 42,826 7,498 4,094 82,567 SCE states that the forecast decline in sales between 2015 and 2016 is primarily due to (1) an assumption of normal weather in 2016, compared to the hotter-than-normal weather experienced in much of SCE’s service area during summer 2015; and (2) increased behind-the-meter (BTM) solar PV generation. SCE also states that “the economy has recovered slowly following the 2007-2009 Great Recession but is projected to pick up with the anticipated housing recovery over the next few years within SCE’s service territory” however “the rapid 589 D.15-11-021 at 380. 590 SCE-09, Vol. 1, Table V-21: “Annual Retail Sales by Customer Class.” - 260 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 increase in customer adoption of BTM solar PV systems has reduced customer need for utility-supplied energy.”591 No party disputes SCE’s sales forecast. 13.2. Customer Accounts and New Meter Connections All parties agree that SCE’s forecast “of new customers and new meter connections follows closely the housing market cycle.”592 SCE’s forecast of new residential meters is primarily driven by forecasted new housing starts, which are considered to be a leading economic variable with respect to new customers. SCE obtains housing start data from Moody’s Analytics. In turn, SCE’s forecast of new commercial customers is assumed to be influenced by changes in the number of residential customers. Finally, SCE’s forecast of the costs of its customer-driven programs are driven by (1) the forecast of new meter sets and (2) SCE’s forecast of the associated unit costs. We addressed SCE’s cost forecasts in Section 4 of this decision, where we noted that those forecasts depended upon our determinations here regarding SCE’s customer and new meter forecasts. SCE provides the following forecast of customer account growth in its direct testimony.593 Neither ORA nor TURN contest SCE’s forecasts. 591 Id. at 62. 592 TURN-11, at 21, citing SCE-9, Vol. 1, at 69. 593 Id., Table V-22: “Year-End Customers by Customer Class.” - 261 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Year-End Customers by Customer Class 2016 2017 2018 2015 4,393,150 4,420,391 4,451,253 4,486,121 21,306 21,180 21,065 20,948 561,475 568,091 575,324 582,516 10,811 10,766 10,718 10,651 46,588 46,548 46,551 46,606 5,033,330 5,066,977 5,104,911 5,146,843 Residential Agricultural Commercial Industrial Public Authorities Total Customers 2019 4,521,495 20,830 589,761 10,556 46,703 5,189,344 2020 4,556,502 20,708 596,975 10,439 46,828 5,231,452 SCE provides the following forecast of new meter connections in its direct testimony.594 Both ORA and TURN recommend alternative forecasts. Comparison of New Meter Connections Forecasts from SCE, ORA, and TURN SCE 2016 2017 2018 2019 2020 ORA TURN Residential Commercial Residential Commercial Residential Commercial 29,895 33,532 41,702 43,438 42,801 6,092 6,666 6,825 7,665 8,188 27,892 34,069 39,912 41,378 42,229 5,354 5,904 6,135 6,210 6,274 31,142 34,013 36,388 37,955 37,729 6,092 6,697 7,045 7,350 7,534 ORA, like SCE, bases its forecast on a regression model, but differs from SCE regarding the proper structure of the model. ORA argues that because its model is more methodologically sound, the resulting forecast should be adopted by the Commission. TURN’s forecast was produced by SCE’s regression model, with inputs requested by TURN. TURN’s recommendation reflects those modeling results as 594 Id., Table V-23: “New Meter Connections.” - 262 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 well as TURN’s analysis of the accuracy of SCE’s forecasts in previous GRC proceedings. TURN states that it has analyzed SCE’s forecasts, and the resulting actual, customer-driven costs over the last two GRC cycles and found that the company’s forecasts contain a relatively consistent upward bias:  In the Test Year 2012 GRC, SCE over-forecast actual costs by around $50 million for 2011-2012.595  For 2014-2015, SCE over-forecast actual costs of residential connections by $143 million.  For 2014-2015, SCE over-forecast actual commercial customer-driven costs by around $41 million.596 Based on this analysis, TURN concludes that while it recognizes the overall growth trend in housing starts, it recommends adjusting the housing start input to SCE’s regression model to reflect the average growth rate in actual housing starts from 2014-2016.597 At TURN’s request SCE made this single change to its regression model to calculate new residential meter sets, which allows us to compare SCE’s forecast with TURN’s modification to that forecast in the chart below: 595 TURN-11, at 25. 596 Id. at 26. 597 Id. at 31. - 263 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE responds to ORA and TURN in its rebuttal testimony and briefs. SCE faults ORA’s modeling results, contending that ORA’s model not only significantly under-forecasts SCE’s new residential meters in 2016 but also performs worse than SCE’s model.598 SCE primarily objects to ORA’s underlying assumption that it takes 36 months from the start of home construction to the meter connection date, twice as long as SCE assumes in its model. As an example, SCE contends that this caused ORA to use housing starts data from 2013 to forecast new meter connections in 2016. SCE suggests that “incorporating actual 2016 meter data will produce a more realistic forecast for the rest of the forecast period.”599 598 SCE-25, Vol. 1, at 26 (discussion and Table III-6). 599 SCE Opening Brief at 208. - 264 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE faults TURN’s analysis of the outcomes from prior GRCs because they do not acknowledge that in this GRC, SCE changed its methodology to use only the Moody’s housing starts forecast, instead of averaging the forecasts of both Moody’s and IHS Global Insights as in the previous GRC, “primarily because the IHS Global Insight's forecast produced an overly optimistic housing recovery.”600 Despite acknowledging that IHS Global Insights produced an inaccurate forecast in the Test Year 2015 GRC, SCE then faults TURN for offering what SCE considers “an arbitrary projection with no economic or demographic foundation.”601 More substantively, SCE contends that TURN’s reduction of residential housing starts will lead to a significant under-forecast of residential meters: “while it does not represent a substantial reduction in residential housing starts for 2017, TURN's forecast downplays economic and housing-related factors assumed in Moody's forecast for the outer years” such as an accelerated pace of new home construction as the SCE service territory enters into a full economic expansion and economic headwinds such as weak income growth dissipate. In its opening brief, SCE alleges with no proof that “TURN’s recommendation is based purely on its subjective goal of creating a lower meter forecast.”602 SCE further alleges that TURN’s method of “[s]electively” relying on Moody’s housing starts data in certain years, and not in others, “is unprincipled and should be rejected.”603 SCE also faults TURN for including 600 Id. at 30. 601 Ibid. 602 SCE Opening Brief at 208. 603 Ibid. - 265 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 more recent data in its forecast.604 Finally, SCE faults TURN’s suggestions in its testimony that SCE has a motive to over-forecast, stating that SCE “earned excess profit for no ratepayer benefit.” SCE references TURN’s witness’ testimony at hearings: “when asked at hearings whether TURN had any evidence to support this statement, Mr. Borden admitted that he had none.”605 That said, SCE provided no evidence that the unspent funds did not go toward excess profit. As we have noted elsewhere in this decision, we are troubled by SCE’s inability to explain where funds that, once approved by this Commission for purposes forecast by SCE, in fact are not spent for that purpose. In short, the key takeaway from TURN’s analysis is that “SCE has consistently over-forecasted these costs in recent GRCs” and SCE has neither demonstrated otherwise, nor explained the financial consequences for ratepayers of its inaccurate forecasts. More broadly, we find TURN’s approach to forecasting new meters, as well as its analysis of prior GRC outcomes, to be carefully conceived and executed, and then explained clearly and transparently. TURN demonstrated that SCE has consistently over-forecasted new meters in recent GRCs. For that reason, we are reluctant to adopt SCE’s forecast in this proceeding. Instead, we adopt the results of TURN’s analysis as the forecast of SCE’s new meters for residential and commercial accounts. We summarize our adopted forecast in the table below. 604 SCE Opening Brief at 210. 605 Ibid., citing RT at 2960 (redacted volume). - 266 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2016 2017 2018 2019 2020 New Meter Connections Adopted Forecast Residential Commercial # Requested # Adopted # Requested # Adopted SCE TURN SCE TURN 29,895 31,142 6,092 6,092 33,532 34,013 6,666 6,697 41,702 36,388 6,825 7,045 43,438 37,955 7,665 7,350 42,801 37,729 8,188 7,534 Agricultural # Adopted Uncontested 349 321 321 321 321 TURN did not develop its own forecasts for Streetlights. However, since the number of streetlights is directly related to the number of new residential meter connections, and since we adopt TURN's forecasts for new residential meters, our adopted 2017 and 2018 forecasts for Streetlights reflect revisions to SCE’s request to align those values with our adopted residential forecasts. No party disputed SCE’s forecast of new meters for agricultural accounts, and we adopt that forecast in this decision. 14. Other Operating Revenues OOR are the revenues received by SCE from transactions not directly associated with the sale of electric energy. OOR is subtracted from total operating costs to determine the test year revenue requirement because it reduces the revenue that must be collected through customer rate levels. SCE forecasts a total of $203.992 million for OOR in Test Year 2018.606 ORA examined 606 SCE-60 at A-35, line 16. - 267 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE’s forecasts and does not oppose them.607 We adopt SCE’s uncontested forecast. 15. Cost Escalation As is typical in general rate cases, SCE utilizes a variety of escalation rates to account for the effects of inflation when developing its forecast labor, non-labor, and capital costs. SCE filed this application in September 2016 so its forecasts were developed using 2015 dollars. These values are subsequently escalated to 2018, 2019 and 2020 dollars by applying the escalators discussed here. We summarize SCE’s methodologies briefly below. First, SCE bases its labor cost escalation index on the actual labor escalation rates SCE incurred during the recorded period (2011–2015). For the forecast period (2016–2020), SCE bases its labor cost escalation forecast on SCE’s represented employees contractual wage increase and Global Insight Power Planner labor cost forecasts.608 Second, to escalate non-labor expenses and capital costs, SCE relies on published indices that are commonly accepted by this Commission: the Handy-Whitman Index of Public Utility Construction Costs and IHS Global Insight forecasts of O&M and capital cost escalation.609 SCE’s proposed cost escalation methodology and escalation rates are unopposed, but ORA and SCE agree that SCE should update the labor, non-labor, and capital-related escalation rates using the most recent information 607 ORA-07 (Transmission and Distribution Expenses and Other Operating Revenues) at 55; ORA -12 (Customer Service Costs) at 3. 608 SCE-09, Vol. 1, at 87. 609 Id., at 86-87. - 268 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 available at the time of the update hearings in this proceeding.610 SCE’s method and its agreement with ORA are reasonable and are adopted. 16. Post Test Year Ratemaking Under the Commission’s long-standing Rate Case Plan, large energy utilities such as SCE are required to file general rate case applications every three years. The applications are required to include detailed support of the applicant's forecasted revenue requirement for the test year (e.g., 2018 in this proceeding), and those forecasts provide the basis for the Commission's decision. The Rate Case Plan also provides that applicants may request an attrition allowance as part of their application for the test year revenue requirement: "[i]f applicant requests an attrition allowance, it shall include in its required supporting materials evidence supporting the requested attrition allowance."611 The Commission adopted the term “attrition” to capture the truism under cost-of-service regulation that if a utility’s costs increase in the years between its test years, and if those costs are not offset by additional revenue from increased rates or due to higher sales, the utility’s earnings will, mathematically, decline. This possibility posed a serious concern during past periods of high inflation, but even after economic conditions stabilized, attrition requests remained a routine feature of the GRC applications of the large energy utilities. Nevertheless, the Commission retains the discretion to grant or deny such requests.612 SCE’s 610 SCE Opening Brief at 211. 611 D.07-07-004, Opinion Modifying Energy Rate Case Plan, Attachment A at A-19 (“Rate Case Plan--Edison Only”). 612 We note here that SCE's testimony is incorrect on this point: "Annual cost increases can be triggered by inflation and by plant additions used to maintain and provide service. Footnote continued on next page - 269 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 attrition increases have been implemented through what the Commission terms a “Post-Test Year Ratemaking” (PTYR). 16.1. Summary of SCE’s Proposals SCE proposes a PTYR mechanism with the following features: 1. An annual advice letter providing notice of the revenue requirement change for the following year. 2. O&M escalation using the escalation rate methodology adopted in this decision for escalating 2015 dollars to 2018 dollars, but updated at the time of the advice letter filing and incorporating known labor cost increases at the time of the GRC decision. 3. Capital-related cost increases using SCE’s Board-approved capital budget or based on reasonable increases in capital additions from test-year levels, updated for changes in SCE’s authorized cost of capital. 4. A "Z-Factor" mechanism that allows SCE to seek recovery of costs associated with exogenous events (Z-Factors) that result in a major cost impact for SCE. The first, second and fourth items listed by SCE represent continuations of SCE's current Commission-adopted PTYR mechanism (although SCE's proposal to incorporate known labor cost increases in its O&M escalation is new). SCE's third item, a budget-based capital cost increase, is SCE's primary proposal for attrition year capital increases. SCE also offers an alternate request, which is to escalate SCE’s 2018 test year capital additions by five percent in both 2019 and 2020, plus an adjustment for one project, the Customer Service Re-Platform capitalized software project. SCE's proposed five percent escalation rate is Cost-of-service ratemaking principles require some means to recognize these increases in the authorized revenue requirement." SCE-09, Vol. 1, at 115, emphasis added. TURN's testimony in this proceeding cites several Commission decisions that denied attrition increases requested by the applicant utility. - 270 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 roughly double the escalation that results from projected changes in capital-good prices.613 For O&M expense escalation, intervenors do not oppose authorizing SCE to escalate its 2019 and 2020 O&M expenses from the 2018 level, but recommend specific escalation factors that result in smaller increases of O&M expenses for 2019 and 2020. Those proposals are summarized in the table below. 613 In our decision on SCE's 2015 GRC application, we adopted ORA's recommendation to escalate adopted Test Year 2015 capital additions by 2.0% per year, since the increase in SCE's forecast of capital additions from 2016 to 2017 was approximately 2.0% - 271 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Intervenors' Proposals for Post-Test Year O&M Escalation Intervenor Proposal  SCE has agreed to ORA’s lower 2019-2020 pension cost estimate.  ORA proposes to escalate medical benefits costs at 4.58% in 2019 and 4.58% in 2020, compared to SCE’s proposal to escalate medical benefits costs by 7.0% per year in 2019 and 2020. ORA  ORA does not oppose SCE’s proposed labor escalation rates of 2.89% for 2019 and 2.94% for 2020, but does oppose SCE’s proposal to update the labor escalation rates.614 TURN--Primary Proposal CPI-U615 CPI-U + no more than 50 basis points if the Commission finds it TURN--Alternate necessary to more closely reflect anticipated SCE-specific cost Proposal increases616 CFC Limit rate increases to the recorded median income growth rates in the SCE service area. SBUA Limit PTYR revenue requirement increases to 3% in 2019 and 2020. For capital-related attrition, SCE's primary proposal is that the Commission authorize 2019 and 2020 capital costs equal to SCE's budget-based forecast of capital additions. However, SCE acknowledges that in its GRCs for 614 SCE originally proposed labor escalation rates equal to 2.79% for 2019 and 2.74% for 2020 (SCE-09, Vol. 1 at 79, Table VII-28, Labor Escalation Rates) but updated these values to those shown here in its December 2017 Update Testimony (SCE-59 at 11, Table III-4). ORA did not object to these updates. 615 TURN-06 at 12. The CPI is the "Consumer Price Index" published monthly by the U.S. Bureau of Labor Statistics (BLS). As described on the BLS website, "indexes are available for two population groups: a CPI for All Urban Consumers (CPI-U) which covers approximately 93 percent of the total population and a CPI for Urban Wage Earners and Clerical Workers (CPI-W) which covers 29 percent of the population." See https://www.bls.gov/cpi/overview.htm. 616 Id., at 13. - 272 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Test Years 2006, 2012 and 2015 the Commission did not adopt this approach. Instead, the authorized PTYR capital additions were calculated by applying an escalation factor to the adopted capital additions in SCE’s test year. SCE informs us that "that approach is acceptable here, provided that the capital escalation rates are sufficient to allow for real increases in capital additions, beyond the increases that result from pure escalation in capital goods prices."617 Indeed, SCE recommends an annual 5% escalation rate, which is twice SCE's estimate of the average forecast capital cost escalation rates for 2019 and 2020 for seven different categories of plant, 2.49%.618 SCE's calculation of the average escalation rate is shown in the table below. SCE describes this additional increment to capital cost escalation as "a reasonable 'down payment' on the capital additions required to build the next-generation grid that the Commission and other policymakers want and California needs."619 617 SCE-09, Vol. 1, at 121. Emphasis in the original. 618 Ibid. The calculation is reproduced from WP SCE-09, Vol. 1, Chapter X at 8-9. In turn, the source values are found in SCE-09, Vol. 1, at 86, Table VII-32 (Capital Escalation Rates). SCE explains those values at pages 84-85 of that Exhibit. 619 Id., at 121-122. - 273 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE Calculation of Unweighted Average of Capital Escalation Rates Year 2019 2020 Total Steam Production Plant 2.51% 2.54% Total Hydraulic Production Plant 2.45% 2.40% Total Other Production Plant 2.11% 2.64% Total Transmission Plant 2.63% 2.62% Total Distribution Plant 3.14% 3.18% General Plant 1.82% 1.81% Total Nuclear Palo Verde 2.55% 2.46% Unweighted Average Across 2019-2020 2.49% Intervenors do not oppose some form of PTYR increases for capital, but indicate a preference for an escalation-based mechanism versus SCE's budget-based proposal. As shown in the table below, the intervenors propose lower escalation rates than those proposed by SCE: Intervenors' Proposals for Post-Test Year Capital Escalation Intervenor Proposals ORA Authorize plant addition increases of 2.4% for 2019 and 2.8% for 2020 TURN Forecast capital expenditures that resulted from trending seven years of recorded capital expenditures (2010-2016) CFC Limit rate increases to the recorded median income growth rates in SCE's service area SBUA Limit PTYR revenue requirement increases to 3% in 2019 and 2020 16.1.1. Discussion Neither SCE nor the intervenors provide convincing reasons for us to change the approach to PTYR that we adopted in D.15-11-021. Therefore, we adopt the following PTYR mechanism for SCE: - 274 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 1. Non-labor O&M expenses shall be escalated as proposed by SCE, using the same pricing methodology and pricing indices that we adopt for test year escalation. This includes benefits escalation. 2. For labor escalation we adopt SCE’s proposed labor escalation rates of 2.89% for 2019 and 2.94% for 2020, but we also adopt ORA's recommendation to deny SCE's request to incorporate known labor cost increases at the time of this GRC decision. 3. Capital-related revenues shall be escalated by increasing gross capital additions in the post test years at a rate of 2.49% per year above the 2018 authorized capital additions. 4. SCE’s Z-factor recovery mechanism shall continue for 2019 and 2020. 5. SCE shall continue to file an advice letter to implement the post-test year revenue requirement. SCE must file an advice letter by November 1st of 2019 and 2020. As we directed in D.15-11-021, SCE must include the following information in these advice letters: a. Its updated post-test year revenue requirement, calculated by using the latest IHS Global Insight escalation rates for the following attrition year. In addition, we direct SCE to augment the information currently provided in these advice letters to include the formulae used to calculate each escalated value, so that the reader can verify SCE's calculations without having to request additional workpapers from the Company. b. For the second attrition year of 2020, SCE shall use the latest Global Insight escalation rates to escalate 2018 authorized level of O&M expenses to 2019 and 2020 levels, but the 2019 authorized level of O&M expenses will not be trued up to reflect the actual escalation factor for 2019. Our adopted escalation rates are summarized in the table below. These are the rates that SCE shall update as part of its annual attrition year advice letter filing. - 275 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Post-Test Year Escalation Rates Adopted in This Decision620 Category O&M: Labor Escalation Rates621 O&M: Benefits Escalation Rates Medical Programs Dental Programs Vision Service Plan Disability Programs (=updated labor escalation rates) Group Life Insurance Misc. Benefit Programs622 Executive Benefits 401 (k) (=updated labor escalation rates) Capital Additions (applied to 2018 capital additions, based on the 2018 authorized capital expenditures authorized in this decision) 17. 2019 2.89% 2020 2.94% 7.00% 4.20% 3.00% 2.89% 0.00% 2.20% 0.00% 2.89% 7.00% 4.20% 3.00% 2.94% 0.00% 2.27% 0.00% 2.94% 2.49% 2.49% Rate Base Components Rate Base represents the depreciated value of assets used to provide service to customers. The product of the Rate Base and the authorized rate of return equals a utility’s return on its shareholders’ investment. The key categories comprising shareholder investment in Rate Base are: Fixed Capital, Adjustments, Working Cash, and Deductions for Reserves. SCE’s fixed capital forecast is set forth throughout their application. By this decision, we have authorized less capital spending than SCE requested and Fixed Capital and SCE’s Rate Base will be adjusted accordingly. 620 SCE-09, Vol. 1 except where noted. 621 SCE-59 at 11, table III-4. 622 SCE-59 at 12, table III-5. - 276 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 17.1. Electric Plant SCE states Electric Plant forecasts are developed by starting with 2015 recorded plant balances and then adding forecast plant additions. Plant additions are based on forecast capital expenditures, such as those for Generation, T&D, and CS, which are addressed separately in this decision. The authorized 2018 Electric Plant will be computed through the Results of Operations model based on authorized capital expenditures and capital additions.623 17.2. Depreciation Expense The authorized depreciation expense will be calculated through the Results of Operations model based on the authorized depreciation rates (discussed in Section 18), applied to Electric Plant balances. The depreciation expense is part of the revenue requirement and accrues to accumulated depreciation which is offset against Rate Base. 17.3. Taxes 17.3.1. The Tax Cuts and Jobs Act On December 22, 2017, Public Law 115-97, the TCJA, was signed into law. SCE reports this legislation includes three changes that directly affect the computation of regulatory tax expense and rate base in SCE’s Test Year 2018 GRC. SCE also proposes to return excess accumulated deferred income taxes beginning in 2018. SCE’s updates to the RO model reflect the following:624 1. Change in the federal income tax rate from 35% to 21%; 623 See SCE Opening Brief, at 219. 624 SCE-60, at 6:1-14. - 277 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2. Loss of Internal Revenue Code (IRC) Section 199 manufacturing deduction; 3. New IRC Section 168(k) Bonus Depreciation rules do not apply to public utility property; and 4. The return of excess tax reserves on historical normalized tax differences using the average rate assumption method (ARAM) as reportedly prescribed by the Internal Revenue Service (IRS), to return these benefits to customers beginning in 2018. The change in the Federal income tax rate from 35% to 21% reportedly affects the revenue requirement in five distinct ways:625 1. Equity return on rate base; 2. Debt return on rate base; 3. Current year flow-through tax benefits generated and returned to customers; 4. Recovery of prior year flow-through tax benefits from customers; and 5. Deferred income taxes impact on rate base. 17.3.2. SCE Testimony: Impact of the Tax Cuts and Jobs Act SCE served testimony addressing the impact of the TCJA on February 16, 2018.626 17.3.2.1. Revenue Requirement With its updated testimony, SCE requests a 2018 GRC revenue decrease of $22 million, 0.38% less than the 2017 authorized GRC revenue requirement.627 625 Id. at 6:15-22. 626 SCE-60. 627 Id. at 5:1-2 and Table IV-3. - 278 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The update reduces SCE’s Test Year 2018 Revenue Requirement by $139 million compared to the revenue requirement request stated in SCE’s December 8, 2017 update testimony.628 SCE reports the key drivers of the reduction are changes in: the Federal Income Tax Rate, IRC Section 199 Deduction, Bonus Depreciation, ARAM, and Added Facilities OOR.629 SCE now, following the updates, requests that the Commission adopt a 2018 revenue requirement of $5.534 billion. The proposed revenue change takes into account a requested $106 million decrease in ABRR, a $43 million increase to account for a decline in 2018 forecast GWh sales, and a $41 million increase related to the recovery of the December 31, 2017 balances in five balancing and memorandum accounts proposed in prior testimony.630 Attrition years 2019 and 2020 would follow with increases to the ABRR of $431 million and $503 million, respectively.631 SCE explains that prior to the TCJA, SCE needed to collect $1,781 from customers to recover $1,000. With the tax legislation, the amount it now needs to collect from customers to recover $1,000 drops to $1,425. This decrease is reflected in the lower “gross-up factor” and reduces the test year revenue requirement.632 In addition to tax benefits for SCE and its ratepayers, the change in tax rates has two unfavorable effects on the revenue requirement. First, the lower 628 Id. at 1:8-10 and p. 3 Table III-1. 629 Id. at 1:12-16. 630 Id. at 4-5. 631 Id., Table IV-3. 632 Id. at 7:1-8 and Table V-4. - 279 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 tax rate reduces the after-tax benefit of tax deductions. That means a tax deduction which formerly provided a 35% benefit and a corresponding decrease in the revenue requirement will now provide a 21% benefit with a correspondingly reduced decrease in the revenue requirement. Second, the lower tax rate, through the gross-up factor, reduces the value of the benefit when converted into the revenue requirement.633 17.3.2.2. Accumulated Deferred Income Taxes The reduction in the corporate income tax rate also results in a reduction in the amounts which need to be held for Accumulated Deferred Income Taxes (ADIT). ADIT results from SCE normalizing the benefit of accelerated depreciation, as required by the IRS.634 When SCE takes accelerated depreciation it receives a current tax benefit. For ratemaking purposes however, SCE’s capital expenditures for its plant is depreciated on a straight-line, or “book” basis, over the life of the asset, in accordance with IRS normalization requirements. This means the ratepayers receiving the benefit of an asset share equally in the cost of that asset over the life of the asset. Included in book depreciation is the initial cost of the asset and the “cost of removal” of the asset or “negative net salvage.” The difference between the accelerated “tax depreciation” and the “book depreciation” multiplied by the tax rate is the ADIT balance. Under IRS normalization rules, while the utility is allowed to claim the benefit of accelerated depreciation in its tax filings, thereby lowering its taxable income, the utility is not allowed to flow through these tax benefits to ratepayers. 633 Id. at 8:1-7 and Table V-7. 634 See, IRC Section 168(f)(2). - 280 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Instead, the IRS requires the creation of the ADIT balance which reduces rate base. The ADIT ensures the ratepayers share in the tax benefit of accelerated depreciation through the ADIT reduction from rate base, while tracking the annual changes between tax and book depreciation. The ADIT, by not allowing the flow through of the tax benefits of accelerated depreciation, also ensures the ratepayers share equally in the tax benefit of accelerated depreciation. Under “normalization” rules all ratepayers over the life of an asset receive the tax benefits of accelerated depreciation; the money saved now due to accelerated depreciation (the income taxes) is deferred for payment of the taxes later so that today’s ratepayers share equally with tomorrow’s ratepayers in the payment of taxes relating to the assets which generated the accelerated depreciation. ADIT was formerly calculated based on a payment of deferred income taxes at the rate of 35%. Due to the reduction in the tax rate to 21%, the amount of ADIT needed to pay the deferred tax is reduced. The excess deferred income taxes which result from the reduced income tax rate will be returned to customers; however, this return will not be immediate. The IRS requires these excess deferred income taxes be “normalized” pursuant to the ARAM.635 When the excess deferred income taxes are returned, ARAM ensures the excess is returned to ratepayers over the remaining life of the underlying asset. Since the deferred income taxes are offset against ratebase, when the excess deferred income taxes are returned, there is a corresponding increase in ratebase.636 635 Public Law 115-97, section 13001(d)(3)(B). 636 SCE-60, at 10:12-12:16. - 281 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE historically has included Cost of Removal in its Book Depreciation for ratemaking purposes. Removal costs are deductible for income tax purposes when they are incurred. For financial reporting and ratemaking purposes, removal costs are estimated and accrued in book depreciation expense. Removal costs associated with assets depreciable under IRC Section 168 are subject to normalization tax treatment, whereas removal costs associated with assets not depreciable under IRC Section 168 (generally, pre-1981 vintages and California tax treatment) are subject to flow-through tax treatment.637 Prior to the TCJA, SCE included Cost of Removal when it calculated its ADIT.638 SCE, by including Cost of Removal in the calculation of ADIT, normalized the Cost of Removal and ensured all ratepayers over the life of the asset shared in that expense. Now, following passage of the TCJA however, SCE contends Cost of Removal must be excluded from Book Depreciation before calculating ARAM.639 TURN questions whether SCE has properly excluded the cost of removal of assets from its calculations of ARAM. Rather than recommending a change to SCE’s calculations, TURN recommends SCE should request a private letter ruling from the IRS concerning the use of the entirety of book depreciation for computing ARAM as opposed to excluding net salvage.640 TURN also recommends this difference be tracked in a memorandum account. SCE, by their rebuttal testimony, agrees with TURN that it should request a Private Letter 637 SCE-09, Vol. 2, at 25:8-13. 638 RT, March 19, 2018, Vol. 24, at 3258:26-3259:6. 639 SCE-60, at 12:4-16 640 TURN-15, at 2-3. - 282 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Ruling to address whether or not cost of removal should be included in book depreciation when computing ARAM.641 17.3.2.3. The Return to Ratepayers of Excess Deferred Income Taxes Does Not Violate IRS Normalization Rules The normalization rules are provided by IRC section 168(i)(9), Treasury Regulations § 1.167(l)-1, and pertinent IRS rulings. The TCJA has adopted normalization requirements at section 13001(d) which are consistent with the normalization rules previously present in the IRC and regulations. Section 168(f)(2) of the IRC provides that a deduction for depreciation expense shall not be available for public utility property, as defined by IRC section 168(i)(10), if the utility does not employ a normalization method of accounting as described in IRC section 168(i)(9). Similarly, section 13001(d)(4) provides that if a taxpayer does not use a normalization method of accounting for corporate rate reductions, the taxpayer’s tax for the taxable year shall be increased by the amount by which it reduces its excess tax reserve more rapidly than permitted under a normalization method of accounting, and (B) such taxpayer shall not be treated as using a normalization method of accounting for purposes of subsections (f)(2) and (i)(9)(C) of section 168 of the Internal Revenue Code of 1986. IRC section 168(i)(9) states, in part, (A) In general In order to use a normalization method of accounting with respect to any public utility property for purposes of subsection (f)(2)– 641 SCE-61, at 1:17-22. - 283 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 i. The taxpayer must, in computing its tax expense for purposes of establishing its cost of service for ratemaking purposes and reflecting operating results in its regulated books of account, use a method of depreciation with respect to such property that is the same as, and a depreciation period for such property that is no shorter than, the method and period used to compute its depreciation expense for such purposes… Under IRC section 168(i)(9)(A)(ii), if the deduction under IRC section 168 is a different amount from the allowable deduction under section 167 when applying the same calculation method as under IRC section 168(a)(9)(A)(i), then the taxpayer must reflect that difference in a tax deferral reserve. This is the ADIT discussed above in section 17.3.2.2. IRC section 168(i)(9)(B)(ii) precludes using: any procedure or adjustment for ratemaking purposes which uses an estimate of the taxpayer’s tax expense, depreciation expense, or reserve for deferred taxes … unless such estimate or projection is also used, for ratemaking purposes, with respect to the other 2 such items and with respect to the rate base. Treasury Regulation § 1.167(l) provides the normalization regulations. These regulations do not relate to other book-tax timing differences other than federal accelerated depreciation.642 Treasury Regulation § 1.167(l)-1(h)(2)(i) requires that deferred income tax based on actual tax liability shall be credited to a reserve for deferred taxes. Treasury Regulation § 1.167(l)-1(h)(1)(iii) provides that the amount of deferred income tax is the “excess . . . of the amount the tax liability would have been had a subsection (l) method been used over the 642 Treasury Regulation § 1.167(l)-1(a)(1) (“The normalization requirements . . . pertain only to the deferral of Federal income tax liability resulting from the use of an accelerated method of depreciation”). - 284 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 amount of the actual tax liability.” A subsection (l) method includes the straight-line method of depreciation used here for ratemaking purposes. The deferred taxes reflected on SCE’s regulatory books of account are based on the differences between SCE’s regulatory tax liability, including Cost of Removal, and its actual tax liability, as calculated on its actual depreciable basis and consistent with IRC section 168(i)(9)(A)(i). This is consistent with Treasury Regulation § 1.167(l)-1(h)(1)(iii). SCE should continue to calculate its excess deferred income taxes and the consequent redistribution of those funds under ARAM, in the same manner. SCE is receiving the full benefits of accelerated depreciation, as calculated on its actual depreciable basis. The depreciable basis under IRC section 167(c) is the adjusted basis of IRC section 1011, following application of IRC section 1016 adjustments. These adjustments must be made pursuant to section 1016(a)(1) for “expenditures, receipts, losses, or other items, properly chargeable to capital account…” and “… for exhaustion, wear and tear, obsolescence, amortization, and depletion …” SCE has consistently normalized the benefits of accelerated depreciation derived from its depreciable basis. It is our intention that SCE continues to normalize the benefits of the TCJA.643 Historically SCE has included Cost of Removal in its calculation of ADIT. Excluding Cost of Removal from the ARAM calculation increases the tax expense for current customers in excess of the benefit received from the asset. The effect is the Cost of Removal is not 643 Taxpayers have a duty to treat items consistently. See Unvert v. Commissioner, 72 T.C. 807, 814 (T.C. 1979) (“‘there is a duty of consistency as to [tax] treatment, and one should be held to the consequences of the initial treatment.’”). - 285 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 normalized, despite it being a cost which should be shared equally by all ratepayers. Accordingly, we believe our approach is consistent with the IRC normalization rules by requiring SCE continue to comply with normalization of the Cost of Removal by including it in its calculation of ADIT and consequently ARAM. We fully intend SCE continues to comply with the normalization rules and consider the requirements of this decision to meet those rules. While we believe we have reached the correct result, and though SCE has not cited to any written determination, case, regulation, or statute to support its position, we recognize that SCE has requested644 and may receive a private letter ruling from the IRS. Accordingly, SCE may track changes in revenue resulting from the application of ARAM in accordance with this decision in the Tax Memorandum Account adopted in Section 25.1, below. In the event that SCE receives a relevant IRS ruling contradicting this decision, stating normalization rules do not apply to Cost of Removal/Negative Net Salvage in the ARAM calculation for the return of excess deferred taxes to ratepayers, then it shall comply with the IRS’s interpretation of the applicable tax laws by filing a Tier 2 advice letter with this Commission to seek an appropriate adjustment to its revenue requirement and/or rate base. 644 On June 8, 2018, SCE filed and served a copy of its draft private letter ruling request to the IRS as a Tier 1 Advice Letter (AL 3813-E). The draft request seeks a private letter ruling in response to the following questions, “Do Normalization Rules apply to Cost of Removal?”, “If Normalization Rules apply to Cost of Removal, should Cost of Removal be treated as a discrete ‘protected’ method/life difference?, and “If the Normalization Rules do not apply to Cost of Removal, would those rules require that both the Cost of Removal component of book depreciation accruals and future Cost of Removal payments be removed from consideration in the computation of the ARAM to be applied to the ‘protected’ Excess Deferred Federal Income Taxes (EDFIT)?” - 286 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 17.3.2.4. Unprotected Assets Some other assets are not subject to normalization rules. These assets are typically referred to as “unprotected” assets.645 SCE identifies the unprotected assets as: Accrued Vacation, ITCC (Income Tax Component of Contributions), Mixed Service Costs, AFUDC (Allowance for Funds Used During Construction), Other Historical Basis Differences, and Cost of Removal.646 In past GRCs normalization rules have been applied to them, even though not required, again to ensure that ratepayers over the life of the asset are treated equally. This is consistent with Public Utilities Code § 454.8 which requires, in part, “the commission shall consider a method for the recovery of these costs which would be constant in real economic terms over the life of the facilities, so that ratepayers in a given year will not pay for the benefits received in other years.” Although we agree that when taxes are deferred the benefit of the deferral should be normalized so that ratepayers are treated equally, we do not agree with deferring the return of excess funds if the deferral is not required by statute or regulation. SCE acknowledges ARAM does not apply to these funds since the IRS normalization rules do not apply.647 We find that funds that are excess funds now and not subject to other limitations, should be returned to ratepayers now. Unlike requiring all ratepayers share equally in the expense of an asset over its life, returning excess funds to current ratepayers does not impose a greater burden on future ratepayers. Rather, repayment now returns the excess funds to ratepayers who are the closest in time to the recent ratepayers who contributed 645 RT, Vol. 24, at 3257:1-14. 646 RT, Vol. 24, at 3264:28-3265:18. 647 SCE-60, at 12:25-26. - 287 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 those funds to these accounts. Therefore, we require the net excess deferrals relating to the unprotected assets consisting of: Accrued Vacation, ITCC, Mixed Service Costs, AFUDC, and Other Historical Basis Differences, be returned to ratepayers. Consistent with the return of other funds due to implementation of the TCJA, we require these funds be returned on an amortized basis over 2018-2020. 17.3.3. Other Tax Issues TURN contends SCE has incorrectly calculated its operational cash requirement by applying the new tax rate only to the 2018 year-end balance and not to the entire year.648 Applying the new tax rate to the entire year reduces the estimate for workers’ compensation reserves by $12.144 million as opposed to SCE’s proposed reduction of $5.297 million. Similarly for the unfunded pension reserve, TURN, applies the 21% tax rate to the entire year of 2018, reducing the unfunded pension estimate by $16.413 million, in contrast to SCE’s reduction to $8.430 million. SCE agrees with TURN’s proposal to apply the 21% tax rate to the entire year and use average deferred tax balances for Workers’ Compensation and Unfunded Pension Reserves rather than year-end balances.649 In addition to a differing method of calculation, when one considers other accounts receivable, TURN relies on a different forecast. In this case, SCE’s revision results in an adjusted number of $73.323 million and TURN’s revised amount is $50.778 million (See Section 17.11.2). 648 TURN-15, at 4-5. 649 SCE-61, at 3:7-14. - 288 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN does not dispute SCE’s calculation of the TCJA impact on long-term incentives; TURN advocates against any recovery of long-term incentives. Consistent with our longstanding position in prior decisions and this decision at section 8.2, we do not permit recovery of long-term incentive compensation. SCE also agrees with ORA and TURN that it should have a broadened Tax Memorandum account.650 The requirements for a Tax Memorandum Account are discussed below at section 25.1. SCE filed an advice letter (AL 3817-E) on June 27, 2018 to address non-rate base impacts of other deferred tax amounts affected by the change in tax rates. 17.3.4. The Impact on Rates SCE presents two proposals for implementing the impact of the TCJA. First, SCE proposes amortizing the balance of the 2018 GRC Revenue Requirement Memorandum Account (RRMA) over 2019 and 2020. SCE suggests this would benefit customers by promoting rate stabilization. If SCE’s application is approved without change, this would result in no change to rates in 2018, followed by a $272 million increase in 2019 and a $503 million increase in 2020.651 Alternatively, SCE proposes placing any tax related savings in a balancing account dedicated to wildfire related risk mitigation.652 ORA is opposed to setting aside the tax benefits to support wildfire-related risk mitigation.653 650 SCE-61, at 2:3-10. 651 SCE-60, at 19. 652 Ibid. 653 ORA-02-T, at 2-8:12-16. - 289 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA states if the initial benefits of TJCA are realized in 2018, the 2018 revenue requirement will be $5.359 billion, a reduction of $281 million from the current revenue requirement of $5.640 million. This would then be followed by attrition year increases of $309 million to $5.668 million for 2019 and an additional $374 million to $6.042 million for 2020.654 ORA however, proposes the benefits be amortized over three years, providing rate stabilization and ensuring some benefits of TJCA flow to ratepayers now, during 2018.655 This would result in a reduction in the revenue requirement for 2018 of $93 million, to $5.547 million, followed by an increase for 2019 of $27 million, to $5.574 million, and for 2020 of $374 million to $5.948 million.656 SCE is not opposed to amortizing the tax benefit over 2018-2020, depending on timing of the decision in this proceeding.657 SCE also agrees it will not contest ORA and TURN’s opposition to placing any tax benefit in an account to mitigate the risk of wildfire. We agree the benefits of the TCJA should flow to the ratepayers. We recognize there will likely be costs associated with wildfires which will have to be paid but the questions of who bears responsibility and thus who should bear the expense, as well as the amount of the expense, may depend on the circumstances and may not be answered for some time. Meanwhile, the TCJA was effective January 1, 2018; the cost of service for SCE has been reduced as of January 1, 2018. SCE has stated it is not opposed to three-year amortization over 654 Id., at 2-2, Table 2-1. 655 Id., at 2-8:5-11. 656 Id., at 2-9:25-30 and Table 2.2. 657 SCE-61, at 3-15:4-9. - 290 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2018-2020 (if a decision is issued before September 30, 2018) as proposed by ORA and TURN (in the interest of rate stability).658 Due to the timing of this decision however, we agree with SCE that amortization over two-years is practical. Therefore, we require the ratepayers begin receiving the benefit of the TCJA effective January 1, 2019 and continuing through the remainder of this GRC cycle, 2018-2020. 17.4. Rate Base SCE’s forecast 2018 rate base is presented in Exhibit SCE-09, Vol. 2, at 41-86. Authorized 2018 rate base is the net of several separate line items, many of which are contested in and resolved by this proceeding. 17.5. Customer Advances Customer Advances represent funds provided by others, such as developers, to construct new distribution facilities to be served by the utility. Customer Advances do not bear interest since they are funded by developers, not shareholders. Customer Advances are subtracted from Rate Base and investors do not earn a rate of return on them.659 SCE forecast Customer Advances based on a three-part analysis of: (1) estimated net advances for Electric Construction; (2) estimated refunds to customers; and (3) customer advances that will permanently offset rate base as a Contribution in Aid of Construction (CIAC).660 658 SCE-61, at 3:17-4:10. 659 SCE-09, Vol. 2, at 42:4-43:2. 660 SCE-09, Vol. 2, at 44; SCE-25, Vol. 2, at 2. - 291 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Both ORA and TURN dispute SCE’s forecast for Customer Advances – Electric Construction. ORA disputes SCE’s forecast of Customer Advances – Temporary Services. We discuss each in the following sections. No party challenges the CIAC forecast, and we agree it is reasonable. 17.5.1. Customer Advances – Electric Construction SCE’s forecast for Customer Advances – Electric Construction is driven by forecast meter sets. The meter sets forecast is discussed at section 13, Sales and Customer Forecast, supra. We find the meter sets forecast prepared by ORA to be reasonable and adopt it. SCE forecasts 2018 Customer Advances for Electric Construction of $65.6 million based on a five-year average of advances per meter set.661 ORA forecast (net of refunds) $84.7 million, a $19.1 million increase over SCE’s forecast. ORA performed a linear regression analysis of six years of data (2010-2015).662 We find convincing ORA’s rationale for its forecast as well as its criticism that SCE’s forecast is unreasonably low and spurious.663 ORA’s restriction to six years of data beginning with 2010 through 2015 is considered reliable as it avoids use of data from the depths of the Great Recession. We adopt ORA’s forecast of $84.7 million. 661 SCE-09, Vol. 2A, at 45, Table IV-14. 662 ORA-20P, at 6, Table 20-2. 663 Id. at 9:9-14. - 292 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 17.5.2. Customer Advances – Temporary Services SCE averaged 2011-2015 recorded balances, then escalated that average by forecast non-labor escalation rates, to forecast Customer Advances – Temporary Services.664 ORA based its forecast on escalation of the recorded 2015 balance.665 SCE’s argument against ORA’s forecast is not persuasive in light of the upwardly trending data; we adopt ORA’s forecast for 2018 of $6.122 million. 17.6. Material and Supplies SCE maintains an inventory of Materials and Supplies (M&S) for new plant construction and operating and maintenance needs. SCE separately forecast M&S balances for T&D, Generation, and IT. SCE forecast $226.965 million for its 2018 M&S. ORA proposed a reduced forecast of $224.476 million.666 ORA challenges SCE’s M&S forecasts for Generation and T&D, but does not challenge the M&S for Information Technology. 17.6.1. Generation M&S SCE’s forecast was based on recorded data excluding unpaid invoices for inventory maintained at the Palo Verde Nuclear Generating Station (PVNGS).667 In rebuttal, SCE shows that its PVNGS adjustment is appropriate. The lag in receipt of detailed accounting information from Arizona Public Service, the operating agent of PVNGS, causes a lag in recording that inventory, which causes SCE to forgo a return on the inventory until the month it is recorded. 664 SCE-25, Vol. 2, at 7:2-3. 665 ORA-20P, at 10. 666 SCE-25, Vol. 2, at 7. 667 SCE-29, at 408. - 293 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA’s proposed adjustment for unpaid inventory is not appropriate; SCE’s forecast of Generation M&S is adopted. 17.6.2. T&D M&S ORA proposes a $391,000 reduction to SCE’s T&D M&S balance based on a three-year moving average.668 In rebuttal, SCE shows that its analysis already incorporated a three-year average, rendering ORA’s second averaging step unnecessary.669 SCE’s forecast is reasonable and is adopted. 17.7. Working Cash ORA proposes a $6.9 million reduction to SCE’s working cash forecast, based on the proposition that the bank balances SCE maintains are not required under Standard Practice U-16, D.12-11-051, D.09-03-025, and D.06-05-016.670 Although SCE contends in rebuttal that these balances are functionally required for operational purposes, SCE does not contest ORA’s proposed adjustment.671 We eliminate the Cash Bank Balances of $6.9 million from the Working Capital forecast. The other Operational Cash Requirements are not contested. 17.8. Lead Lag Study SCE’s Lead-Lag Study seeks to quantify the amount of funds needed from investors to cover the timing difference between receipt of revenues and payment of expenses. SCE’s analysis for this GRC shows, on average, SCE pays expenses 12.7 days before receiving corresponding revenues. Based on estimated 668 SCE-25, Vol. 2, at 8:12-13. 669 SCE-25, Vol. 2, at 8:13-20. 670 ORA-20P, at 17:1-18:19. 671 SCE-25, Vol. 2, at 9:6-9. - 294 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 daily expenses of $28.9 million, SCE estimates its Lead-Lag Working Cash requirement is $367 million.672 Most of the components of SCE’s Lead Lag Study are not contested; however, TURN and ORA do contest a few items which are discussed in the following sections. 17.8.1. Revenue Lag Days Revenue Lag is the number of days between delivery of service to the customer (measured from the midpoint of the service period) and availability of payment for the service in SCE’s bank account. SCE calculated a 45.01 day Revenue Lag in accordance with Standard Practice U-16.673 TURN proposes adjusting SCE’s Revenue Lag days to account for the return of Green House Gas revenue to customers, and SCE agrees, reducing the estimated Revenue Lag by 0.94 days.674 ORA proposes to reduce SCE’s requested Revenue Lag days by 2.66 days to 43.29 to “smooth out the fluctuations caused by SCE recalculating annual estimates every GRC.” The proposal is based on an average from the 2012 and 2015 GRCs and the study for this GRC.675 ORA’s rationale is insufficient to warrant deviating from Standard Practice U-16. We adopt a Revenue Lag Day estimate of 45.01 days, accepting SCE’s proposal as adjusted by TURN. 672 As a result of the tax update filed in SCE-60, the RO model dynamically updated the numbers provided in SCE-09, Vol. 2, at 61. 673 SCE-09, Vol. 2A, at 62-A and SCE-29 at 39. 674 SCE-25, Vol. 2, at 10. 675 ORA-20P, at 18:25-28, at 19, Table 20-7. - 295 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 17.8.2. Income Tax Lag The Income Tax Lag represents the period from when current tax expenses are accrued to the time they are due by statute.676 SCE’s 2018 estimated Income Tax Lag day calculation is based on a July 13th midpoint accrual date and the quarterly due dates prescribed by Federal and California tax law resulting in a proposed Federal Income Tax lag of 25.50 days and a proposed California Income Tax Lag of 8.60 days.677 ORA proposes 96.98 days and 117.20 days, respectively.678 ORA’s proposal is based primarily on estimated tax payments recorded over an eight-year period (2008-2015), a period during which SCE made no estimated tax payments half of those years, in part due to large bonus depreciation deductions that are set to expire during this rate cycle.679 SCE’s “statutory” based approach results in proposals for a dramatically lower number of Tax Lag days compared to ORA’s proposal or prior GRC decisions. The 2015 decision adopted 85.98 days for the Federal Income Tax lag and 56.34 for the California Income Tax lag, based on TURN’s five-year weighted average (SCE proposed a five-year average).680 For the 2012 GRC, ORA proposed a four-year average, SCE proposed five, and we used a three-year average based on facts and regulations leading to the exclusion of earlier years as not being 676 SCE-09, at 68:18-19. 677 SCE-09, at 69:3-20, Table IV-28 and at 69, Table IV-29. 678 ORA-20P, at 20, Table 20-8. 679 SCE-25, Vol. 2, at 13-14. 680 D.15-11-021, at 469. - 296 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 representative. This resulted in the Commission adopting a Federal Income Tax lag of 83.28 days and a California Income Tax lag of 61.59 days.681 SCE contends its “statutory” approach avoids relying on using subjective analysis and judgment to select the recorded data to produce the best estimate. It also argues that there is no tax payment history for the end of rules on bonus depreciation. Curiously, SCE does not argue the methods used in the past to determine the Federal Income Tax lag days and California Income Tax lag days produce results that are not supported by the evidence. SCE has not established that its proposal to base Income Tax Lag Days on statutory payment dates rather than historical data is reasonable. ORA’s proposal is consistent with prior decisions and results in Income Tax Lag Day calculations which are representative and we adopt it. 17.8.3. Fuel and Purchased Power Expense Lag Fuel and Purchased Power are two components of the overall Expense Lag calculation. Fuel costs represent the natural gas, diesel, propane and nuclear fuel amounts used by SCE generating stations. Although SCE initially relied on data from earlier forecasts, SCE is not opposed to TURN’s proposal using the more recent Fall 2016 forecast to compute Fuel and Purchased Power expense lags, providing the use is consistent.682 This results in proposals of 36.4 lag days for purchased power, $206.3 million for fuel, $4,574.2 million for purchased power, and working cash requirements of $7.2 million for fuel, and $107.8 million for purchased power as adjusted for use of the United States Postal Service for 31% 681 D.12-11-051, at 641-642. 682 SCE-25, Vol. 2, at 16. - 297 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 of payments.683 ORA’s testimony is unclear and inconsistent. Therefore, we find TURN’s proposal to use the more recent Fall forecasts reasonable, as is SCE’s proposal to consistently use forecasts from the same period. We adopt the proposals as stated above. 17.8.4. Other O&M Expense Lag (ISO Charges) Other O&M Expense Lag is intended to compensate investors for the time between the recording of utility costs and payment of those costs for non-labor expenses associated with balancing accounts.684 SCE asserts its analysis showed 12.1 expense lag days for this category. Although ORA initially proposed an alternative value, ORA has since agreed the ISO charges are correctly calculated at 12.1 expense lag days.685 We adopt it. 17.8.5. Depreciation & Deferred Income Tax Lag SCE’s Expense Lag Day calculation is included in the lead lag study to compensate investors for the timing difference between the receipt of revenues and the accrual of depreciation expense and deferred income taxes.686 Although TURN implicitly acknowledges depreciation and deferred taxes are recognized categories of working cash under Commission Standard Practice U-16 (SP U-16), TURN asserts this recognition is an element of SP U-16 which may no longer be aligned with principles of working capital based on the principal they are “non-cash” items which do not affect utility cash balances.687 683 Ibid. and SCE-25, Vol. 2, at 17, Table I-3 and SCE-29 at 38 and 410. 684 SCE-09, Vol. 2, at 66. 685 ORA Opening Brief, at 242. 686 SCE-09, Vol. 2, at 68:4-9; SCE-25, Vol. 2, at 19:7-20:17. 687 TURN-11, at 44:5-45:27. - 298 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN provides no authority for the proposition that accounting for depreciation and deferred taxes has changed since Standard Practice U-16 was adopted, but supports its argument by citing to a rule from Texas.688 SCE’s rebuttal establishes, although these two items are both accrued, the other side of the accounting entry lowers the rate base on which the utility earns a rate of return. The utility reduces rate base at the midpoint of the service period during which depreciation and deferred income taxes are accrued, but, on average, customers do not render payment until 46 days after the service is rendered, creating a lag between the date rate base is lowered and the revenues are received.689 We agree, consistent with long-standing practice, it is appropriate to continue to compensate for this lag. 17.9. Customer Deposits SCE is required to offset rate base by the amount of its customer deposits as an adjustment for working cash. This requirement recognizing customer deposits as a source of permanent working capital has been in effect since SCE’s 2003 GRC.690 In every GRC since 2003, SCE has urged the Commission revisit this decision and recognize customer deposits as debt which is not offset against rate base. In each decision for each GRC the Commission has reached the same conclusion.691 688 Id. 689 SCE-25, Vol. 2, at 19:7-23:15. 690 D.04-07-022, at 249-255. 691 D.06-05-016, (SCE 2006 GRC), at 279-282; D.09-03-025 (SCE 2009 GRC), at 278-290; D.12-11-051 (SCE 2012 GRC), at 627-629; D.15-11-021 (SCE 2015 GRC), at 470-473. - 299 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Although SCE may have presented an approach in its current testimony to depart from this longstanding requirement, SCE has failed to introduce a different argument supporting its request. We are faced once again with the repeated arguments against offsetting rate base with customer deposits that we previously rejected.692 In the face of the same arguments, we reach the same conclusion: we do not agree with SCE. Absent an indication of a policy change by this Commission or a new (and preferably irrefutable) argument, we direct SCE to resist the temptation to argue these same points again. Beginning with its 2012 GRC, the Commission has granted SCE permission to use a portion (up to 10%) of its customer deposits to promote the Company’s use of minority and community banks.693 This policy was continued in SCE’s 2015 GRC,694 and SCE proposes that it continue in this GRC.695 No party opposes this proposal, and we again adopt it. We direct $231.9 million, less 10% devoted to the community bank program, be used as a rate base offset.696 We also grant an offsetting interest expense based on the three-month commercial paper interest rate. 17.10. AFUDC SCE’s proposed AFUDC rates through the post-test year period have not been opposed by any party. AFUDC is the standard way of capitalizing equity and debt costs incurred for financing Construction Work in Progress (CWIP). 692 SCE-25, Vol. 2, at 24-31. 693 D.12-11-051, at 628-630, COL 534, at 877. 694 D.15-11-021, at 474, FOF 567, at 533, COL 148, at 550. 695 SCE-09, Vol. 2, at 83-84. 696 SCE-25, Vol. 2, at 25:3-5. - 300 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Capitalizing these costs helps ensure that full construction costs are paid by customers who received the services provided by the capital projects. It also helps ensure that investors’ costs incurred during construction are fully recovered after the capital projects enter service.697 The Commission adopts SCE’s proposed AFUDC rates. 17.11. Rate Base Components – Additional Issues 17.11.1. Long-Term Incentives We discuss and have adopted the proposed disallowance of Long-Term Incentives in Section 8.2.2. of this decision. The authorized rate base is correspondingly increased by $4.3 million. 17.11.2. Other Accounts Receivable SCE estimates 2018 Accounts Receivable rate base of $73 million. SCE’s estimate is based on 2015 recorded data, the same approach followed in prior GRCs.698 TURN makes a revised proposal of a $22.5 million reduction to SCE’s forecast, based on recorded 2016 data.699 SCE has conceded concerning other accounts as to the greater reliability of recorded 2016 data over 2015 when making forecasts. We adopt TURN’s recommendation, based on 2016 recorded data as reasonable and adopt $50.8 million for this account. 18. Depreciation Study SCE’s recorded 2015 depreciation expense at authorized rates was $1.656 billion. The proposed change due to plant growth from 2016-2018 is 697 SCE Opening Brief, at 230. 698 SCE-29, at 409. 699 SCE-60, at 14, Table VI-9 and TURN-15 (Marcus Update), at 4 and 6. - 301 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 $266 million. The additional newly proposed amount following SCE’s Depreciation Study is $81 million. The total proposed 2018 depreciation expense is $2.003 billion, over one-third of the requested total revenue requirement.700 D.15-11-021, at 396, stated, “In D.12-11-051, we warned SCE against over-reliance on judgment without further explanation, and encouraged SCE to provide more transparency in its depreciation showing.”701 In D.15-11-021, we again found significant shortcomings in SCE’s showing and offered guidance for the current GRC. We offered guidance to avoid the possibility that a failure by SCE to meet its burden of proof for depreciation costs would burden future ratepayers with a disproportionate share of the costs of removal and salvage. We stated, “First, we believe that SCE can and must do more to explain and justify its use of judgment in its depreciation showing.”702 We further stated, Second, we direct SCE to provide considerably more detail in support of its net salvage proposals for at least five of the largest accounts, as measured by proposed annual depreciation expense. At a minimum, this detail shall include: 1. A quantitative discussion of the historical and anticipated future Cost of Removal (COR) on a per unit basis for the large (greater than 15% as measured by portion of plant balance) asset classes in the account. This discussion should identify and explain the key factors in changing or maintaining the per-unit COR. 2. A quantitative discussion of the historical and anticipated future retirement mix (i.e., retirements among different asset 700 SCE-09, Vol.02 at 17, Table 11-7. 701 See, e.g., D.12-11-051 at 673, 685. 702 D.15-11-021 at 397. - 302 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 classes), identifying and explaining the key factors in changing or maintaining this mix. 3. A quantitative discussion of the life of assets and original cost of assets being retired, in relation to the COR, on both a historical and anticipated future basis. This discussion should be integrated with and/or cross-reference the proposal for life characteristics. 4. An account-specific discussion of the process for allocating costs to COR.703 And, Third, we recognize that this is at least the second consecutive GRC that the Commission has expressed serious concern with the quality of SCE’s depreciation showing. In order to motivate SCE to take these concerns seriously in developing its direct showing for its next GRC, we encourage ORA and TURN (and any other interested party) to consider making proposals in that GRC to shift a portion of the under-collection risk from future customers to SCE’s shareholders. Parties should only make such proposals if SCE’s direct showing in the following GRC exhibits the same types of shortcomings, discussed here and in D.12-11-051, in a widespread manner.704 In response to these directives, SCE produced a Depreciation Study which under the guise of meeting the Commission’s directives seeks to introduce a new method for determining depreciation rates. We find, however, the study brings us no closer to resolving questions about the reliability of SCE’s depreciation showing. Indeed, the study presents additional questions and assumptions which are not readily verified or resolved. Most notably, SCE’s study presents a new proposal for determining depreciation rates rather than simply, as the 703 Id. at 398. 704 Id. at 398-399. - 303 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 directives intended, providing additional evidence supporting SCE’s depreciation testimony. Apparently recognizing the untenability of the results of its study, SCE scales back the results the study would seemingly support and proposes a cap on depreciation following the principle of gradualism. Then, in a further display of the lack of support SCE provides for its study, SCE in its rebuttal testimony states it “is not proposing to change depreciation practices to an entirely different net salvage analysis method.”705 We find little merit in either the results of the depreciation study or the application of gradualism to its results. Straight-line depreciation following Standard Practice U-4706 remains the proscribed means for determining depreciation rates. The multiplicity of assumptions underlying SCE’s proposal argues against our deviating from our long-standing and accepted practice. 18.1. Foundational Overview The purpose of depreciation is to allow a utility to recover the original cost of the asset, as well as the net salvage value (salvage minus cost of removal), over the life of the asset. This ensures assets are paid for by the customers who benefit from the use of the asset. To meet this objective, the Commission uses the Straight-line Remaining Life depreciation method described by Standard Practice U-4. Under the straight line remaining life depreciation method, the undepreciated asset amount (original cost less accumulated depreciation plus the 705 SCE-25, Vol. 4, at 61-62. 706 Originally issued by the Commission in 1952 and subsequently revised in 1953, 1954, and 1961. - 304 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 estimated net salvage) is depreciated over the remaining life of the asset. The net salvage includes the cost of removal of the asset at the end of its useful life as well as any salvage value the asset may have at that time. The original cost of the asset and the net salvage are expressed in nominal dollars. This is shown by the following formula: Depreciation Expense = Plant Balance – Reserve – Gross Salvage + Cost of Removal Remaining Service Life of Asset(s) A net salvage rate under Standard Practice U-4 is applied to the plant balance to determine the future net salvage. The net salvage rate is computed as follows: Net Salvage ($) Retirements ($) = Gross Salvage ($) – Cost of Removal ($) Retirements ($) Retirements ($)707 Under the per-unit analysis proposed by SCE’s depreciation study, SCE determines the future net salvage rate based on a “per-unit net salvage.” In an effort to counter TURN’s contention as to the complexity of its method, SCE’s expert Dr. Ronald White describes it in his testimony: The per-unit model is described by the following four simple steps: Step 1. Average net salvage per-unit recorded over a few recent activity years to obtain a normalized per-unit ratio applicable to future vintage-year retirements. Step 2. Divide the average ratio derived in Step 1 by vintaged per-unit additions. Step 3. Multiply forecasted retirements by ratios derived in Step 2 and a selected age-adjusted inflation rate to obtain forecasted future net salvage for each future activity year. 707 SCE-09, Vol. 3, at 16, Figure II-2 - 305 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Step 4. Sum the forecasted future net salvage derived in Step 3 and divide by total plant in service to obtain estimate of future net salvage rate.708 The analysis incorporates as a multiplier an “age-adjusted inflation rate” to obtain the forecasted net salvage. Despite stating the forecasted net salvage in future inflated dollars, SCE did not similarly adjust the dollars to be accrued for that forecast. TURN raises valid concerns about this issue, describing it as a “currency mismatch” due to the calculation of costs based on future currency that has a lower value than today’s dollars collected from current ratepayers.709 Although TURN may raise valid criticisms of SCE’s methods, TURN’s own proposal ignores Standard Practice U-4 and Commission precedent in support of SCE collecting approximately 1.2 times SCE’s incurred net salvage costs for recent years. Both SCE’s per-unit analysis and TURN’s proposal are substantial deviations from Standard Practice U-4 and we do not adopt them here. Following the directive of D.15-11-021, SCE performed this analysis on nine T&D accounts, “which comprise 85% of the total COR expense proposed.”710 SCE contends, in an effort to establish the reasonableness of its per unit analysis, “Comparing the results of both approaches demonstrates that the results are largely comparable … and underscores the reasonableness of SCE’s proposal.”711 708 SCE-25, Vol. 4, at 64:20 – 65:2. 709 TURN Opening Brief, at 297. 710 SCE-09, Vol. 3, at 12:8-9. 711 SCE-25, Vol. 4, at 15:13-14. - 306 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Comparison of Traditional vs. Per-Unit Net Salvage Analysis Results712 Account Traditional Analysis Per-Unit with 2.72% Inflation SCE Proposed 354 355 356 364 365 366 367 368 369 -931% -175% -388% -656% -293% -228% -178% -68% -520% -185% -499% -210% -488% -538% -401% -261% -47% -387% -75% -90% -100% -263% -144% -38% -75% -25% -125% Traditional compared to Per-Unit Higher Lower Higher Higher Lower Lower Lower Higher Higher Likely recognizing that these net salvage rates are significantly different, SCE explains, These variances between the results produced by a traditional analysis versus a per-unit analysis do not demonstrate flaws in the per-unit approach; rather, they reflect the difference between past retirement experience and what one can reasonably expect about future retirements and costs.713 SCE then further explains by reference to its traditional analysis which supports a depreciation increase of $782 million and the per-unit analysis supporting an increase of $893 million, “… the traditional analysis, without application of expert judgment, produces depreciation expense approximately as large as the results supported by SCE’s per-unit analysis.”714 Notably missing from this explanation is that expert judgment is a required element of the 712 Id., at 16, Table II-3. 713 Id., at 16. 714 SCE-25, Vol. 4 at 16:17-20, at 17, Figure II-2 - 307 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 traditional analysis, Standard Practice U-4. We further note, we have questioned the expert judgment applied by SCE for its traditional analysis in the previous two SCE general rate case decisions, D.12-11-051 and D.15-11-021. We are left with little that supports recognition of SCE’s proposed ballooning amount for depreciation. SCE, however, rather than requesting as part of its revenue requirement the nearly $1 billion its analysis would suggest proposing, moderates its proposal to less than one-tenth of what – if reliable – would be fiscally responsible and proposes an $84 million increase to its depreciation accrual. We are left with a failure of any party to establish by a preponderance of the evidence the validity of their proposed net salvage ratios, along with our own recognition that due to the costs of removal net salvage is nearly always negative. Therefore, we find it reasonable to maintain in most instances the net salvage ratios which were previously adopted by D.15-11-021. We also note Standard Practice U-4’s reliance on regularly updated numbers increases the likelihood the net salvage ratios are reliable. As SCE states, “in future rate cases, SCE will have the ability to take its then-surviving plant balances to even better refine its projections about the future in light of then-available conclusions about historical costs-per-unit.”715 18.2. T&D Net Salvage SCE has proposed increases to most net salvage ratios, tempered by a 25% cap for T&D accounts. As discussed above, we do not adopt the proposed net salvage ratios based on SCE’s depreciation studies, but rather maintain the ratios 715 SCE Exhibit 09, Vol. 3, at 8:6-8. - 308 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 adopted in the 2015 GRC for most accounts. For those accounts for which SCE proposed a net salvage ratio which is equal to or lower than the ratio which was previously authorized, we have accepted the SCE proposal as reasonable. The following table provides a summary of the contested accounts and the amounts authorized. Account (all values are negative) 2015 GRC SCE TURN Adopted       Transmission Plant 352 - Structures and Improvements 35% 35% 35% 35% 353 - Station Equipment 15% 10% 10% 10% 354 - Towers and Fixtures 60% 75% 35% 60% 355 - Poles and Fixtures 72% 90% 100% 72% 356 - Overhead Conductors & Devices 80% 100% 60% 80% 357 - Underground Conduit 0% 0% 5% 0% 358 - Underground Conductors & Devices 15% 19% 15% 15% 359 - Roads and Trails 0% 0% 5% 0%       Distribution Plant 361 - Structures and Improvements 25% 30% 30% 25% 362 - Station Equipment 25% 31% 30% 25% 364 - Poles, Towers and Fixtures 210% 263% 210% 210% 365 - Overhead Conductors & Devices 115% 144% 100% 115% 366 - Underground Conduit 30% 38% 50% 30% 367 - Underground Conductors & Devices 60% 75% 75% 60% 368 - Line Transformers 20% 25% 35% 20% 369 - Services 100% 125% 70% 100% 370 - Meters 5% 0% 0% 0% 373 - Street Lighting & Signal Systems 30% 38% 100% 30% 18.3. Life SCE’s proposed service lives are disputed for only three categories of assets: (1) T&D (Account 369), (2) hydroelectric (hydro) facilities; and (3) solar photovoltaic facilities. - 309 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 18.3.1. T&D Life SCE proposed service lives for all but two T&D accounts that are the same, or longer, as the service lives authorized in the 2015 GRC. ORA did not oppose any of SCE’s T&D life proposals. TURN disputed only the proposed life for Account 369, Services. SCE proposed decreasing the service life for Account 353, Station Equipment, by five years. The dollar-weighted average service life for this category is 44 years. We find the evidence does not support changing the adopted service life from the currently authorized 45 years. SCE proposed decreasing the service life for Account 367, Underground Conductors & Devices, by two years, to 43 years. The proposal is consistent with the weighted average service life for this account and is adopted. SCE proposed maintaining a 45 year service life for Account 369, Services, even while acknowledging that its own data produces a result suggesting an estimated service life of 65 years. SCE however, questions its own data due to a change from three-phase bare-wire conductor which was identified as three units of property to triplex which is categorized as one unit. This change then resulted in accounting modifications which leads SCE to doubt the analysis as to the estimated service life. Instead of relying on data driven analysis – as SCE does for other accounts – SCE argues we should revert to reliance on a simulated plant record and maintain the authorized service life from the 2015 GRC. We find SCE’s disregard for its own data troubling and are not persuaded by SCE’s arguments against its consideration. TURN’s proposal to accept a 55 year service life is reasonable and is more consistent with historical data and therefore, is adopted. - 310 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Unless otherwise noted above, SCE’s proposals are approved. The following table shows a summary of the accounts. Account 2015 GRC SCE TURN Adopted TRANSMISSION PLANT 350.2 Easements 60 60 60 352 Structures and Improvements 55 S 3.0 55 L 1.0 55 L 1.0 353 Station equipment 45 R 0.5 40 L 0.5 45 R 0.5 354 Towers & Fixtures 65 R 5 65 R 5 65 R 5 355 Poles & Fixtures 50 R 0.5 65 SC 65 SC 356 Overhead Conductors & Devices 61 R 3 61 R 3 61 R 3 357 Underground Conduit 55 R 3.0 55 R 3.0 55 R 3.0 358 Underground Conductors & Devices 40 R 2.5 45 S 1.0 45 S 1.0 359 Roads and Trails 60 SQ 60 R 5.0 60 R 5.0 DISTRIBUTION PLANT 360.2 Easements 60 60 60 361 Structures and Improvements 42 R 2.5 50 L 0.5 50 L 0.5 362 Station Equipment 45 R 1.5 65 L 0.5 65 L 0.5 364 Poles, Towers & Fixtures 47 L 0.5 55 R 1.0 55 R 1.0 365 Overhead Conductors & Devices 45 R 0.5 55 R 0.5 55 R 0.5 366 Underground Conduit 59 R 3.0 59 R 3.0 59 R 3.0 367 Underground Conductors & Devices 45 R 0.5 43 R 1.5 43 R 1.5 368 Line Transformers 33 R 1 33 S 1.5 33 S 1.5 369 Services 45 R 1.5 45 R 1.5 370 Meters 20 R 3.0 20 R 3.0 20 R 3.0 373 Street Lighting & Signal Systems 40 L 0.5 48 L 1.0 48 L 1.0 38 R 3.0 45 R 0.5 45 R 0.5 55 R 1.5 55 R 1.5 GENERAL BUILDING 390 Structures and Improvements 18.3.2. Hydro Life SCE proposes to set the depreciable life of hydroelectric facilities equal to the average remaining years on the facilities’ current FERC licenses, unless the - 311 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 license is expired or will expire within five years. For those facilities, the depreciable life is assumed to be extended by forty years to approximate the anticipated renewal period. For facilities outside the five-year window of expiration, renewal is not assumed. SCE argues in its Reply Brief that it is not suggesting all hydro facilities more than five years from license expiration will be decommissioned. “Rather, the point is to estimate a reasonable depreciable life for the turbines, generators, and other hydro assets that will be replaced before the final decommissioning of the overall facility.”716 SCE further contends this is consistent with Commission practice, logically ties to applicable federal regulations, and avoids assuming renewal of licenses for small hydro facilities due to their uncertain economics.717 TURN was the only party to contest SCE’s proposal for hydroelectric facilities. TURN does not dispute SCE’s approach for facilities with over fifteen years to license expiration (adopt as the service life the time to license expiration) or for facilities with under five and one-half years to license expiration (adopt as the service life the time to expiration, extended by forty years). TURN proposes, for those facilities with between 5.5 and 15 years remaining life until license expiration, the service life be extended by 33.7 years. TURN derives this number by reducing the forty year renewal period by 16% (reflecting SCE’s experience of decommissioning of hydro facilities).718 The currently authorized hydro depreciation rate is 2.68%. SCE’s proposal would increase the rate to 3.57% and would increase the annual accrual by $10.5 716 SCE Reply Brief, at 161-162. 717 SCE Reply Brief, at 161. 718 TURN Opening Brief, at 325. - 312 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 million. TURN’s proposal would result in a rate of 2.13%, a decrease of $5.5 million.719 The evidence supports recognizing the vast majority of licenses will be renewed. SCE has not met its burden to establish the authorized depreciation rate of its hydroelectric plant is 3.57% based on its anticipated service life which presumes all facilities with a remaining service life over five and one-half years will not be renewed. We adopt as reasonable a rate of 2.13%. 18.3.3. Solar Life The 2015 GRC adopted a 25-year average service life for SCE’s solar PV assets based in part on an admission on SCE’s website and manufacturer warranties.720 SCE now contends the previously authorized 20-year average service life should be readopted. We find SCE’s contention that the service life for solar PV assets should more nearly match the roof life and lease life is reasonable. We adopt a 20-year average service life for solar PV assets. 18.4. Generation Decommissioning SCE proposes to escalate costs of decommissioning generation plant to the anticipated cost in the year of retirement and, based on that inflated cost, seeks to accrue depreciation on an annual basis over the remaining service life of the plant. For example, based on a solar PV decommissioning expense of $80.8 million in 2038, assuming a twenty year service life, SCE proposes we adopt an annual accrual of $4.04 million. 719 The difference between the two proposals is $16 million. SCE Opening Brief, at 268. 720 D.15-11-021, at 429-430. - 313 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 TURN counters decommissioning expenses should be escalated to 2020, consistent with Standard Practice U-4. TURN’s proposal avoids collecting dollars now on a vastly inflated expense. TURN’s proposal is persuasive; SCE has not met their burden to support recovery of the escalated expense without a concurrent adjustment to the annual accrual. We therefore adopt the annual accrual proposed by TURN for Mountainview 3 & 4 of $0.3 million, Solar PV of $3.2 million, and Peakers of $0.2 million. 18.5. Depreciation Study – Additional Issues We continue to be troubled by the inadequacy of SCE’s evidence supporting its claimed depreciation expense. As indicated (but not accepted) by the per unit analysis and suggested gradualism, the depreciation expense may be significantly greater than what is accepted here. If so, the cost of removing plant may not be adequately funded by the depreciation reserves. That outcome could raise the question as to whether future ratepayers should bear the burden of paying more for plant than the benefit they receive or whether that cost should be borne by shareholders due to SCE’s own evidentiary failings and to avoid the proscription of Public Utilities Code §454.8. Therefore, we direct SCE to work with TURN, ORA, the Energy Division, and any interested parties to develop a more reliable depreciation study for the Commission to examine and consider in the next GRC. This study should not support only the incremental request for depreciation, but also, the amount already accrued. We expect that SCE’s next depreciation study will present depreciation expenses that rely much less on expert opinion and judgment, and much more on data and statistical analyses. - 314 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 19. Rate Base – Additional Issues We discussed in section 17 that Rate Base represents the depreciated value of assets used to provide service to customers and the product of the Rate Base and the authorized rate of return equals a utility’s return on its shareholders’ investment. In some instances, SCE’s spending was more than what had been authorized by the 2015 GRC decision, D.15-11-021. In other instances, capital investments or a portion of an investment were not allowed in a prior decision. In a third instance, TURN argues for a disallowance based on alleged imprudence. Now, in this application, SCE has proposed that these investments should be included in rate base and SCE should earn its authorized rate of return on them. TURN is uniformly opposed to these additions to rate base, contending that expenditures which have not been authorized or which were imprudent, should not, by the passage of time, be authorized and added to rate base. 19.1. Aged Poles SCE’s opening testimony recounts that: In the 2015 GRC Decision, the Commission approved only part of SCE’s Aged Pole program to systematically replace aged poles on a proactive basis …. The Commission authorized SCE’s replacement of more than 14,000 aged poles over the period 2013 to 2015. SCE actually replaced 8,586 more poles than what the Commission authorized.721 SCE’s testimony shows the shortfall of authorized compared to actual spending for this program in 2014 and 2015 was $108 million and states, SCE “did not collect the revenue requirement on these aged poles during the period 721 SCE-09, Vol. 2, at 3:19 – 22. - 315 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 2015-2017. Starting in 2018, SCE’s plant balances will reflect the remaining book value of the replacement.”722 SCE contends that the shortfall of the $108 million resulted in lost revenues of $23 million over the 2015-2017 GRC cycle, that “SCE has permanently foregone those revenues”723 and the “extent of the remedy SCE has already endured” is a sufficient basis to support recovery now for the additional 8,586 poles which were not previously authorized.724 We found in D.15-11-021 that it was prudent for SCE to replace 5,245 of these aged poles in 2013 and an additional 9,000 in 2014 to support the “ramp up” for the Pole Loading Program and in recognition that some value was being provided to ratepayers because some poles may have failed in service while also recognizing some could have continued to provide service to ratepayers for many years to come.725 In D.15-11-021 we disallowed additional aged pole expenditures, stating, The fact that the new poles provide service to ratepayers and are used and useful is insufficient to prove that the expenditures to purchase and install the poles should be recovered from rates. That question turns on the prudency of the investment decision.726 19.1.1. SCE Has Not Presented Evidence Supporting Recovery SCE does not answer the question as to the prudency of the investment decision, stating “SCE does not seek re-litigation of the merits of the program in 722 Id. at 4:4-6. 723 SCE Opening Brief, at 284. 724 SCE Reply Brief at 165. 725 726 Id., at 113-114. D.15-11-021, at 112. - 316 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 this case.” Instead, SCE acknowledges “… SCE replaced too many poles based solely on their age even though they may have provided additional months or years of service …” and contends “… no one can know, today, how many more months or years sixty-five or seventy-year-old poles would have continued to provide service had SCE not replaced them under the Aged Pole program.”727 SCE contends TURN’s remedy of permanently removing from rate base the previously disallowed capital expenditures is “extreme,” stating, TURN’s proposal unreasonably assumes that the imprudence related to early replacement extends to the average life of the replacement poles, or 55 years, and relatedly assumes that customers are to receive free electric utility service from these poles to overcome the utility’s ambitious safety initiative spanning an 18-month period. This unfair, punitive and unreasonable outcome should be rejected outright.728 SCE, in response, assumes that the disallowance ordered in D.15-11-021 must be interpreted to have extended only to that rate cycle, allowing SCE to begin “cost recovery of the replacement poles … at a significantly discounted price in 2018.”729 SCE argues the aged poles would have failed eventually and the replacement poles are “used and useful” providing “decades of future value to ratepayers.”730 We agree TURN’s proposal to disallow recovery for replacement poles would have to implicitly find that the aged poles which were replaced would not have failed during the lifetime of the replacement poles. That is a finding which 727 SCE Opening Brief, at 284. 728 Id., at 283. 729 Id., at 282-283. 730 Id., at 282. - 317 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 logic dictates we cannot make. Additionally, SCE is correct, the replacement poles are now used and useful. As we stated in D.15-11-021 however, whether the poles are used and useful is not the only question which must be answered. SCE still has not answered the question posed prior to D.15-11-021, a precondition before we would allow recovery in rates for expenditures to purchase and install the poles. That question turns on the prudency of the investment decision. SCE has not established, indeed has not presented evidence, which would support a finding that it was prudent to replace poles (beyond the poles the Commission authorized) which continued to be used and useful at the time they were replaced. Absent evidence – which we indicated in D.15-11-021 should be provided – supporting the prudence of early replacement of aged poles over higher frequency of inspections or pole reinforcement or other evidence which would support the prudency of the expenditure, we continue to disallow recovery for the 8,586 more aged poles SCE replaced over what the Commission authorized.731 In disallowing recovery now we note our decision is based on a failure by SCE to establish the prudence of its expenditure: that it was reasonable to replace poles which although “aged” continued to be used and useful. We are presented with an unknown period of time during which it was not prudent to replace the existing poles but also recognize that at some point in time it would become prudent to replace these aged poles. Therefore, we do not preclude SCE from attempting to establish in its next GRC the prudency of replacing the 8,586 poles by a certain date or dates. 731 D.15-11-021, at 114 authorized recovery of actual replacements in 2013 of 5,245 (originally stated to be 5,330) and 9,000 of the 14,500 poles requested. The program was not authorized for 2015 as it was originally intended to provide a ramp up for other pole replacement programs. - 318 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 19.1.2. Other Disallowances From the 2015 GRC Decision TURN has identified two other disallowances from the 2015 GRC which SCE would like to include in rates now and to which TURN objects. These are capital expenditures for the Advanced Technology Laboratories and the Pebbly Beach Generation Automation Project. 19.1.2.1. Advanced Technology Laboratories In D.15-11-021 we disallowed half of the request for the Westminster Lab upgrades because SCE did not establish portions of the upgrades were related to matters that should be funded by ratepayers. We disallowed all of the request for the Equipment Demonstration and Evaluation Facility (EDEF) “because SCE has not shown that the technical problems it would address are unique to SCE and that other more cost-effective options do not exist for doing this research.”732 The disallowance for Westminster for 2014 was $1.8 million and for 2015 was $2 million. The disallowance for EDEF for 2014 was $3.3 million and for 2015 was $4.4 million. SCE responds to the Commission’s determination that “SCE has not shown that the problems it would address are not unique to SCE” by stating “EDEF was not designed for that purpose.”733 SCE then argues “the standard in judging these expenditures is whether they are prudent”734 and supports its claim of prudence by asserting 732 Id., at 50. 733 SCE-02, Vol. 11, at 33:12. 734 Id., at 33:16. - 319 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE identified a specific need for a set of capabilities that would allow it to safely, reliably, and prudently accelerate testing and deploying new technologies to support California’s energy and environmental goals, and specifically with respect to its fault detection activities, work to improve grid safety.735 As TURN notes, however, “SCE simply does not address the Commission’s valid concern that the capabilities supported by EDEF may not need to be owned by SCE but rather could be obtained through vendors or research institutions.”736 As for whether SCE has demonstrated “other more cost-effective options…exist for doing this research” SCE relies on its survey to which thirteen research facilities/laboratories responded. SCE claims the survey results show SCE’s own facility is the only facility which can meet all of SCE’s needs, making EDEF “the most efficient means to execute this work.737 TURN’s review of the survey result finds however, that the survey shows every feature SCE wants could be provided by multiple facilities.738 Consistent with D.15-11-021, we continue to consider it to be relevant whether or not the facility would address problems which are unique to SCE. We also continue to find SCE has not established that other more cost-effective options do not exist. SCE claims a single facility (their own) is more cost effective but they have provided nothing to support that claim. In recognition that the services provided by Westminster (now Fenwick) and EDEF could not have been 735 Id., at 33:13-16. 736 TURN-11, at 5:3-5. 737 SCE-02, Vol. 11, at 33:24-25. 738 TURN-11, at 5:17-24. - 320 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 obtained for nothing and that these facilities are used and useful and therefore providing some value to ratepayers, we allow half of the expenditures for these facilities (including maintaining the one-half disallowance for Westminster and the entire disallowance for EDEF adopted in D.15-011-021) and adopt capital expenditures for SCE’s laboratories, as follows. Advanced Technology Capital Expenditures ($000) Project 2016739 2017 2018 2019 2020 2016-2020 Fenwick Labs (Westminster) 1,033 2,347 2,098 3,129 4,778 13,385 Pomona Lab740 1,110 1,701 1,205 1,320 1,390 6,726 338 1,142 264 272 281 2,297 EDEF 19.1.2.2. Pebbly Beach Automation The disallowance of capital expenditures for the PBGS Automation Project is discussed at section 7.4.2. 19.2. 2014-15 Capital Spending Above Authorized TURN has identified five infrastructure programs for which SCE recorded, for 2014 and 2015, $235 million more capital spending than was authorized by D.15-11-021.741 The programs are four T&D Infrastructure Replacement programs: WCR, Substation Transformer Bank Replacement, Substation Circuit 739 In SCE-18, Vol. 11 at 6, SCE agreed with ORA to use 2016 recorded (instead of forecasted) capital expenditures for Advanced Technology Labs. 740 The amounts requested for Pomona were not disputed and are adopted. 741 TURN-12, at 14-15. - 321 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Breaker Replacement, and “Other” (including Underground Oil Switch Replacement), and a new program: Overhead Conductor. TURN argues these amounts (and others) should be disallowed because the Commission has not previously found these amounts to be reasonable and SCE’s showing of reasonableness is inadequate.742 SCE responds that the assets are used and useful, SCE made prudent decisions concerning these expenditures, evaluations of reasonableness should not be made program-by program, and that its showing is adequate.743 We agree with TURN that SCE cannot establish reasonableness based simply on a claim that an expenditure was made and has resulted in an investment which is used and useful for SCE’s customers.744 SCE does not disagree. SCE acknowledges, “It is well established that while utilities have the ultimate burden to prove the reasonableness of any costs they request, any party contesting those costs has the burden of going forward to produce evidence to support its own position.”745 Although the fact that an expenditure has been made and there is evidence that the asset is used and useful may support a finding that a capital expenditure in excess of amounts authorized by an earlier GRC decision is reasonable, the existence of these factors does not preclude our review on a “program-by-program” basis of the reasonableness of the expense. 742 TURN Opening Brief, at 340. 743 SCE-25, Vol. 3, at 20-32. 744 TURN Opening Brief, at 340-341. 745 SCE Reply Brief, at 173, quoting D.15-03-049, at 6. - 322 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Excepting the Overhead Conductor program, SCE has met its burden of proof to establish that these expenditures have resulted in used and useful assets at a just and reasonable expense. In reaching this finding we consider not just the limited evidence of the expenditures for 2014 and 2015, but rather we consider the totality of the evidence supporting these programs. TURN’s limited focus on 2014 and 2015 takes these expenditures out of context of those programs in which the expenditures are made and does not meet TURN’s burden of production in this instance. Therefore, we accept the recorded capital expenditures for these Infrastructure Replacement programs excepting the Overhead Conductor program. As discussed in section 4.8.4, we impose a 10% disallowance of the 2015 and 2016 Overhead Conductor recorded costs of $155.456 million, resulting in a disallowance of $15.55 million. Therefore, we approve, $115 million for 2014 and $52.3 million for 2015, following the disallowance for the Overhead Conductor program. 19.3. Changes in Accounting TURN has identified two separate accounts for which costs were initially approved as O&M expenses in prior GRCs and which SCE subsequently capitalized and put into rate base. These accounts are for underground location costs (Account 588.281) and real property expenses (Account 920.220). $4.2 million was expensed for underground location costs in the 2015 GRC but then subsequently capitalized and $9.9 million for real property was expensed in the 2012 and 2015 GRCs but has been capitalized since 2013.746 TURN does not object to the accounting changes. TURN’s objection is to what it characterizes as 746 TURN Opening Brief, at 349. - 323 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 double recovery for amounts which were initially forecast as expense and were subsequently capitalized.747 TURN recommends a disallowance of $1,420,000 for each of 2015, 2016, and 2017 as representative of capitalized underground locating costs for those years which had been forecast as an O&M expense in the 2015 GRC.748 TURN recommends the disallowance be permanent.749 TURN further recommends a disallowance of $9.94 million from gross plant due to real property expenses which were recovered by the 2012 and 2015 GRCs even though an accounting change capitalizing this recovery was made in 2013. TURN also recommends this disallowance be permanent.750 SCE does not dispute TURN’s calculations. Instead, SCE contends the adjustments should be rejected because: 1) SCE needs to accurately and timely record its expenses to either capital or O&M; 2) a change to accounting is not “an assault on the integrity of the future test year ratemaking process” because the $14 million in dispute is 0.1% of SCE’s T&D capital for the period (2013-2017); and, 3) allowing only accounting changes which coincide with rate case test years would be inconsistent with current practice.751 We agree SCE should continue to accurately and timely record its expenses to capital or O&M. We also agree SCE’s accounting changes are reasonable and 747 Ibid., at 350. 748 TURN also recommends that SCE remove 17.48% of recorded expenses from the historical period (2011-2014) from O&M Account 588.281, resulting in a $363,000 downward adjustment to the forecast. SCE stipulated to this adjustment in SCE-29 at 33. 749 TURN Opening Brief, at 350. 750 Id. 751 SCE Opening Brief, at 294-296. - 324 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 not an assault on the integrity of the future test year ratemaking process. Lastly, we find no reason to delay accounting changes to coincide with rate case test years. We also find there is no reason to permit SCE a double recovery of capital expenditure of amounts previously authorized and adopted by an O&M forecast. Therefore, we disallow $4.26 million from gross plant ($1.42 million for each of 2015, 2016, and 2017) for underground location costs (Account 588.281) which was expensed in the 2015 GRC but then subsequently capitalized. We also disallow $9.94 million from gross plant for real property expenses (Account 920.220) which was expensed in the 2012 and 2015 GRCs but has been capitalized since 2013. Each of these disallowances are permanent. 19.4. SPIDACalc Pole Issues In April 2013 SCE began using SPIDACalc, a software program, to calculate pole loading safety factors for its poles. Based on its use of SPIDACalc, SCE forecast for its 2015 GRC that 3% of its poles would require repair and 19% would need to be replaced. In D.15-11-021 we adopted a forecast of 18,213 pole replacements per year (for 2015 through 2025) for SCE’s Pole Loading Program and authorized a corresponding capital expenditure of $245.006 million.752 Shortly after SPIDACalc was launched, SCE began receiving reports of larger than expected poles being recommended by the program.753 Ultimately SCE began using a new version of SPIDACalc (version 6 as opposed to Version 5) 752 D.15-11-021, at 140 - 141. 753 SCE-25, Vol. 3, at 48:6-7. - 325 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 and SCE found the predicted failure rate was reduced by approximately 55% for PLP pole replacements and 50% for non-PLP pole replacements.754 After SCE and TURN submitted their testimony they agreed to submit joint testimony setting forth the calculations for potential disallowances arising from SCE’s use of SPIDACalc resulting in the premature replacement of poles. This testimony, SCE-TURN-01, SCE-TURN Joint Supplemental Testimony Regarding SPIDA Software Disallowance Scenarios and Calculations, while confirming the parties’ disagreement as to whether or not a disallowance is warranted, provides agreed testimony as to the potential disallowance based on various timing scenarios and other factors. The following table sets forth the possible disallowances. Table IV-1755 Impact to 2018 GRC cycle revenue requirement (in millions of dollars) Starting Date Returned to Returned to Rate Rate Base after 20 Base after 10 No years years Disallowance All Gates All Gates All Gates Poles 1-4 Poles 1-4 Poles 1-4 Complete Disallowance All Gates Poles 1-4 April 2013 $0 $0 $74.7 $74.7 $120.1 $120.1 $210.5 $210.5 September 2014 $0 $0 $69.9 $64.8 $112.3 $104.2 $196.9 $182.6 January 2015 $0 $0 $66.5 $56.4 $106.9 $90.7 $187.4 $159.0 September 2015 $0 $0 $38.9 $21.7 $62.5 $34.9 $109.5 $61.1 754 SCE-TURN-01, 4:13-16. 755 SCE-Turn-01, at 9. - 326 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 SCE and TURN agree the numbers set forth on the above table reflect the present value revenue requirement for each of the agreed scenarios. SCE and TURN also agree that an adopted disallowance (if any) for this SPIDACalc pole replacement issue should be spread over the entire three-year GRC cycle of 2018-2020. The numbers shown are stated to capture the “impact of the lower revenue requirement associated with removing the poles from rate base and then returning them to rate base at a later date….” and thereby eliminate the need for any further rate base adjustment.756 SCE advocates for no disallowance based on the belief “it acted prudently to procure, deploy, improve, and eventually update SPIDACalc Version 5 with Version 6” but also argues that if a disallowance is adopted by the Commission is should consider the fact that these prematurely replaced poles would have been replaced eventually.757 TURN proposes a disallowance for the life of the replacement poles for two reasons. First, due to SCE’s delay in placing a “reassessment hold” on pole replacements until September 1, 2015, despite its earlier concerns that SPIDACalc v5.0 was identifying poles for replacement which would meet pole loading safety factors. Second, TURN advocates a complete disallowance due to SCE’s failure to inform the Commission about these issues with SPIDACalc during the 2015 GRC.758 Alternatively, the parties have agreed to proposed disallowances if the Commission decides some level of pole replacement at 10 years and 20 years. 756 Id., at 8. 757 Id., 5:24-6:2. 758 TURN, Opening Brief, at 352-359. - 327 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 The proposed disallowances assume that the poles replaced due to the use of SPIDACalc v5.0 would have been replaced within that amount of time. The 10-year proposed disallowance is derived from the 9.6 year difference in the age of poles replaced in the PLP using SPIDACalc v5.0 compared to the age of poles replaced in the deteriorated Pole program. This proposal presumes that poles which failed SPIDACalc v5.0 but passed SPIDACalc v6.0 were close to being overloaded and would have needed to be replaced due to deterioration within an additional ten years.759 TURN has alternatively proposed a 20-year disallowance based on the argument that the 10-year proposed disallowance presumes the prematurely replace poles were in poor condition, but it is more reasonable to presume the condition of the prematurely replaced poles was consistent with the rest of SCE’s poles. On this basis, TURN proposes relying on the 55-R1 life curve to estimate age Based on this estimate, TURN assumes the actual expected life of the prematurely replaced poles would have been between 30 years and the 10 years proposed by SCE and proposes 20 years.760 The “Gates” in the table refers to steps in SCE’s pole replacement process. SCE contends poles in Gates 5 or 6 should be excluded because reassessment would not have been practical at that time because a pole at Gate 5 has already been released for installation.761 The starting dates proposed by the SCE-TURN table are based on possible times for the Commission to find the expenditures for poles should be 759 SCE-Turn-01, at 6:3-19. 760 Id., 6:20-7:9. 761 Id., 7:16-21. - 328 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 disallowed. April 2013 is the initial implementation date of SPIDACalc v5.0. September 2014 is the time of the first major update of SCE’s Engineering Team to PLP Management of SCE’s internal evaluation of SPIDACalc v5.0. January 2015 reflects the conclusion of the engineering evaluation leading to the development of SPIDACalc v6.0. September 2015 coincides with SCE’s instruction to its contractor to hold all assessments based on SPIDACalc v5.0 to permit reassessment using SPIDACalc v6.0 following confirmation that SPIDACalc v5.0 had overstated the need for replacement by at least 50%.762 We begin with the recognition and findings that no pole will last forever, that it was imprudent to replace poles prematurely, and that premature replacement, when the poles continued to be useful, resulted in a loss of value to ratepayers. Therefore, we exclude from further consideration both the “No Disallowance” options and the “Complete Disallowance” options. We find that it is just and reasonable to base the impact to the SCE revenue requirement on returning the value of these poles to rate base after 20 years. This 20-year disallowance is based on our finding that it is reasonable to presume the life span of the prematurely replaced poles would have been consistent with the life span of the rest of SCE’s poles. Furthermore, we find SCE did not meet its burden to establish a shorter life span for these poles. Lastly, we adopt April 2013 as the commencement date for disallowing these pole expenditures. April 2013 is when SCE began using SPIDACalc v5.0. We find it was not prudent of SCE to use SPIDACalc v5.0 at that time due to SPIDA’s lack of experience, SCE’s inadequate vetting of the software (it did not 762 Id., 6:7-18. - 329 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 perform an engineering benchmark or any field testing or verification prior to procurement),763 and a lack of prudence by SCE in embarking on a program of this magnitude. SCE acknowledges pole loading assessment is a “very complex set of analysis” with “a lot of assumption.”764 It recognized the “sheer volume of pole loads being conducted by SCE will naturally amplify (more quickly) any small issue with any software product.”765 Nevertheless, this new pole loading assessment software was deployed almost immediately to assess an “unprecedented number of pole loads per year through PLP.”766 Despite this, SCE proceeded to select an unknown software with which it had no prior experience767 and which was anticipated to “launch SPIDA into the level of major pole assessment vendors.”768 Based on these facts, we find SCE’s selection of SPIDACalc v5.0 and immediate implementation lacked prudence and supports disallowing recovery of all expenditures for poles which were prematurely replaced due to SCE’s imprudent use of the software. Therefore, we reduce SCE’s revenue requirement by $120.1 million over the 2018-2020 GRC cycle. 19.5. Correction for Shareholder Assigned Costs Beginning with the 2006 GRC decision and continuing with each successive GRC decision since then, the Commission has barred SCE from 763 SCE-25, Vol. 3, Appendix E. 764 RT, Vol. 16:17-19, 24-25. 765 SCE-25, Vol. 3, at 43, fn. 94. 766 Id. 767 RT Vol. 16, 2245:6-9. 768 SCE-25, Vol 3, Attachment 1, at 1-4. - 330 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 recovering through customer rates certain portions of employee compensation. These items relate to the Short-term Incentive Program, Executive Incentive Compensation, and Supplemental Employee Retirement Plan. Historically SCE applied a capitalization rate to these expenses, thereby capitalizing a portion of them. Although SCE adjusted the revenue requirement to reflect the assignment of these costs to shareholders, it had not made the adjustment to plant-in-service to remove the portions of the capitalized costs which the Commission had assigned to shareholders. Instead the rate base continued to include these costs for benefits. In April 2017, SCE discovered this issue and concluded an adjustment to SCE’s forecast is necessary. The intervenors do not contest SCE’s testimony or the proposed adjustment. SCE estimates the reduction to rate base will be approximately $34 million in 2018. In addition to the rate base adjustment, SCE filed an advice letter refunding to customers the cumulative capital revenue requirement from 2009 through 2017, plus interest relating to this adjustment.769 19.6. Rate Base – Additional Issues The additional issues raised by SCE’s Opening Brief and TURN’s Reply are issues which we have discussed and applied as it concerns specific expenditures and forecasts, such as for Catalina and for the Pole Loading Program following SCE’s use of SPIDACalc. SCE raises them generally because TURN, in its discussion of specific expenditures and forecasts, has advocated we adopt certain policies of general application concerning these issues. 769 See Advice Letter 3702-E, effective as of December 21, 2017. - 331 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 First, SCE contends it should continue to be permitted to “true up” rate base during a GRC test year when it has spent more than it was authorized in the previous GRC cycle. Although we agree, we note it should not be presumed that the true up will be authorized following review by the Commission. As SCE states (and we agree), “[t]o the extent the utility is expected to justify expenditures above those specifically authorized, the standard is whether the utility acted reasonably.”770 SCE then attempts to place limits on our judgment, stating, “[t]hat judgment by the Commission may go to the reasonableness of the timing of the investment …”771 We agree when reviewing expenditures which are in excess of an adopted forecast, SCE must establish the reasonableness of the timing of the investment. SCE, however, must also establish that the amount of the investment is fair and reasonable to rate payers. The fact that money has been spent on something that is used and useful for ratepayers does not necessarily establish that the expenditure was fair and reasonable and should be recovered in rates. Second, SCE contends that when the Commission disallows an expenditure due to imprudence, it does not necessarily mean the investment should never be included in rate base. TURN argues there should be a “fundamental rule: … a capital expenditure disallowed in a prior decision must stay disallowed.” This would create a presumption that the disallowance would continue 770 SCE Opening Brief, at 304. 771 Ibid. - 332 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 … unless and until the Commission states otherwise. And if the utility (or any other party, for that matter) believes that the Commission should change its treatment of previously disallowed amounts, the burden would be on that party to establish the reasonableness of the proposed change to the previously disallowed amount.772 SCE agrees that investments which the Commission has found are not used and useful to customers should never be included in rate base. By contrast, SCE argues that when the investment is a used and useful asset, the utility may meet its burden of proof in a subsequent GRC to establish the reasonableness of the expenditure. We agree and have applied these principles to specific expenditures elsewhere in this decision. We decline to create a presumption that once an expenditure has been disallowed it must stay disallowed. We, however, agree that a party advocating the Commission should change its treatment of previously disallowed amounts bears the burden to establish the reasonableness of the proposed change. It should not be presumed that since the expenditure has resulted in the creation of a used and useful asset that the expenditure is also prudent and recoverable. 20. Results of Examination Public Utilities Code § 314.5 provides in relevant part, The commission shall inspect and audit the books and records for regulatory and tax purposes (1) at least once every three years in the case of every electrical … corporation serving over 1,000 customers …. An audit conducted in connection with a rate proceeding shall be deemed to fulfill the requirements of this section. 772 TURN Opening Brief, at 331. - 333 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA states that it conducted an examination of SCE’s financial records in accordance with the foregoing section and sections 314 and 309.5 of the Public Utilities Code.773 The general objectives of ORA’s examination are to ensure that the interests of ratepayers are reasonably protected and that SCE’s financial records, on which the GRC was built, were reasonable and proper for ratemaking purposes under established Commission rules and regulations.774 ORA had no recommended adjustment to expenses associated with:  SCE-02, Transmission and Distribution  SCE-03, Customer Service  SCE-04, Information Technology  SCE-05, Power Supply  SCE-06, Human Resources, and  SCE-07, Operational Services.775 Based on ORA’s results of the Utility Plant review for 2013 to 2015, ORA proposed an audit adjustment to increase weighted average Customer Advances for Construction (CAC) and reduce weighted average Rate Base for 2015 by $2.267 million.776 SCE made this adjustment in errata prior to the filing of ORA’s testimony.777 773 ORA-22, at 1:11-13. 774 ORA Opening Brief, sec. 21, at 250. 775 ORA-22, at 2. 776 ORA-22, at 2. 777 SCE-09, Vol. 2A, at 45, Table IV-14. - 334 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Additionally, ORA reviewed various balancing and memorandum accounts:  RRIMA (Residential Rate Implementation Memorandum Account, Oct 2015-June 2016)  RIIM (Reliability Investment Incentive Mechanism) and successor account SRIIM (Safety and Reliability Investment Incentive Mechanism)  Bark Beetle CEMA (Catastrophic Event Memorandum Account) (2012-2014)  PDDMA (Project Development Division Memorandum Account)  MCAGCCMA (Marine Corps Air Ground Combat Center Memorandum Account, Oct 2014 – Jun 2016)  SOBA (Edison Smart Connect Opt-Out Balancing Account, Apr 2012 – Jun 2016)  RSDMA (Residential Service Disconnection Memorandum Account, Jan 2015 – Jun 2016)  EDRPMA (Energy Data Request Program Memorandum Account, Dec 2014 - Jun 2016)  CDAP (Customer Data Access Project costs), also known as ESPI Energy Service Provider Interface costs) and  TAMA Distribution (Tax Accounting Memorandum Account, 2015) and  TAMA Generation (Tax Accounting Memorandum Account, 2015) ORA found no required accounting adjustments. ORA found that the accounting entries to the foregoing 10 accounts for the periods indicated are appropriate, correctly stated and in compliance with applicable Commission decisions. ORA does not object to SCE’s proposals regarding the 10 balancing - 335 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 and memorandum accounts and regulatory mechanisms for modifying, recovering, eliminating and continuing accounts.778 21. Compliance In this GRC, SCE provided a separate exhibit summarizing its compliance with requirements it has identified in its 2006, 2009, 2012 and 2015 GRC decision, as well as other relevant proceedings or settlements.779 SCE states its purpose is to demonstrate that it has complied with all relevant orders of the Commission. SCE provides a list of 37 items, with the following information for each item:780  The Commission decision adopting the compliance action item;  The required action by SCE;  The supporting decision reference; and  SCE's Compliance Action and Status: a brief summary of the status of any compliance action items and or a reference (to SCE's exhibits or workpapers in this proceeding) where compliance with a particular item is addressed. We have reviewed SCE's compliance showing and agree with SCE that it demonstrates SCE's compliance with each of the 37 listed items. Furthermore, we find the format of SCE's presentation to be very helpful in facilitating our review, and we direct SCE to include the same showing as a separate exhibit in its 2021 general rate case testimony. 778 ORA-22, at 23-27. 779 SCE-10, “Compliance Requirements from 2009-2015 GRC Decisions Requirements from other Proceedings and or Settlements.” 780 Id., Table II-1, Southern California Edison Company 2018 General Rate Case Reporting and Compliance Items. - 336 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 22. CEMA Bark Beetle Recovery SCE recorded $10.5 million in O&M expenses to its Bark Beetle CEMA for 2012-2014. Pursuant to Resolution E-3238, SCE has requested we find these expenses are reasonable, and authorize the transfer of the December 31, 2014 balance in the Bark Beetle CEMA O&M Cost Sub-account, $10.6 million, to the Base Revenue Requirement Balancing Account (BRRBA) for recovery in rates.781 ORA reviewed SCE’s Bark Beetle CEMA, and does not oppose SCE’s request for rate recovery.782 We approve the request. 23. CALSLA Issues SCE owns and maintains over 680,000 streetlights in its service territory.783 SCE provides streetlight service pursuant to three tariffs:  LS-1, a non-metered, SCE-owned streetlight tariff;  LS-2, a non-metered, customer-owned streetlight tariff; and  LS-3, a metered, customer-owned streetlight tariff. SCE initiated a process in 2013 whereby governmental entities within its service territory could negotiate with SCE to purchase the streetlight systems located within their jurisdiction. Over 80 cities expressed interest in the purchase of the SCE streetlights in their respective communities.784 However, in Spring 2015 SCE informed the cities and other jurisdictions in its service territory that it would no longer accept requests for streetlight acquisition submitted after 781 SCE-12, at 1. 782 ORA-22, at 24 and 27. 783 SCE-02, Vol. 5 at 39. 784 SCE-26, at 1. - 337 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 August 15, 2015. Local governments could enter a queue by August 15, 2015 in order to preserve the opportunity to purchase streetlights, by entering into an agreement to purchase within one year from the date of SCE’s delivery of their respective community’s valuation.785 In its June 2017 rebuttal testimony, SCE provided the following status report as of May 2017:  SCE had received CPUC approval and completed streetlight sales agreements with six cities;  An additional 19 communities were engaged in negotiations or preparing to submit completed agreements to the CPUC; and  Seven additional communities were also actively working with SCE at that time to finalize and sign agreements for the purchase of streetlights in their communities.786 SCE notes that sales of utility assets such as these streetlights, which are necessary and useful in the provision of electric service, require Commission approval under Public Utilities Code Section 851. The Commission established a procedure that allows for § 851 approval via Advice Letter for transactions of less than $5 million, while transactions above that amount require an application. As 785 Id. at 2. SCE states that communities that received their valuation prior to the queue closure date of August 15, 2015 had until August 15, 2016 to enter into an agreement with SCE. Local governments that did not enter into a purchase agreement before the expiration of the one year deadline are no longer able to purchase SCE streetlights through the negotiation and sale process. 786 Ibid. - 338 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 of May 2017, SCE had submitted three Advice Letters and three applications seeking Commission approval for sale of streetlight systems under § 851.787 Testimony addressing SCE's streetlight acquisition program and the issue of LED rebates was submitted by the California City-County Street Light Association (CALSLA). CALSLA represents all street light and traffic control customers in California that receive electric service from SCE (as well as PG&E and SDG&E). A number of SCE's streetlight customers, representing 21 jurisdictions that account for 110,000 streetlights, co-sponsored exhibits with CALSLA.788 CALSLA and its co-sponsors provide five recommendations regarding SCE's streetlight acquisition program, and a sixth, related recommendation regarding the Commission’s LED rebate funding for streetlights, which would apply to lights that are currently being evaluated for sale under SCE's streetlight acquisition program. While this GRC proceeding may not provide direct solutions to each of CALSLA's issues, we review them here and direct certain additional actions by SCE and CALSLA that we intend to repair what appears to be an inefficient and dysfunctional acquisition process. The first three of CALSLA's recommendations are interrelated. CALSLA notes that the overall purchase price valuation provided by SCE consists of the cost of the lamps plus fees and taxes, which CALSLA describes as "adjustments 787 Id. at 3. 788 Exhibit CALSLA-1 presents CALSLA's "Report on Streetlight Programs" and recommendations, while Exhibits CALSLA-2 through CALSLA-12 present the testimony of the co-sponsors. The co-sponsoring entities are the City of Downey, the City of Huntington Beach, the City of La Verne, the City of Norwalk, Orange County, the City of Palmdale, the City of Rialto, the City of Santa Ana, the City of Temecula, the City of Tustin, and the Western Riverside Council of Governments. - 339 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 and fees for additional asset components, ad hoc replacements, transition costs, property taxes, and a tax assessment."789 SCE calculates the value of the lamps using a standard "Replacement Cost New Less Depreciation" (RCNLD) method. According to CALSLA, "the price is non-negotiable, and SCE refuses to consider other methods of valuation such as comparable sales or the capitalization of net income."790 CALSLA states that the additional fees and taxes are charged on a case-bycase basis and may not be applied to each sale. For that reason, it is very difficult for public agencies to understand the nature of SCE’s fees and under what circumstances the fees are applied. SCE’s sales proposals are brief and provide little discussion of SCE’s valuation methodology or the reason for added fees.791 In light of the above, CALSLA's first recommendation is that SCE should provide a detailed explanation of all taxes, fees, and charges (line-item by lineitem) included in the sales price of street light assets being considered under SCE's street light acquisition program. In rebuttal, SCE contends that it "has been and continues to be transparent in providing every participating jurisdiction with detailed explanations of the valuation methodology and adequate engagement opportunities for questions and feedback."792 SCE's rebuttal on this first item is not credible to us, given that CALSLA and the co-sponsoring jurisdictions are plainly stating that whatever SCE is telling them or providing to 789 CALSLA-01 at 6. 790 Id., at 4, citing SCE's response to a CALSLA data request. 791 Id., at 6-7. 792 SCE-26 at 6. - 340 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 them is not clear enough to enable the buyers to understand SCE's pricing method. Apart from this matter of basic clarity, CALSLA states that it takes issue with the substance of the tax assessments and the transition fees themselves. Thus, CALSLA's recommendation #2 is that the tax assessment fee should be eliminated from pending street light sales, and CALSLA's recommendation #3 is that the transition fee should also be eliminated from pending street light sales. Instead, CALSLA recommends that SCE should record tax losses as well as profits from street light sales in a balancing account and, in the next GRC, SCE should file workpapers detailing the net proceeds from the sales. If there is a net tax loss across the street light customer class, SCE should recover the loss via a monthly surcharge on participating lamps.793 Regarding the transition fee, CALSLA contends that "the fee collects mapping and inventory management costs that have already been accounted for in revenue requests from past GRCs and recouped from LS-1 rates [so] the transition fee double charges customers for these expenses."794 SCE addresses CALSLA's contentions and recommendations in its rebuttal testimony, suggesting that CALSLA is misinterpreting the substance and purposes of the taxes and fees in question. SCE's response, even if correct on the substance, is surprising to us in that (as we just described above) SCE asserted several pages earlier in the same rebuttal testimony that it "has been and continues to be transparent in providing every participating jurisdiction with 793 CALSLA-01 at 7. 794 Id., at 8. - 341 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 detailed explanations of the valuation methodology and adequate engagement opportunities for questions and feedback." The purchasers say they cannot understand SCE's valuations, SCE responds that it has explained everything, but when the purchasers make recommendations regarding SCE's estimated taxes and fees, SCE responds that the purchasers simply don't understand these terms. SCE cannot have it both ways here. CALSLA's fourth, fifth and sixth issues and recommendations are also interrelated, and have to do with SCE's less-than-enthusiastic approach to the acquisition process. CALSLA's recommendation #4 is that customers should be permitted to purchase mast arms and luminaires attached to shared distribution poles. CALSLA notes that PG&E does allow customers to purchase lamps on shared distribution poles, citing a 2013 sales agreement with the City of Richmond. CALSLA recommends that SCE should use Pole Contact Agreements to facilitate customer ownership and maintenance of street lights on shared poles. In rebuttal, SCE simply responds that CALSLA’s recommendation would jeopardize public and program participant safety, ignoring the PG&E precedent.795 CALSLA's recommendation #5 is that the Commission should require SCE to transfer street lights to the customer with 30 days of approval of the sale by the CPUC. CALSLA describes SCE’s current policy of conducting lamp-by-lamp inspections prior to the transfer of lamps to the customer as unreasonable. Instead, CALSLA offers that customers will commit to work with SCE to conduct a true-up of SCE’s inventory. In rebuttal, SCE describes the steps it takes in its 795 SCE-26 at 12. - 342 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 inspection process and asserts that its "current inspection process protects ratepayers and provides an accurate accounting of streetlights to be sold or maintained under SCE ownership."796 However, despite acknowledging local government concerns "that these and other delays result in financial hardships for customers" SCE provides no evidence that its current inspection policy really does protect ratepayers. Nor does SCE appear open to CALSLA's suggestion that SCE work collaboratively with the purchasers to find a more cost-effective solution. All of CALSLA's concerns coalesce to produce its sixth and final recommendation: due to the delays in the acquisition process that CALSLA attributes to SCE throughout its testimony, CALSLA recommends that customers should not lose rebates on LED streetlights that were scheduled to be eliminated on January 1, 2018 "because of unreasonable delays caused by SCE."797 CALSLA states that customers sought to purchase their streetlights and converting them to LED to capture energy savings and lower their bills, and that in some instances their purchase plans are no longer feasible without the rebates. In rebuttal, SCE simply notes that LED rebates are not addressed in this GRC proceeding and suggests that CALSLA pursue its proposal in SCE’s Energy Efficiency Business Plan proceeding (A.17-01-013). SCE does not respond to the allegations underlying CALSLA's recommendation: Customers expected SCE to make a good faith effort to efficiently evaluate the lamps and conduct the sales. Yet, this has not been the case. SCE caused 796 Ibid. 797 CALSLA-01 at 15. - 343 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 significant delays in the transfer of street lights to customers to the extent that LED rebates are now in jeopardy. The acquisition program has been active for five years, and yet very few sales have occurred due to no fault of customers.798 CALSLA's testimony--and SCE's response in its rebuttal testimony-indicates to us that SCE's process for transferring streetlight ownership should be improved. More than anything, we find the difficulties reported by CALSLA, and SCE's response to CALSLA's concerns, to be puzzling. While SCE's testimony is not clear on this point, it appears that SCE created this program on its own initiative in 2013. SCE invited the cities and other governmental entities to submit requests to purchase SCE's streetlights, charging them $10,000 each for that opportunity. Then (apparently) SCE had a change of heart about selling these assets, such that the company is now either digging in its heels or dragging its feet in its "negotiations" with the interested jurisdictions. Indeed, CALSLA states that SCE's valuations are presented as "non-negotiable" and SCE's rebuttal to CALSLA suggests in several instances that if SCE and a city are not able to reach a mutually agreeable sales price, that is not really a problem that should concern this Commission because alternatives courses of action are available: either SCE can continue to own and operate the streetlight system, or the city can pursue an eminent domain action in Superior Court to condemn SCE's streetlight system in order to acquire the assets, at a valuation determined by the court. Thus, SCE concludes that there is no need for the Commission to intervene in this "negotiating" process or otherwise set the terms of contract negotiations.799 798 Id. at 11. Unfortunately, the rebates described by CALSLA were in fact terminated by the Commission in 2018. 799 SCE-26 at 3 and 9. Quotation marks added. - 344 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Again, to be blunt, much has happened to alter the very landscape of California and SCE's territory since SCE filed this GRC application in 2016, and it is inarguable that SCE, these jurisdictions, and this Commission have new and extremely pressing and challenging issues that demand their attention. So it concerns us greatly that--as CALSLA observes with its references to SCE's T&D testimony on Distribution Construction & Maintenance, which includes SCE's requested funding for its Street Lighting Program--we are approving SCE's use of ratepayer funds in this GRC to (in part) manage this streetlight acquisition program, only to learn that SCE is approaching the task in such a litigious manner. This is an inappropriate and unreasonable use of ratepayer funds and should not continue. We direct SCE to meet and confer with CALSLA and all interested officials from affected jurisdictions in order to prepare a joint proposal to address each of the concerns raised in CALSLA's testimony regarding (1) the information that interested jurisdictions receive, or do not receive, during the acquisition process, (2) the possibility of including mast arms and luminaires attached to shared distribution poles in streetlight acquisition agreements, (3) more efficient transfer of streetlights following Commission approval of a sale, (4) exploration of the question of the impact of delays on receipt of LED rebates, and (5) any other issues that the Commission could address. The joint proposal should be provided either as part of SCE's testimony when it files its next GRC application, or as a supplemental exhibit as soon as possible after that date. Both sides are encouraged to seek assistance from the Commission's Alternative Dispute Resolution program if that would expedite their efforts or avoid conflict. - 345 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 24. Other Issues 24.1. Tax Memorandum Accounts The 2015 GRC decision authorized SCE to establish a TAMA. SCE proposes in this proceeding to extend the TAMA so it may continue to mitigate any tax-related ratemaking implications resulting from estimating differences between forecast and incurred repair deductions, changes in tax law and guidance associated with tax depreciation, and the impact of any tax accounting method changes.800 No intervenor opposed this proposal.801 On November 6, 2017, SCE filed Advice Letter 3610-E under rules relating to its TAMA. The filing was due to an accounting change relating to deductible capitalized software. SCE proposes, and we approve, SCE continue to record in a memorandum account any recorded to forecast differences related to deductible capitalized software and trued up through memorandum accounts through 2020.802 We agree the TAMA should be extended; however, the extension of the TAMA in its current form will limit the effectiveness of this important account. We do not find the limitations on TAMA to be beneficial. We consider additional requirements for TAMA to be reasonable. Commission precedent supports a policy of requiring the utilities subject to our jurisdiction establish memorandum accounts to track the various costs and benefits of newly enacted tax law. In 2011, following passage of the federal Tax Relief Act, the Commission adopted Resolution L-411A in order to 800 SCE-09, Vol. 2, at 20. 801 ORA-02, at 2; SCE-02-T, at 2-4. 802 SCE-59, at 42-43. - 346 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 … preserve the opportunity for the Commission to decide at a future date whether some of the impacts of the Tax Relief Act, not otherwise reflected in rates, ought to be reflected in future rates, without having to be concerned with issues of retroactive ratemaking.803 The Tax Relief Act created the likelihood of large and unexpected decreases in tax expense for the utilities which, due to the timing of Commission rate cases, created the possibility that benefits of the tax decrease might not accrue to ratepayers in the same way they would if the tax decrease had been expected. The Commission’s solution to this challenge was to direct certain utilities, to establish memorandum accounts in order to allow the Commission to determine at a future date whether rates should be changed, without the impediment of claims of retroactive ratemaking. Based on that precedent, and consistent with our identical orders in the SDG&E and SoCalGas Test Year 2016 proceeding and the Liberty Utilities Test Year 2016 GRC,804 in D.17-05-013 we created a memorandum account to track all differences between forecast and recorded tax expenses so that we could more closely examine revenue impacts caused by PG&E’s implementation of various tax laws, tax policies, tax accounting changes, or tax procedure changes. This was intended to help the Commission review the reasonableness of PG&E’s election of various tax options, such as various tax policies, tax procedures, or tax accounting changes. The memorandum account has separate line items detailing the differences between tax expenses forecasted and tax expenses incurred, specifically resulting from (1) net revenue changes, (2) mandatory tax law 803 Resolution L-411A, at 3. 804 D.16-12-024, Ordering Paragraph 6. - 347 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 changes, tax accounting changes, tax procedural changes, or tax policy changes, and (3) elective tax law changes, tax accounting changes, tax procedural changes, or tax policy changes. The account remains open and the balance in the account shall be reviewed in every subsequent GRC proceeding until a Commission decision closes the account.805 ORA, in its updated testimony following the passage of the 2017 Tax Cuts and Jobs Act (TCJA) and SCE’s own updated testimony, recommends that the Commission adopt a broadened tax memorandum account consistent with that adopted for the other investor owned utilities.806 We agree SCE should establish a new tax memorandum account, consistent with that adopted by the other investor owned utilities. As we have required of SDG&E, SoCalGas, and PG&E, SCE shall notify the Commission of any tax-related changes, any tax-related accounting changes, or any tax-related procedural changes that materially affect, or may materially affect, revenues. Our reference to “materially affect” means a potential increase or decrease of $3 million or more. The failure to disclose such changes in a timely fashion undermines the integrity of the regulatory process, and may amount to a violation of Rule 1.1. Finally, we find that the establishment of a memorandum account is consistent with Resolution L-411A at 13 in which the Commission stated: We believe that an even handed approach to regulation requires us to consider, when there has been a large and unexpected decrease in expenses 805 See, D.17-05-013, at 115-118. 806 ORA-02-T, at 2-7:6-22. - 348 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 between rate cases, whether it is appropriate to establish a memorandum account to allow for a future decrease in rates. 24.2. SCE Request for Oral Argument We note SCE has requested final oral argument pursuant to Rule 13.13 of the Commission’s Rules of Practice and Procedure section 16 of the Scoping Memo and Joint Ruling of Assigned Commissioner and Administrative Law Judges issued in this proceeding. The request was granted. Final oral argument was held June 20, 2018. 25. Conclusion Excepting as is otherwise discussed by this decision, the application of Southern California Evidence is granted. 26. Comments on Proposed Decision The proposed decision of ALJs Roscow and Wildgrube in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission’s Rules of Practice and Procedure. Comments were filed on _____________, and reply comments were filed on ___________________ by __________________. 27. Assignment of Proceeding President Picker is the assigned Commissioner and Stephen C. Roscow and Eric Wildgrube are the assigned ALJs in this proceeding. Findings of Fact 1. With respect to individual uncontested issues in this proceeding, we find that SCE has made a prima facie just and reasonable showing, unless otherwise stated in this opinion. Transmission and Distribution - 349 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Operational Overview 2. SCE’s forecasts of OpX savings are reasonable. Risk Informed Decision Making 3. SCE, ORA and CUE agree that the Commission should not base its decision on safety related-cost recovery on SCE's risk informed decision making analyses until SCE’s planning approach is further developed. Safety and Reliability Investment Incentive Mechanism (SRIIM) 4. SCE's proposed enhancements to SRIIM, with the modifications SCE agreed to make in response to CUE, are reasonable. Residential line extension 5. SCE’s approach to forecasting cable feet per installed meter for residential line extensions is reasonable. Residential Tract Development 6. SCE’s approach to forecasting cable feet per installed meter for residential tract developments is reasonable. Rule 20 Issues 7. The Commission’s decision in PG&E’s 2017 Test Year GRC ordered PG&E to establish a one way Rule 20A balancing account that tracks the annual capital and expense costs for Rule 20A undergrounding projects, on a forecast and recorded basis. 8. The Commission ordered that overcollected balances in the account shall remain available for future Rule 20A projects, and that the balances in the account would be reviewed in PG&E’s next GRC proceeding. Distribution Transformers - 350 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 9. New service connections are a major driver for new transformer purchases, but most distribution work activity involves installing or replacing under sized, failed or deteriorated transformers. T&D – System Planning 10. In the context of T&D System Planning, the term “grid” refers to “the infrastructure comprised generally of transmission lines, substations, distribution circuits, and critical equipment such as circuit breakers, relays, substation transformers, conductors, and automation apparatus.” 11. The overall drivers of SCE’s planning process are accommodating increased capacity needs (resulting from new customers or increased load from existing customers) while meeting system reliability. Photovoltaic (PV) Dependability and Capacity Driven Capital Expenditures 12. It is reasonable to accept SCE’s use of its PV Dependability study for the purpose of preparing its GRC forecast. Distribution Circuit Upgrades 13. SCE considers distribution circuit upgrades when it forecasts any portion of its distribution system to be overloaded and if existing distribution equipment cannot meet the needs of the system. 14. SCE cannot and should not require wholesale DERs, already connected to SCE's system, to pay for circuit upgrades triggered by new retail DER. New Distribution Circuits 15. SCE builds new distribution circuits as part of three types of projects: (1) new substation projects, (2) substation capacity increase projects, and (3) as standalone projects. - 351 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 16. ORA’s methodology did not address SCE’s project-specific forecast and ORA does not contest the need for any specific projects SCE identified as necessary. Substation Expansion Projects 17. Substation expansion projects fall into three categories: (1) substation capacity projects located within scope in the existing substation footprint; (2) substation expansion that includes projects where the substation perimeter fence requires expansion; and (3) new substations. 18. ORA expects the new “Safari” substation will be delayed and will not be completed in this GRC cycle, but additional information provided by SCE in its rebuttal testimony supports a conclusion that it is more likely than not that the new “Safari” substation will be completed in this GRC cycle. Substation Equipment Replacement Program 19. Funding for SCE’s Substation Equipment Replacement Program is used to replace overstressed circuit breakers on SCE’s system. Subtransmission Lines Plan 20. SCE expended less than forecast for its Subtransmission Lines Plan in 2016 due to construction permitting and other unexpected delays on specific projects, but SCE’s forecast for the 2018-2020 GRC period is based on project specific requirements during this period. 4 kV Programs 4 kV Cutover Program 21. SCE’s 4 kV Cutover Program converts portions of 4 kV circuits to higher voltages in order to reduce load and foster reliability. 22. SCE has demonstrated that its methodology for estimating the scope and cost of its 4 kV cutover program is reasonable. - 352 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 4 kV Substation Elimination Program 23. SCE’s 4 kV Substation Elimination Program involves conversion of the entire 4 kV circuitry from a substation to higher voltage. 24. Now that SCE proposes to expand the pace of its 4 kV Substation Elimination Program, a closer look is warranted. 25. TURN’s analysis of SCE’s 4 kV Substation Elimination Program demonstrated that the program provides questionable benefits. Grid Reliability Projects 26. The Commission granted SCE a permit to construct the Cerritos Channel Transmission Tower Replacement Project in D.18-08-021 and noted that construction of the project is scheduled to begin September 1, 2018 and to be completed by the fourth quarter of 2020. 27. The Cerritos Channel Transmission Tower Replacement Project is unlikely to be used and useful during the 2018-2020 rate case period. T&D – Distribution Maintenance and Inspection 28. SCE’s method of forecasting its T&D Distribution Maintenance and Inspection O&M and capital costs by using its 2015 recorded adjusted expenses as a basis for proposed Test Year projects and activities is reasonable. T&D – Distribution Construction and Maintenance 29. SCE’s explanation of a misunderstanding by ORA regarding O&M for Street Lighting Operations and Maintenance (FERC sub account 585.170) is reasonable. 30. SCE has not made a persuasive argument that ratepayers should fund SCE’s service guarantees. - 353 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 31. ORA’s testimony demonstrated that SCE significantly underspent the budgets for Distribution Storm O&M (FERC sub account 598.170) authorized by the Commission in its 2012 GRC and its 2015 GRC. 32. A one-way balancing account for Distribution Storm Expenses could lead to an unbalanced outcome where ratepayers would receive refunds in years when the weather was mild, but shareholders would fund part of storm-related repairs in years when the weather was more severe. T&D – Substation Construction & Maintenance 33. SCE’s rebuttal testimony effectively refuted ORA’s recommendation to reduce SCE’s requested funding for Substation Physical Security. T&D – Transmission Construction & Maintenance 34. SCE’s forecast expenses for two items in FERC Account 571.150, (1) Transmission Overhead and Underground Line Maintenance and (2) Transmission Vegetation Management, are reasonable. Transmission Tools and Work Equipment 35. Regarding SCE’s capital forecast, ORA recommends reductions of $616,000 in 2016 and $519,600 in 2017 for transmission tools and work equipment activities. 36. SCE used a five year average (2011-2015) to develop its 2016 – 2018 forecasts due to the unpredictability of equipment retirements and external drivers. 37. ORA proposes to use SCE’s recorded adjusted capital expenditure for 2016, and SCE agrees. 38. SCE effectively rebutted ORA’s critique of SCE’s forecast capital expenditures for transmission tools and work equipment activities and demonstrated that its forecast is reasonable. - 354 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 T&D – Infrastructure Replacement Worst Circuit Rehabilitation Program 39. In rebuttal testimony and at hearing, SCE justified its forecast capital expenditures for its Worst Circuit Rehabilitation Program. Cable Life Extension Program 40. SCE’s capital expenditure forecast for its Cable Life Extension Program is reasonable. Cable-In-Conduit Replacement Program 41. SCE’s capital expenditure forecast for its Cable-in-Conduit Program is reasonable. Overhead Conductor Program 42. SCE developed and implemented its Overhead Conductor Program (OCP) following the Commission's decision in SCE’s 2015 rate case. 43. Although the Commission had not authorized any funding for OCP in D.15-11-021, once the program became operational SCE replaced 74 circuit miles in 2015 and 202 circuit miles in 2016, with recorded capital expenditures for the program equal to $58 million in 2015 and $97 million in 2016. 44. TURN demonstrated that incorrect engineering created circumstances where some wires may have more extensive damage that they would otherwise, thus justifying its recommended 10% disallowance. 45. ORA demonstrated in testimony that SCE provided no explanation of how it determined that annual replacement of 300 circuit miles would be optimal. Underground Oil Switch Replacement Program 46. SCE’s capital expenditure forecast for its Underground Oil Switch Replacement Program is reasonable. Capacitor Bank Replacement Program - 355 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 47. SCE originally forecast $34.744 million in capital expenditures for 2017 2018, based on a forecast annual replacement volume higher than the historical five year average, albeit “significantly” lower than the steady state replacement rate. 48. SCE agreed to accept TURN’s proposal to use 2014 unit costs, which reduces SCE's forecast to $27.692 million. Automatic Recloser Program 49. SCE’s 2017-2018 capital expenditure forecast for its Automatic Recloser Program is reasonable. PCB Transformer Replacement Program 50. SCE’s 2017-2018 capital expenditure forecast for its PCB Transformer Replacement Program is reasonable. Substation Infrastructure Replacement Program 51. SCE’s 2017-2018 capital expenditure forecast for its Substation Infrastructure Replacement Program is reasonable. T&D – Poles Poles--Capital Expenditures 52. For pole-related capital expenditures, TURN demonstrated in its testimony that these costs increased by amounts “above and beyond” general inflation. 53. TURN asks reasonable questions regarding the reasons SCE’s contractor costs increased much faster than the rate of inflation, and SCE has not responded with a fact based explanation. 54. SCE has not affirmatively demonstrated that its contractor costs are reasonable and its circular argument that, because SCE uses a competitive process, the results of that process must be reasonable, is insufficient. - 356 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 55. It is reasonable to adopt TURN’s recommended downward adjustment of the unit costs for the categories listed below by removing SCE’s reported increase in contractor costs from 2012 to 2015: Distribution Deteriorated Pole Replacement and Restorations Pole Loading Distribution Pole Replacements Pole Loading Transmission Pole Replacements Transmission Deteriorated Pole Replacement and Restorations T&D – Grid Modernization Grid Modernization Capital Expenditures Distribution Automation Programs 56. It is reasonable to approve less funding for distribution automation than requested by SCE, because a lower amount will result in the proper balance between SCE’s need to maintain and upgrade aging infrastructure while also accommodating realistic levels of DER growth in the 2018-2020 GRC period. 57. TURN’s testimony regarding the DER portion of distribution automation shows that beyond a limited number of installations, there is insufficient value to installing more advanced Remote Intelligent Switches to achieve full switching automation. Communications 58. SCE has not demonstrated the need to proactively update substations by implementing a Substation Automation (SA 3) program at this time. 59. The Common Substation Platform (CSP) will deliver cybersecurity and interoperability benefits 60. SCE has demonstrated that the Field Area Network (FAN) will provide cybersecurity benefits and ensure that distribution devices have sufficient communications. - 357 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 61. TURN demonstrated in testimony that funding for Distribution System Efficiency Enhancement Program (DSEEP) will enable SCE to maintain the existing communications network while the new FAN is being installed. 62. SCE should be authorized $15 million for the Distribution System Efficiency Enhancement Program (DSEEP) over the 2018-2020 period. This amount reflects SCE’s historic rate of spending for the DSEEP. 63. SCE’s showing did not demonstrate why expenditures for a Wide Area Network (WAN) are necessary during this GRC period. Tools for Data Analysis and Decision Making 64. SCE's request for its System Modeling Tool (SMT) is compliant with the DRP proceeding. 65. SCE's request for its DRP External Portal is compliant with the DRP proceeding. 66. The Grid Management System (GMS) will provide cybersecurity benefits, enable DERs, and integrate SCE’s distribution software. T&D – Grid Technology Distribution Volt VAR Control 67. SCE reasonably established that its proposed Distribution Volt VAR Control (DVVC) program is intended to provide reliability benefits and benefits of reduced energy costs for SCE’s customers. Energy Storage Pilots 68. ORA’s objection to SCE’s Distributed Energy Storage Integration (DESI) pilot program is incorrect because ORA has misunderstood Commission policy regarding such pilot programs. 69. The DESI pilots do not meet the criteria for Electric Program Investment Charge (EPIC) funding, but they do meet the criteria for GRC funding. - 358 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 70. Pursuant to D.12-05-037, Ordering Paragraph 3, the Commission defined an EPIC-eligible RD&D project as one that supports research into the installation and operation of pre-commercial technologies. 71. The energy storage technologies that SCE proposes to implement in its DESI pilots are in the early stages of the technology maturity cycle, but these technologies are already commercially available. 72. The DESI pilots involve expenditure for capital projects that will be “used and useful” for the duration of their service lives, and “will provide energy services to customers for the useful life of the asset, rather than for a particular project or demonstration” in contrast with EPIC projects that are only funded for a three year period. 73. SCE demonstrated that the proposed DESI pilots will provide ratepayer benefits that could not be obtained with existing pilots or SCE-owned storage facilities. T&D – Safety Training & Environmental Programs Environmental Program – Transmission (FERC Account 565.281) 74. SCE’s O&M forecast request is based on the environmental remediation work forecasted for specific transmission projects in 2018-2020, and uses the same methodology the Commission adopted for SCE in D.15-11-021. Hazardous Waste Management & Disposal – Distribution (FERC Account 598.250) 75. SCE’s proposal to use a multi-year average as the forecasting methodology Distribution Hazardous Waste Management & Disposal (FERC Account 598.250) due to the unpredictable nature of this account is reasonable. SCE properly excluded two years showing unusually high activity, which would have otherwise inflated its forecast. - 359 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 T&D – Other Costs, Other Operating Revenues T&D –Other Operating Revenues 76. SCE receives Other Operating Revenues (OOR) from transactions not associated with the sale of electric energy. Tariffed OOR is based on CPUC or FERC approved rates, and offsets the revenue requirement SCE would otherwise collect from general ratepayers. T&D – Other Costs 77. SCE’s forecasts for Transmission and Distribution Work Order write-offs are based on five year averages of recorded data, a method approved by the Commission in SCE’s two most recent GRC proceedings because accounts like these are influenced by forces outside SCE’s control. 78. SCE’s rebuttal testimony provided a detailed and reasonable explanation of the logic underlying SCE’s calculations costs for Transmission and Distribution Capital Related Expense, as well as a detailed critique of ORA’s method. 79. SCE accepted TURN’s recommended methodological change to SCE’s calculation of its forecast for underground locating services (FERC Account 588.281). This results in a test year forecast equal to $8.227 million, which is $363,000 lower than SCE’s original request of $8.590 million. Customer Service Re-Platform 80. Tracking the costs and benefits of CS Re-Platform in a memorandum account is reasonable. Customer Service – O&M 81. We find the link between customer growth and increased expenses to be tenuous and to support TURN’s recommendations against upward adjustments - 360 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 of SCE’s forecasts based on growth due to the impact of automation and increasing efficiency. Meter Reading Operations – FERC Account 902 82. The reduced proposal of $9.909 million, removing the projected increase due to growth, is reasonable. Test, Inspect, and Repair Meters – FERC Account 586.400 83. The proposed reduction eliminating the increase for customer growth and the reduced proposal of $15.438 million is reasonable. Turn-On and Turn-Off Services – FERC Account 586.100 84. SCE established the increase of $114,000 for customer growth. Excluding $289,000 for CS Re-Platform benefits, we find $5.164 million reasonable. Customer Installation and Energy Theft Expense – FERC Account 587 85. We find $6.506 million for this account is reasonable. Meter Services Operations and Management – FERC Account 580 86. We find $5.671 million is reasonable following reduction of $155,000 for customer growth. Billing Services – FERC Account 903.500 87. We find $23.645 million is reasonable. Credit and Payment Services – FERC Account 903.200 88. Excluding the increase for customer growth and CS Re-Platform expenses and benefits, we find reasonable $15.477 million for this account. Postage – FERC Account 903.100 89. Following an adjustment for the 2018 postal rate increase we find reasonable TURN’s proposed adjusted forecast of $14.371 million. Uncollectable Expenses – FERC Account 904 - 361 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 90. TURN’s recommended forecast of 0.211% based on a five-year average of 2012 – 2016 using 2016 unadjusted data is consistent with the downward trend of the data. Customer Contact Center– FERC Account 903.800 91. It is reasonable to accept $43.779 million for this account. Business Customer Division– FERC account 908.600 92. We find reasonable a forecast of $18.790 million. Customer Programs and Services– FERC account 905.900 93. We find reasonable the forecast of $24.656 million for Customer Programs and Services. 94. SCE has demonstrated a commitment to outreach to its diverse communities which is consistent with NDC’s recommendations; we will not impose greater requirements. Operating Unit Management and Support–FERC Accounts 901 and 907.600 95. We find reasonable for FERC Accounts 901 and 907.600 a forecast of $6.887 million. Customer Service – Capital 96. We find reasonable $24.251 million for 2017 and $34.956 million for 2018. Customer Service – Other Operating Revenue 97. SCE estimates OOR to be $27.981 million in Test Year 2018. The forecast is undisputed and reasonable. Customer Service – Additional Issues 98. SCE and SBUA entered into two joint exhibits and stipulations, SCE-SBUA–1 and SCE-SBUA-2. The commitments agreed to by SCE within these stipulations are reasonable and further the interests of ratepayers generally and small business customers of SCE specifically. - 362 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Information Technology – O&M and Hardware Hardware/Software Licenses & Maintenance 99. SCE has met its burden to establish the forecast of $70.73 million for this account. Business Integration & Delivery 100. A 2018 forecast for BID of $37.196 million is reasonable. Grid Services 101. The forecast for Grid Services for 2018 of $34.5 million is reasonable. Information Technology – Capitalized Software 102. ORA proposed using SCE’s recorded capital expenditures in place of forecast expenditures for 2016 for several capitalized software projects. SCE did not object, provided “2016 recorded costs are used for all IT capital projects and cherry-picking is not utilized.” 103. Except as noted, we find it reasonable to use the 2016 recorded capital expenditures. Contingency Amounts in Capitalized Software Forecasts 104. SCE’s request for 2017 of $24.75 million and $23.86 million for 2018 software contingencies is not reasonable. 105. We find disallowing these contingencies should motivate SCE to remain within its forecast budgets for these projects. If additional funds become necessary, SCE may seek to establish that necessity in the next GRC. Cybersecurity and Compliance 106. We adopt as reasonable and exclusive of contingencies, $22.590 million for 2016, $52.003 million for 2017, and $47.457 million for 2018 for Cybersecurity and Compliance software. - 363 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 107. We agree with SCE that their showing is adequate and a memorandum account is not needed. We also agree further review of how to address cyber-related information would be appropriate in another forum. Grid Modernization Cybersecurity 108. We adopt the 2016 recorded expense of $2.901 million and find reasonable 40% of the forecasted expenses (less contingencies) for 2017 and 2018, $5.34 million and $8.063 million, respectively. Other Capitalized Software Vegetation Management Project 109. We find reasonable the recorded expense for 2016 of $916,000 and the forecast (less contingency) for 2017 of $4.75 million for the Vegetation Management Project. Comprehensive Situational Awareness for Transmission 110. Comprehensive Situational Awareness for Transmission (CSAT) was known as Advanced Phasor Data Analytics when approved by D.15-11-021. 111. SCE’s lack of transparency for how the previously approved funding was spent leads us to find SCE’s revised forecast is not just and reasonable for ratepayers. Instead, we find the 2016 recorded expense of $0, $0.476 million for 2017, $0.951 million for 2018, $3.236 million for 2019, and $3.236 million for 2020 to be just and reasonable to ratepayers. Grid Planning & Analytics Software 112. We accept as reasonable the recorded expense for 2016 for the GIPT, GAA, LTPT, and GCM projects of $9.371 million, and 50% of SCE’s request (the forecast less contingencies), $12,796 million for 2017, and $7.332 million for 2018. Enterprise Content Management Project - 364 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 113. SCE has established the distinctions between ECM and eDMRM and that the ECM project is reasonable and necessary. The requests (the forecast less contingencies) of $2.833 million for 2017, and $4.333 million for 2018 are reasonable. Operating System Software 114. We find reasonable the forecast capital expenditure for this account for 2016 of $8.75 million, and the forecast less contingencies, of $13.113 million for 2017, and $19.80 million for 2018. Information Technology - Customer Service Re-Platform 115. The factors to support establishing a memorandum account to track Customer Service Re-Platform costs, benefits, and capital expenditures for review in the next GRC are present. Information Technology – Managed Services Providers 116. SCE’s use of Managed Services Providers and its request for this account are reasonable. Generation 117. ORA proposed using SCE’s recorded capital expenditures in place of forecasted expenditures for 2016 for SCE’s generation capital expenses. SCE has agreed with this recommendation. Except as noted below, we agree and find reasonable the 2016 recorded capital expenditures. Generation – Catalina Catalina – O&M 118. ORA accepts SCE’s 2018 forecast for O&M for this account of $4.374 million. It is reasonable and we approve it. Catalina – Pebbly Beach Generating Station Automation - 365 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 119. The costs for the PBGS Automation Project have not been established to be just and reasonable and therefore, we do not allow them. Catalina – Other Capital Projects Under $3 million 120. We find ORA’s recommendation is just and reasonable and adopt the 2016 actual recorded expense of $.007 million and the forecast of $0.448 million for each of the years 2017 and 2018. Solar Photovoltaic 121. SCE submits its 2013 and 2014 O&M expenses for reasonableness review in this GRC. SCE incurred $8.286 million for 2013 and $4.270 million for 2014. These expenses are not disputed and we find them reasonable and recoverable. Fuel Cells 122. SCE’s forecast for O&M for its fuel cell program is $0.379 million. This amount was not disputed. We find it is reasonable. Human Resources 123. Legislation passed in 2018 prohibits an electrical or gas corporation from recovering from ratepayers any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of the electrical corporation or gas corporation, and requires that compensation instead be funded solely by shareholders of the utility. 124. Commission Resolution E-4963 ordered SCE and other affected utilities to establish “Officer Compensation Memorandum Accounts” (OCMA) with an effective date of January 1, 2019. 125. SCE complied by filing Advice Letter 3927-E, which was approved by the Commission’s Energy Division on January 29, 2019. Human Resources Department and Executive Officers Human Resources Operating Unit - 366 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 126. No parties contested the reasonableness of SCE's forecast for HR Department O&M expenses. Executive Officers 127. Executive Incentive Compensation (EIC) awards are largely based on shareholder benefits. 128. SCE financial performance may benefit ratepayers, but the ratepayer benefit is much less direct than the shareholder benefit. 129. The additional testimony prepared by SCE regarding its EIC Plan, while informative, is not evidence that the EIC awards incent executives to achieve ratepayer benefits. 130. We remain unconvinced that ratepayers should fund 100% of SCE’s EIC program. Benefits and Other Compensation Short Term Incentive Program 131. It is reasonable to continue to use the same ratio of total STIP spending to labor expense (12.11%) as we adopted in D.15-11-021. 132. Even though the STIP and the EIC use the same financial metric, and even though the Commission adopted a 40% reduction for the EIC, the Commission only adopted a 10% reduction for the authorized STIP amount in the 2015 GRC based on the financial performance metric. Long Term Incentives 133. Parties’ positions regarding Long Term Incentives (LTI) are essentially unchanged since SCE’s 2015 GRC, when we concluded that LTI does not align executives’ interests with ratepayer interests, and continued “our consistent practice” and denied SCE recovery for its LTI program. Recognition Programs - 367 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 134. SCE provided thorough support for its forecast of costs for its Recognition Programs in its rebuttal testimony, in response to ORA’s critique of its direct showing. Pension Costs 135. SCE states in testimony that upcoming Retirement Plan changes will reduce the Plan’s long term cost structure. 136. Based on SCE’s testimony, ORA supported SCE’s 2018 forecast, and recommended that the Commission authorize the same annual amount for 2019 and 2020. SCE accepted ORA’s proposal. Medical Programs 137. In D.15-11-021 we deferred to SCE’s reliance on medical program cost escalation rates provided by its plan administrators, rather than relying on a broader public study as proposed by ORA. 138. ORA has not demonstrated that a different approach is warranted in this proceeding. Operational Services Business Resiliency 139. SCE forecasts $7.964 million in O&M expenses for the organization in Test Year 2018. Of that amount, $74,000 would fund one analyst position to better support Emergency Management Operations training and exercise activities. 140. SCE’s forecast for Business Resiliency O&M expenses is reasonable, including funding for an additional analyst position. Corporate Environmental Services 141. SCE supports the request made by SDG&E in this proceeding for recovery of SDG&E’s costs relating to the San Dieguito Wetlands and Wheeler North Reef. Corporate Real Estate (CRE) - 368 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Service Center Modernization Program 142. TURN demonstrated in testimony that for the past ten years, over the course of three GRC cycles, SCE has repeatedly requested and received significant funding to modernize its service centers, but has not used significant portions of those funds for that purpose. 143. SCE explains that the funds were “reallocated at the corporate level to projects that were deemed more critical for the delivery of safe and reliable service to SCE’s customers.” 144. The purpose, need for, and cost of the “more critical” projects is unknown, because SCE did not provide this information in response to challenges by TURN in SCE’s 2012 rate case, its 2015 rate case, and now in this 2018 rate case. 145. Instead, SCE invokes the general principle that “utilities must retain flexibility in spending funds authorized in GRC decisions.” 146. The Commission has repeatedly authorized funding for service center modernization to address what we understood to be significant modernization needs, on the basis of SCE’s testimony that the funding was “critical to fostering safe and effective environments for its workforce” and would address “severe and pressing needs.” 147. SCE’s justification of the need to modernize its identified service centers is generally sound, which is consistent with our willingness to fund these projects in the past. Bishop Service Center 148. SCE’s proposed modernization of the Bishop Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. Kernville Service Center - 369 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 149. SCE’s proposed modernization of the Kernville Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. Redlands Service Center 150. SCE’s proposed modernization of the Redlands Service Center is necessary for worker safety, regulatory compliance, and operational efficiency. Ridgecrest Service Center 151. SCE’s proposed modernization of the Ridgecrest Service Center is necessary to support of safe and efficient service over the projected life of the facility. San Joaquin Service Center 152. SCE’s proposed modernization of the San Joaquin Service Center is necessary to foster a safe and effective work environment and to addresses new operational methods and equipment requirements. Santa Ana Service Center 153. SCE’s proposed modernization of the Santa Ana Service Center is necessary to foster a safe and effective work environment. Santa Barbara Service Center 154. SCE has justified its proposal to relocate its Santa Barbara Service Center because the reduction in employee travel time will result in the dual benefits of shorter outages in the Santa Barbara area, as well as higher retention rates for SCE’s employees. Barstow Service Center 155. SCE’s uncontested Barstow Service Center modernization proposal is reasonable. Blythe Service Center - 370 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 156. SCE’s uncontested Blythe Service Center modernization proposal is reasonable. Shaver Lake Service Center 157. SCE’s uncontested Shaver Lake Service Center modernization proposal is reasonable. Operational Support Program Infrastructure Upgrade Projects 158. SCE’s forecast of capital expenditures of $45.978 million for Test Year 2018 related to nine infrastructure upgrade projects during the 2018-2020 GRC period is reasonable. Substation Maintenance and Test Buildings (Substation Reliability Upgrades) 159. SCE’s forecast of capital expenditures of $8.254 million for Substation Maintenance and Test Buildings and Substation Reliability Upgrades in Test Year 2018 is reasonable. Facility Repurpose Projects 160. TURN effectively demonstrated that SCE’s justification for the “Storage of Critical Electrical Equipment Spares Project” did not meet SCE’s burden to prove the project is reasonable. Projects Less Than $3 Million 161. SCE’s forecast of capital expenditures of $5.524 million for Test Year 2018 related to Projects Less Than $3 Million during the 2016-2020 period is reasonable. Blanket Capital Program Non-Electric Capital Maintenance - 371 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 162. In 2016 SCE forecast $21 million in capital expenditures for Non-Electric Capital Maintenance but only recorded $14 million, and has not explained why it would require $21 million annually for this program in 2018. 163. TURN’s recommended funding levels for Non-Electric Capital Maintenance, $14.49 million for 2017 and $15.215 million for 2018, are reasonable. Substation Capital Maintenance 164. TURN’s recommendation to use recorded 2016 expenditures ($10.766 million) as the basis for the 2017 and 2018 forecasts of Substation Capital Maintenance is reasonable, without escalation for 2017 or 2018, or imposing a reduction from the 2016 level. Energy Efficiency 165. SCE’s forecast of capital expenditures of $2.919 million for Test Year 2018 related to Energy Efficiency Projects during the 2016-2020 period is reasonable. Ergonomic Equipment 166. SCE’s forecast of capital expenditures of $1.355 million for Test Year 2018 related to Ergonomic Equipment during the 2016-2020 period is reasonable. Ongoing Furniture Modifications 167. SCE’s forecast of capital expenditures of $3.961 million for Test Year 2018 related to Ongoing Furniture Modifications during the 2016-2020 period is reasonable. Various Major Structures 168. Although spending for SCE’s Various Major Structures (VMS) Program is for unplanned or emergent projects, and therefore is unpredictable, TURN demonstrated that SCE has not supported its significantly higher forecasts with evidence that unforeseen, necessary capital spending will rise to those levels, or even is likely to do so. - 372 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 169. Although CRE’s responsibility has expanded since SCE’s last GRC, SCE provided little actual analysis to support its significantly higher expenditure forecasts for the 2017-2020 period 170. TURN demonstrated in its testimony that SCE has used VMS funds in the past for projects that could have been planned in advance and presented to the Commission for review and approval. Corporate Health and Safety 171. ORA’s recommendation to exclude EPRI funding from SCE’s Corporate Health and Safety O&M forecast for Test Year 2018 reflects ORA’s misunderstanding of D.15-04-020, which denied SCE’s request to fund EPRI Program 60 research using EPIC funds. The Commission did not take any action in D.15-04-020 that extended beyond the EPIC program. 172. SCE seeks GRC funding for EPRI Program 60 research because it was denied EPIC-authorized funding in D.15-04-020. 173. The Commission previously approved SCE’s request for EPRI funding in its 2012 GRC decision, D.12-11-051, so it is logical and reasonable for SCE to seek this funding in this GRC proceeding. SCE’s specific funding request in this proceeding is reasonable. Corporate Security 174. SCE’s forecast of $26.906 million in Corporate Security O&M expenses for Test Year 2018 is reasonable. 175. SCE’s capital expenditure forecast for Corporate Security during the 20162018 period, adjusted to include final 2016 recorded capital expenditures, is reasonable. Supply Management - 373 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 176. SCE’s 2018 Test Year O&M forecast for the Supply Management organization is unchanged from 2015 spending levels and is reasonable. 177. SCE’s capital expenditure forecast for Supply Management during the 2016-2020 period, adjusted to include final 2016 recorded capital expenditures, is reasonable. Supplier Diversity 178. SCE’s 2018 Test Year O&M forecast for the Supplier Diversity organization is reasonable. Transportation Services Operating Costs Fuel Operating Costs 179. SCE accepted TURN's recommendation to use the 2016 version of the Energy Information Administration’s Annual Energy Outlook to update projections of its forecast gas and diesel fuel costs. The resulting total combined fuel cost forecast of $15.654 million is reasonable. Capital 180. SCE’s capital expenditure forecast for Transportation Services during the 2016-2018 period, adjusted to include final 2016 recorded capital expenditures, is reasonable. Administrative & General Ethics and Compliance 181. SCE forecasts Administrative and General (A&G) expenses for Ethics and Compliance for 2018 of $9.863 million. We find the request to be reasonable. Regulatory Affairs Regulatory Affairs Labor: FERC Account 920/921 - 374 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 182. We find reasonable SCE’s forecast of $15.214 million of Test Year 2018 expenses for its Regulatory Affairs Department in FERC Accounts 920/921. Regulatory Affairs – Integrated Planning Power Procurement: FERC Account 557 183. We find reasonable SCE’s forecast of $10 million for Test Year 2018 for Integrated Planning Power Procurement, FERC Account 557. SCE used the Last Recorded Year as the forecast method. Corporate Communications Corporate Communications Operations Labor: FERC Account 920/921 184. We find reasonable SCE’s forecast of $5.071 million of Test Year 2018 expenses for its Corporate Communications Operations Department in FERC Accounts 920/921. Corporate Communications - Outside Services: FERC Account 923 185. SCE forecasts $1.689 million for FERC Account 923 for: 1) ethnic media services; 2) communications measurement; and 3) communications quality assurance. We find the forecast to be reasonable. Local Public Affairs Local Public Affairs – FERC Account 920/921 186. SCE forecasts $7.904 million for Test Year 2018 for Local Public Affairs, FERC Account 920/921. The amount is not disputed; we find the forecast is reasonable. 187. The National Diversity Coalition (NDC) however, urges we require SCE to host at least five capacity building workshops annually for community-based organizations. These workshops were intended to inform and educate customers and community organizations about company programs and initiatives. SCE discontinued these workshops in 2015 following a reorganization and - 375 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 determination that the workshops are not core to the Local Public Affairs’ function. Although NDC establishes the workshops were well attended and inexpensive and would likely continue to be, NDC does not establish a basis for requiring these workshops; we decline to order them. Corporate Membership Dues and Fees – FERC Account 930 188. We find SCE has not met its burden to establish any portion of the Edison Electric Institute dues are recoverable from ratepayers. 189. SCE has not established the ratepayer benefits of supporting California Taxpayer Association, Business Roundtable, California Small Business Association, and California Small Business Roundtable. Accordingly, we find a forecast of $168,701 FERC Account 930 for the ratepayer funded portion of dues and memberships costs is reasonable. Financial Services 190. We find reasonable SCE’s 2018 forecast for the Financial Services Department of $43.3 million for Accounts 920/921 and TURN’s recommendation of $13.251 million for Financial Services Accounts 923/930. Audits 191. We find reasonable the SCE forecast of $8.657 million for the Audit Service Department in 2018. Legal - Removal of Costs Resulting from Alleged Imprudence 192. We approve as reasonable a 10% reduction of the forecast for Outside Counsel. As for In-House Counsel, we also note SCE has, in a number of instances, renewed previously denied arguments without providing an explanation as to what has changed to warrant a different outcome in the present case. Therefore, we reduce the In-House forecast an additional 5% for a total of 15% reduction. - 376 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 193. Although we decline to order changes to SCE’s internal guidance concerning the removal of costs for imprudent activities, we consider greater transparency to be warranted and recognize recalcitrance by SCE in regards to this issue may undermine its showing in meeting its burden of proof in future GRCs. 194. We find the parties should meet and confer to explore this proposal further. During this process the parties should consider means to accurately determine the portion of In-House Counsel costs and other expenses which are incurred in connection with findings of utility imprudence. This consideration should include timekeeping or other means to accurately evaluate the allocation of expenses, notwithstanding our previous rejection of ORA’s predecessor, the Division of Ratepayer Advocate’s, suggestion that SCE be required to have a timekeeping system. Law In-House, FERC Accounts 920/921 195. Following application of the 15% reduction discussed above, we find reasonable a forecast of $21.587 million for In-House Counsel. FERC Accounts 923/925/928 Outside Counsel 196. We find reasonable a forecast of $12.532 million. FERC Account 930 Corporate Governance 197. As we have in past rate cases we exclude equity compensation; we find reasonable a forecast of $3.1 million. Claims 198. We find reasonable SCE’s Administrative Expense forecast of $3.025 million. 199. We find reasonable a forecast of $14.948 million for Claims Reserves. - 377 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Workers’ Compensation 200. Neither ORA nor TURN challenge the forecasted administrative expense of $6.783 million and we find it reasonable. 201. We find reasonable for Workers’ Compensation Reserve expense, a forecast of $7.773 million. Disability Program 202. SCE’s forecast of $833,000 for Disability Administration is not disputed and is reasonable. 203. We find reasonable a forecast for the Disability Program of $17.766 million. Property and Liability Insurance Property Insurance 204. SCE accepts ORA’s and TURN’s recommended property insurance expense forecast of $14.070 million for Test 2018 (a reduction of $2 million from SCE’s original forecast) and we adopt it as reasonable. Liability Insurance 205. We find SCE’s continuing reliance on an expert forecast is reasonable and find reasonable for total liability insurance expense the forecast of $92.427 million. Ratemaking Proposals Establishment of the DER Deferred Project Memorandum Account (DERDPMA) 206. SCE has withdrawn its request to establish the DERDPMA. Establishment of the Public Utilities Code Section 706 SCE Officer Compensation Memorandum Account (SOCMA) 207. SCE’s request to establish this memorandum account has been mooted by statutory changes enacted after SCE made this proposal in its September 2016 application. - 378 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 ORA’s Proposal to Establish a One Way Storms Balancing Account 208. In the section of this decision addressing T&D Distribution Construction and Maintenance, we denied ORA’s proposal to create a one way balancing account for Distribution Storm Expenses (FERC Sub Account 598.170). 209. SCE’s five-year average forecast method for storm expenses is reasonable given the inherent variability of storm expenses and SCE’s storm expenses forecast is reasonable. Uncontested Proposals for Memorandum Accounts and Balancing Accounts 210. SCE provided a list in its opening brief of its memorandum account and balancing account proposals that are uncontested, and we find each of the uncontested proposals reasonable. Jurisdictional Issues 211. SCE uses a Commission approved methodology to calculate factors to allocate total company costs between CPUC and FERC jurisdictional revenue requirements and presents those unopposed allocation factors in SCE-09, Table IV 6. SCE’s uncontested jurisdictional allocation factors are calculated according to methods we have approved in the past and are reasonable. Sales and Customer Forecast 212. TURN’s forecast of new Residential and Non-Residential meters is reasonable. 213. SCE’s forecast of new Agricultural meters is reasonable. 214. It is reasonable to adjust SCE’s forecasts of retail sales and number of customers based on the adopted forecast of new meters. Other Operating Revenues 215. SCE’s total OOR forecast of $126.426 for 2018 is reasonable. - 379 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Cost Escalation 216. SCE’s uncontested cost escalation method is reasonable. Post Test Year Ratemaking 217. An appropriate PTYR mechanism is simple; accurately aligns with how costs are incurred for the utility; and gives the utility an incentive to manage costs while enhancing productivity. 218. Global Insight escalation rates are a reasonable forecast of the inflationary increases for O&M labor costs. 219. SCE’s PTYR escalation rates for other O&M expenses are reasonable. 220. Escalating capital additions by 2.49% per year is reasonable. 221. The following escalation rates are reasonable: Category O&M: Labor Escalation Rates807 O&M: Benefits Escalation Rates Medical Programs Dental Programs Vision Service Plan Disability Programs (=updated labor escalation rates) Group Life Insurance Misc. Benefit Programs808 Executive Benefits 401 (k) (=updated labor escalation rates) Capital Additions (applied to 2018 capital additions, based on the 2018 authorized capital expenditures authorized in this decision) 2019 2.89% 2020 2.94% 7.00% 4.20% 3.00% 2.89% 0.00% 2.20% 0.00% 2.89% 7.00% 4.20% 3.00% 2.94% 0.00% 2.27% 0.00% 2.94% 2.49% 2.49% 222. SCE’s Z-factor mechanism is reasonable. 223. SCE’s proposal to implement PTYR updates by advice letter is reasonable. 807 SCE-59 at 11, table III-4. 808 SCE-59 at 12, table III-5. - 380 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 224. The adopted PTYR mechanism strikes an appropriate balance between the goals described above as well as the parties’ different positions. Rate Base Components The Tax Cuts and Jobs Act 225. On December 22, 2017, Public Law 115-97, the Tax Cuts and Jobs Act (TCJA), was signed into law. 226. SCE served testimony addressing the impact of the TCJA on February 16, 2018 and an evidentiary hearing was held on March 19, 2018. Revenue Requirement 227. With its updated testimony, SCE requests a 2018 GRC revenue decrease of $22 million, 0.38% less than the 2017 authorized GRC revenue requirement; SCE requests that the Commission adopt a 2018 revenue requirement of $5.534 billion. 228. Attrition years 2019 and 2020 would follow with increases to the Authorized Base Revenue Requirement (ABRR) of $431 million and $503 million, respectively. 229. The deferred taxes reflected on SCE’s regulatory books of account are based on the differences between SCE’s regulatory tax liability, including Cost of Removal, and its actual tax liability, as calculated on its actual depreciable basis and consistent with IRC section 168(i)(9)(A)(i). This is consistent with Treasury Regulation § 1.167(l)-1(h)(1)(iii). 230. Prior to the TCJA, SCE included Cost of Removal when it calculated its ADIT. SCE, by including Cost of Removal in the calculation of ADIT, normalized the Cost of Removal and ensured all ratepayers over the life of the asset shared in that expense. Excluding Cost of Removal from the ARAM calculation increases the tax expense for current customers in excess of the - 381 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 benefit received from the asset. The effect is the Cost of Removal is not normalized, despite it being a cost which should be shared equally by all ratepayers. 231. SCE has consistently normalized the benefits of accelerated depreciation derived from its depreciable basis. Likewise, it is our intention SCE continues to normalize the benefits of the TCJA. 232. Some other assets are not subject to normalization rules. These assets are typically referred to as “unprotected” assets. SCE identifies the unprotected assets as: Accrued Vacation, ITCC, Mixed Service Costs, AFUDC, Other Historical Basis Differences, and Cost of Removal. In past GRCs normalization rules have been applied to them, even though not required, again to ensure that ratepayers over the life of the asset are treated equally. 233. Returning excess funds to current ratepayers does not impose a greater burden on future ratepayers. Rather, repayment now returns the excess funds to ratepayers who are the closest in time to the recent ratepayers who contributed those funds to these accounts. Therefore, it is reasonable to require the net excess deferrals relating to the unprotected assets consisting of: Accrued Vacation, ITCC, Mixed Service Costs, AFUDC, and Other Historical Basis Differences, to be returned to ratepayers. Consistent with the return of other funds due to implementation of the TCJA, it is reasonable to require these funds be returned on an amortized basis over 2018-2020. 234. We find reasonable TURN’s calculation of SCE’s operational cash requirement by applying the new tax rate only to the 2018 year-end balance reducing the workers’ compensation estimate to $12.144 million. - 382 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 235. We find reasonable TURN’s use of the 21% tax rate for both beginning- and end-of-2018, reducing the unfunded pension estimate to $16.413 million. 236. SCE agrees with ORA and TURN that it should have a broadened Tax Memorandum account. 237. We agree the benefits of the TCJA should flow to the ratepayers. 238. Ratepayers should begin receiving the benefit of the TCJA now and continuing through the remainder of this GRC cycle, 2018-2020. Customer Advances 239. Customer Advances represent funds provided by others, such as developers, to construct new distribution facilities to be served by the utility. 240. No party challenges the CIAC forecast, and we agree it is reasonable. Customer Advances – Electric Construction 241. We find reasonable ORA’s forecast of $84.7 million for 2018 Customer Advances for Electric Construction. Customer Advances – Temporary Services 242. We find reasonable ORA’s forecast for 2018 of $6.122 million. Materials and Supplies Generation M&S 243. SCE’s forecast of Generation M&S is reasonable. T&D M&S 244. SCE’s forecast of T&D M&S is reasonable and is adopted. Working Cash 245. We find reasonable elimination of the Cash Bank Balances of $6.9 million from the Working Capital forecast. The other Operational Cash Requirements are not contested. - 383 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Lead Lag Study 246. SCE’s Lead-Lag Study seeks to quantify the amount of funds needed from investors to cover the timing difference between receipt of revenues and payment of expenses. SCE’s analysis for this GRC shows, on average, SCE pays expenses 12.7 days before receiving corresponding revenues. Based on estimated daily expenses of $28.9 million, SCE estimates its Lead-Lag Working Cash requirement is $367 million. Revenue Lag Days 247. We find reasonable a Revenue Lag Day estimate of 45.01 days, accepting SCE’s proposal, as adjusted by TURN. Income Tax Lag 248. ORA’s proposal of 96.98 days Federal Income Tax lag and of 117.20 days California Income Tax Lag is consistent with prior decisions and results in Income Tax Lag Day calculations which are representative and is reasonable. Fuel and Purchased Power Expense Lag 249. We find TURN’s proposal to use the more recent Fall forecasts reasonable, as is SCE’s proposal to consistently use forecasts from the same period resulting in proposals of 36.4 lag days for purchased power, $206.3 million for fuel, $4,574.2 million for purchased power, and working cash requirements of $7.2 million for fuel, and $107.8 million for purchased power as adjusted for use of the United States Postal Service for 31% of payments. Other O&M Expense Lag (ISO Charges) 250. ORA has agreed the ISO charges are correctly calculated at 12.1 expense lag days for Other O&M Expense Lag. - 384 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Depreciation & Deferred Income Tax Lag 251. SCE’s Expense Lag Day calculation is included in the lead lag study to compensate investors for the timing difference between the receipt of revenues and the accrual of depreciation expense and deferred income taxes. We agree, consistent with long-standing practice, it is appropriate to continue to compensate for this lag. Customer Deposits 252. SCE is required to offset rate base by the amount of its customer deposits as an adjustment for working cash. In every GRC since 2003, SCE has urged the Commission revisit this decision and recognize customer deposits as debt which is not offset against rate base. In each decision for each GRC the Commission has reached the same conclusion. 253. Beginning with its 2012 GRC, the Commission granted SCE permission to use a portion (up to 10%) of its customer deposits to promote the Company’s use of minority and community banks. No Party opposes this proposal, and we again adopt it. 254. It is reasonable for $231.9 million, less 10% devoted to the community bank program, to be used as a rate base offset. An offsetting interest expense based on the three-month commercial paper interest rate is also reasonable. AFUDC 255. SCE’s proposed AFUDC rates through the post-test year period have not been opposed by any party SCE’s proposed AFUDC rates are reasonable. - 385 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Rate Base Components – Additional Issues Long-Term Incentives 256. It is reasonable to adopt the proposed disallowance of Long-Term Incentives. The authorized rate base is correspondingly increased by $4.3 million. Other Accounts Receivable 257. TURN’s recommendation for $50.8 million for 2018 Accounts Receivable, based on 2016 recorded data, is reasonable. Depreciation 258. Straight line depreciation following Standard Practice U-4 remains the proscribed means for determining depreciation rates. 259. Both SCE’s per unit analysis and TURN’s depreciation proposal are substantial deviations from Standard Practice U-4. 260. We find neither SCE nor TURN established by a preponderance of the evidence the validity of their proposed net salvage ratios. 261. We find that due to the costs of removal, net salvage is nearly always negative. 262. We find it reasonable to maintain in most instances the net salvage ratios which were previously adopted by D.15 11 021. 263. The reasonable net salvage ratios are set forth in the following table: - 386 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Account (all values are negative) 2015 GRC SCE TURN Adopted       Transmission Plant 352 - Structures and Improvements 35% 35% 35% 35% 353 - Station Equipment 15% 10% 10% 10% 354 - Towers and Fixtures 60% 75% 35% 60% 355 - Poles and Fixtures 72% 90% 100% 72% 356 - Overhead Conductors & Devices 80% 100% 60% 80% 357 - Underground Conduit 0% 0% 5% 0% 358 - Underground Conductors & Devices 15% 19% 15% 15% 359 - Roads and Trails 0% 0% 5% 0%       Distribution Plant 361 - Structures and Improvements 25% 30% 30% 25% 362 - Station Equipment 25% 31% 30% 25% 364 - Poles, Towers and Fixtures 210% 263% 210% 210% 365 - Overhead Conductors & Devices 115% 144% 100% 115% 366 - Underground Conduit 30% 38% 50% 30% 367 - Underground Conductors & Devices 60% 75% 75% 60% 368 - Line Transformers 20% 25% 35% 20% 369 - Services 100% 125% 70% 100% 370 - Meters 5% 0% 0% 0% 373 - Street Lighting & Signal Systems 30% 38% 100% 30% 264. Service lives, as shown by the following summary of accounts table, are reasonable: - 387 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Account 2015 GRC SCE TURN Adopted TRANSMISSION PLANT 350.2 Easements 60 60 60 352 Structures and Improvements 55 S 3.0 55 L 1.0 55 L 1.0 353 Station equipment 45 R 0.5 40 L 0.5 45 R 0.5 354 Towers & Fixtures 65 R 5 65 R 5 65 R 5 355 Poles & Fixtures 50 R 0.5 65 SC 65 SC 356 Overhead Conductors & Devices 61 R 3 61 R 3 61 R 3 357 Underground Conduit 55 R 3.0 55 R 3.0 55 R 3.0 358 Underground Conductors & Devices 40 R 2.5 45 S 1.0 45 S 1.0 359 Roads and Trails 60 SQ 60 R 5.0 60 R 5.0 DISTRIBUTION PLANT 360.2 Easements 60 60 60 361 Structures and Improvements 42 R 2.5 50 L 0.5 50 L 0.5 362 Station Equipment 45 R 1.5 65 L 0.5 65 L 0.5 364 Poles, Towers & Fixtures 47 L 0.5 55 R 1.0 55 R 1.0 365 Overhead Conductors & Devices 45 R 0.5 55 R 0.5 55 R 0.5 366 Underground Conduit 59 R 3.0 59 R 3.0 59 R 3.0 367 Underground Conductors & Devices 45 R 0.5 43 R 1.5 43 R 1.5 368 Line Transformers 33 R 1 33 S 1.5 33 S 1.5 369 Services 45 R 1.5 45 R 1.5 370 Meters 20 R 3.0 20 R 3.0 20 R 3.0 373 Street Lighting & Signal Systems 40 L 0.5 48 L 1.0 48 L 1.0 38 R 3.0 45 R 0.5 45 R 0.5 55 R 1.5 55 R 1.5 GENERAL BUILDING 390 Structures and Improvements 265. We find the vast majority of hydroelectric facility licenses will be renewed and find reasonable a depreciation rate of 2.13% for hydroelectric facilities. 266. We find SCE’s contention that the service life for solar PV assets should more nearly match the roof life and lease life is reasonable and therefore a 20year average service life for solar PV assets is reasonable. - 388 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 267. We find reasonable the decommissioning generation plant annual accrual proposed by TURN for Mountainview 3 & 4 of $0.3 million, Solar PV of $3.2 million, and Peakers of $0.2 million. Rate Base – Additional Issues Aged Poles 268. SCE has not established it was prudent to replace aged poles which continued to be used and useful. Advanced Technology Laboratories 269. SCE has not established that other more cost-effective options to Fenwick Labs and the Equipment Demonstration and Evaluation Facility do not exist but We find Fenwick Labs and the Equipment Demonstration and Evaluation Facility are used and useful and authorize 50% of SCE’s forecast. 2014-15 Capital Spending Above Authorized 270. SCE’s expenditures for T&D Infrastructure Replacement programs: Worst Circuit Rehabilitation, Substation Transformer Bank Replacement, Substation Circuit Breaker Replacement, and “Other” (including Underground Oil Switch Replacement), and a new program: Overhead Conductor have resulted in used and useful assets at a just and reasonable expense of $115 million for 2014 and $114 million for 2015. Changes in Accounting 271. It is unreasonable to permit SCE a double recovery of capital expenditure of amounts previously authorized and adopted by an O&M forecast. SPIDACalc Pole Issues 272. We find an adopted disallowance for the SPIDACalc pole replacement issue should be spread over the entire three-year GRC cycle of 2018-2020. - 389 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 273. We find that no pole will last forever, that it was imprudent to replace poles prematurely, and that premature replacement, when the poles continued to be useful, resulted in a loss of value to ratepayers. 274. It is just and reasonable to base the impact to the SCE revenue requirement on returning the value of these poles to rate base after 20 years. 275. We adopt April 2013 as the commencement date for disallowing these pole expenditure as we find it was not prudent of SCE to use SPIDACalc v5.0 at that time. Compliance 276. In this GRC, SCE provided Exhibit SCE-10 summarizing its compliance with requirements it has identified in the 2006, 2009, 2012, and 2015 GRC decisions, as well as other relevant proceedings or settlements. We find SCE has complied with the relevant orders of the Commission. Tax Memorandum Account 277. A tax memorandum account would increase the transparency of SCE’s incurred and forecasted income tax expenses to the Commission, so that the Commission can more closely examine revenue impacts caused by SCE’s implementation of various tax laws, tax policies, tax accounting changes, or tax procedure changes. CALSLA Issues 278. CALSLA's testimony in Exhibits CALSLA-01 through CALSLA-12, and SCE's rebuttal testimony in Exhibit SCE-26, demonstrate that that SCE's process for transferring streetlight ownership is structured and managed in an inefficient manner that uses ratepayer funds uneconomically. - 390 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Conclusions of Law 1. SCE bears the burden to establish that its requests are just and reasonable. 2. Public Utilities Code §451 provides, in part, “all charges demanded or received by any public utility … shall be just and reasonable.” 3. SCE must establish its requests are just and reasonable by the preponderance of the evidence. 4. Public Utilities Code §454.8 requires, in part, “the commission shall consider a method for the recovery of these costs which would be constant in real economic terms over the life of the facilities, so that ratepayers in a given year will not pay for the benefits received in other years.” Safety and Reliability Investment Incentive Mechanism (SRIIM) 5. The Commission should adopt the three enhancements to the capital mechanism of SRIIM proposed by SCE, with the modifications SCE agreed to make in response to CUE. 6. The Commission should adopt the four enhancements to the workforce mechanism of SRIIM proposed by SCE, with the modifications SCE agreed to make in response to CUE. T&D – System Planning Distribution Circuit Upgrades 7. SCE’s 2017-2018 capital expenditure forecast of $100.485 million for Distribution Circuit Upgrades should be adopted. New Distribution Circuits 8. SCE’s 2017-2018 capital expenditure forecast of $90.137 million for New Distribution Circuits should be adopted. Substation Expansion Projects - 391 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 9. SCE’s 2017-2018 capital expenditure forecast of $224.101 million for substation expansion projects should be adopted. Substation Equipment Replacement Program 10. SCE’s 2017-2018 capital expenditure forecast of $49.785 million for its Substation Equipment Replacement Program should be adopted. Subtransmission Lines Plan 11. SCE’s 2017-2018 capital expenditure forecast of $205.582 million for its Subtransmission Lines Plan should be adopted. 4 kV Programs 4 kV Cutover Program 12. SCE’s requested levels of 2017 and 2018 funding for its 4 kV Cutover Program ($35.955 million in 2017 and $36.663 million in 2018) should be adopted. 4 kV Substation Elimination Program 13. SCE’s requested level of funding of its 4 kV Substation Elimination Program in the 2018- 2020 period should be denied. 14. The level of funding recommended by TURN for SCE’s 4 kV Substation Elimination Program for the 2018 test year, which we calculate to be $4.897 million, should be approved. Grid Reliability Projects 15. Spending for the Cerritos Channel Transmission Tower Replacement Project should be disallowed as follows: all spending prior to 2016 and the $57.904 million forecasted amount (CPUC jurisdictional) requested by SCE for the 2016-2020 period. For Test Year 2018, the disallowed amount should be $34.048 million (CPUC jurisdictional). T&D – Distribution Maintenance and Inspection - 392 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 16. SCE’s undisputed forecast O&M expenses of $159.968 million for T&D Distribution Maintenance and Inspection should be adopted. 17. SCE’s undisputed forecast capital expenditures of $273.955 million for T&D Distribution Maintenance and Inspection should be adopted. T&D – Distribution Construction and Maintenance 18. For Test Year 2018, and $70.491 million for O&M expenses. 19. SCE’s undisputed forecast capital expenditures of $203.700 million for T&D Distribution Construction & Maintenance should be adopted. 20. SCE’s Test Year 2018 forecast for FERC sub account 585.170, equal to $6.936 million, should be adopted. 21. SCE’s shareholders should continue to be responsible for funding SCE’s service guarantees. 22. The funding level for Distribution Storm O&M (FERC sub account 598.170) recommended by ORA, $7.814 million, should be adopted. T&D – Substation Construction & Maintenance 23. SCE’s undisputed O&M forecast of $78.15 million for Substation Construction and Maintenance should be adopted. 24. SCE’s 2018 capital expenditure forecast of $176.329 million for Substation Construction and Maintenance should be adopted. T&D – Transmission Construction & Maintenance 25. SCE’s O&M forecast of $40.918 million for Transmission Construction and Maintenance should be adopted. Transmission Tools and Work Equipment 26. SCE’s 2018 capital expenditure forecast for Transmission Construction & Maintenance of $216.793 million should be adopted. T&D – Infrastructure Replacement - 393 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Worst Circuit Rehabilitation Program 27. SCE’s forecast capital expenditures for its Worst Circuit Rehabilitation Program, a total of $249.313 million for 2017-2018, should be adopted. 28. TURN’s policy recommendations should be adopted, as modified below: (1) the Commission should direct SCE to begin recording cable failures by cable type; (2) the Commission should direct SCE to change the minimum age used to select mainline cable replacements; and (3) If a cost benefit analysis determines that a pilot is necessary, SCE should be directed to begin piloting cable injections (instead of replacements) on mainline cable, and report on quantitative and qualitative findings from the pilot in the next GRC. Cable Life Extension Program 29. SCE’s capital expenditure forecast for its Cable Life Extension Program should be adopted. Cable-In-Conduit Replacement Program 30. SCE’s capital expenditure forecast for its Cable-In-Conduit Replacement Program should be adopted. Overhead Conductor Program 31. SCE spent $97.330 million to support replacement of 202 circuit miles in 2016, so it is reasonable for the Commission to expect that SCE will continue replacements at that level in 2017 and 2018, with the same level of funding, if not a higher level in the event that SCE continues to find ways to improve processes and lower costs. 32. SCE has not met its burden to prove that its requested levels of Overhead Conductor Program funding are reasonable. - 394 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 33. The Commission should authorize the same level of annual expenditures for SCE’s Overhead Conductor Program in 2017 and 2018 that SCE recorded in 2016: $97.330 million (subject to the adjustment we order below). 34. The Commission should adopt TURN’s recommendation that we impose a 10% disallowance of Overhead Conductor Program costs, to be paid for by shareholders, to recognize the role that the incorrect engineering had in creating circumstances where some wires may have more extensive damage than they would have otherwise. 35. For Overhead Conductor Program recorded costs in 2015 and 2016 totaling $155.456 million, the Commission should disallow $15.54 million. 36. For the annual Overhead Conductor Program capital expenditures approved in this decision for 2017 and the remainder of this GRC period (20182020), SCE should record 10% of its recorded costs in a below the line account. On a forecast basis, this amount would equal $9.733 million annually. Underground Oil Switch Replacement Program 37. SCE’s capital expenditure forecast for its Underground Oil Switch Replacement Program should be adopted. Capacitor Bank Replacement Program 38. The Commission should adopt SCE’s reduced forecast for its Capacitor Bank Replacement Program, based on SCE’s agreement to accept TURN’s proposal to use 2014 unit costs. The reduced forecast is $27.692 million. Automatic Recloser Program 39. SCE’s 2017-2018 capital expenditure forecast for its Automatic Recloser Program should be adopted. PCB Transformer Replacement Program - 395 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 40. SCE’s 2017-2018 capital expenditure forecast for its PCB Transformer Replacement Program should be adopted. Substation Infrastructure Replacement Program 41. SCE’s 2017-2018 capital expenditure forecast for the three functions within its Substation Infrastructure Replacement Program should be adopted, as follows: a. Transformer Replacement: $134.352 million b. Circuit Breaker Replacement: $88.818 million c. Substation Switchrack Rebuild: $37.187 million T&D – Poles O&M Expenses 42. The following SCE forecasts for Pole-related O&M expenses are uncontested and should be adopted: a. Transmission and Distribution Pole Loading Program Related Expenses; b. Transmission and Distribution Deteriorated Pole Inspections; and c. Joint Pole Organization expenses. 43. The following TURN recommendations for Pole-related O&M expenses should be adopted: a. Distribution and Transmission Pole Loading Assessments; and b. Distribution and Transmission Pole Loading Program Repairs. Capital Expenditures 44. For Pole-related capital expenditures, SCE should be authorized to spend the amounts recommended by TURN and summarized in the table in Section 4.9.2 of this decision. Pole Loading and Deteriorated Pole Programs Balancing Account - 396 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 45. No changes in the structure of the PLDPBA are warranted at this time. T&D – Grid Modernization Grid Modernization Capital Expenditures Distribution Automation Programs 46. SCE should be authorized $64.675 million per year for the Worst Circuit Rehabilitation (WCR) portion of distribution automation. TURN’s testimony shows that this amount should enable funding for: (1) five Remote Fault Indicators (RFIs) on the 600 WCR circuits; (2) one tie switch and (3) up to two remote controlled switches (RCSs) on the 110 WCR circuits that have no existing ties. 47. SCE should be authorized $11.178 million per year for the DER portion of distribution automation. Communications 48. SCE’s request for $314 million in capital expenditures for its Substation Automation (SA 3) program over the 2018-2020 period should be denied. 49. The Common Substation Platform (CSP) will deliver cybersecurity and interoperability benefits 50. SCE’s proposed Common Substation Platform (CSP) and SCE’s associated request for $46 million in capital expenditures over the 2018-2020 period should be approved. 51. SCE’s proposed Field Area Network (FAN) and SCE’s associated request for $199 million in capital expenditures over the 2018-2020 period should be approved. 52. SCE’s showing did not demonstrate why expenditures for a Wide Area Network (WAN) are necessary during this GRC period. - 397 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 53. SCE’s request for $314 million in capital expenditures for its proposed Wide Area Network (WAN) over the 2018-2020 period should be denied. Tools for Data Analysis and Decision Making 54. SCE’s request for $2.467 million for Test Year 2018 capital expenditures for its System Modeling Tool (SMT) should be approved. 55. SCE’s request for $3.641 million for Test Year 2018 capital expenditures for its DRP External Portal should be approved. 56. SCE’s request for $39.456 million for Test Year 2018 capital expenditures for the GMS should be approved. T&D – Grid Technology Distribution Volt VAR Control 57. SCE’s forecast capital expenditures for its proposed Distribution Volt VAR Control (DVVC) program for Test Year 2018, $4.414 million, should be adopted. Energy Storage Pilots 58. SCE’s forecast capital expenditures for Distributed Energy Storage Integration (DESI) pilots in 2018, $22.499 million, should be adopted. T&D – Safety Training & Environmental Programs Environmental Program – Transmission (FERC Account 565.281) 59. SCE’s O&M forecast for Transmission Environmental Programs (FERC Account 565.281) should be adopted. Hazardous Waste Management & Disposal – Distribution (FERC Account 598.250) 60. SCE’s O&M forecast for Distribution Hazardous Waste Management & Disposal (FERC Account 598.250) should be adopted. T&D – Other Costs, Other Operating Revenues T&D –Other Operating Revenues - 398 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 61. SCE’s undisputed forecast of $126.426 million in 2018 for tariffed OOR for T&D activities should be adopted. T&D – Other Costs 62. Based on the Commission’s findings for specific line items in SCE’s forecast for Other Costs in 2018, each of SCE’s forecast values (other than Underground Locating Services) should be adopted. 63. The test year forecast for underground locating services (FERC Account 588.281), $8.227 million, that has been mutually agreed upon by SCE and TURN should be adopted. 64. SCE should establish a memorandum account for tracking the costs and benefits of Customer Service Re-Platform. Customer Service – O&M Meter Reading Operations – FERC Account 902 65. For the Meter Reading Operations account, the Commission should adopt the reduced proposal of $9.909 million removing the projected increase due to growth. Test, Inspect, and Repair Meters – FERC Account 586.400 66. For the Test, Inspect and Repair Meter’s Account, the Commission should adopt the reduced proposal of $15.438 million. Turn-On and Turn-Off Services – FERC Account 586.100 67. For the Turn-On and Turn-Off Services Account, the Commission should adopt the forecast of $5.164 million. Customer Installation and Energy Theft Expense – FERC Account 587 68. For the Customer Installation and Energy Theft Expense Account, the Commission should adopt $6.506 million for this account. Meter Services Operations and Management – FERC Account 580 - 399 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 69. For the Meter Services Operations and Management Account, the Commission should adopt $5.671 million. Billing Services – FERC Account 903.500 70. For Billing Services, the Commission should adopt $23.645 million. Credit and Payment Services – FERC Account 903.200 71. For Credit and Payment Services, the Commission should adopt $15.477 million for this account. Postage – FERC Account 903.100 72. For Postage, the Commission should adopt TURN’s proposed adjusted forecast of $14.371 million. Uncollectable Expenses – FERC Account 904 73. For Uncollectable Expenses, the Commission should adopt a forecast of 0.211%. Customer Contact Center– FERC Account 903.800 74. We should adopt $43.779 million for the Customer Contact Center account. Business Customer Division– FERC account 908.600 75. We should adopt a forecast of $18.790 million for the Business Customer Division Account. Customer Programs and Services– FERC account 905.900 76. We should adopt the forecast of $24.656 million for Customer Programs and Services. Operating Unit Management and Support–FERC Accounts 901 and 907.600 77. We should adopt for FERC Accounts 901 and 907.600 a forecast of $6.887 million. Customer Service – Capital 78. We should adopt $24.251 million for 2017 and $34.956 million for 2018. - 400 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Customer Service – Other Operating Revenue 79. SCE estimates OOR to be $27.981 million in Test Year 2018. The forecast should be adopted. Information Technology – O&M and Hardware Hardware/Software Licenses & Maintenance 80. We should adopt the forecast of $70.73 million for this account. Business Integration & Delivery 81. A 2018 forecast for BID of $37.196 million should be adopted. Grid Services 82. The O&M associated with Grid Modernization capital projects in the amount of $5.046 should be adopted. 83. The forecast for Grid Services for 2018 of $34.5 million should be adopted. Information Technology – Capitalized Software 84. Except as noted, we should adopt the 2016 recorded capital expenditures for capitalized software in Information Technology. Contingency Amounts in Capitalized Software Forecasts 85. We should not adopt forecasts for software contingencies. Cybersecurity and Compliance 86. We should adopt, exclusive of contingencies, $22.590 million for 2016, $52.003 million for 2017, and $47.457 million for 2018 for Cybersecurity and Compliance software. Grid Modernization Cybersecurity 87. We should adopt the 2016 recorded expense of $2.901 million and adopt 40 percent of the forecasted expenses (less contingencies) for 2017 and 2018, $5.34 million and $8.063 million, respectively. Other Capitalized Software - 401 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Vegetation Management Project 88. We should adopt the recorded expense for 2016 of $916,000 and the forecast (less contingency) for 2017 of $4.75 million for the Vegetation Management Project. Comprehensive Situational Awareness for Transmission 89. We should adopt the 2016 recorded expense of $0, $0.476 million for 2017, $0.951 million for 2018, $3.236 million for 2019, and $3.236 million for 2020. Grid Planning & Analytics Software 90. We should adopt the recorded expense for 2016 for the GIPT, GAA, LTPT, and GCM projects of $9.371 million, and 50% of SCE’s request (the forecast less contingencies), $12.796 million for 2017 and $7.332 million for 2018. Enterprise Content Management Project 91. The requests for ECM (the forecast less contingencies) of $2.833 million for 2017 and $4.333 million for 2018 should be adopted. Operating System Software 92. We should adopt the forecast capital expenditure for the Operating System Software account for 2016 of $8.75 million, and the forecast, less contingencies, of $13.113 million for 2017, and $19.80 million for 2018. Information Technology - Customer Service Re-Platform 93. SCE should establish a memorandum account to track CS Re-Platform costs, benefits, and capital expenditures for review in the next GRC. 94. We should adopt the 2016 recorded capital expenditures for Managed Services Providers. Generation Generation – Nuclear Generation (Palo Verde) - 402 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 95. No party disputed SCE’s O&M expenses or capital expenditures for Nuclear Generation (Palo Verde) and they should be adopted. Generation – Energy Procurement 96. No party disputed SCE’s O&M expenses or capital expenditures for Energy Procurement and they should be adopted. Generation – Hydro Generation 97. No party disputed SCE’s O&M expenses or capital expenditures for hydro generation and they should be adopted. Generation – Catalina Catalina – O&M 98. We should adopt SCE’s 2018 forecast for Catalina O&M of $4.374 million. Catalina – Pebbly Beach Generating Station Automation 99. The costs for the PBGS Automation Project have not been established to be just and reasonable and therefore, we should not allow them. Catalina – Other Capital Projects Under $3 million 100. We should adopt the 2016 actual recorded expense of $.007 million and the forecast of $0.448 million for each of the years 2017 and 2018. Generation – Other Mountainview 101. No party disputed SCE’s O&M expenses or capital expenditures for Mountainview Generation and they should be adopted. Peakers 102. No party disputed SCE’s O&M expenses or capital expenditures for Peakers and they should be adopted. Mohave Closure - 403 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 103. No party disputed SCE’s O&M expenses or capital expenditures for generation costs associated with Mohave closure and they should be adopted. Solar Photovoltaic 104. SCE should be allowed to recover its Solar Photovoltaic O&M expenses of $8.286 million for 2013 and $4.270 million for 2014. 105. We should adopt SCE’s 2018 Solar Photovoltaic O&M forecast of $2.842 million and its 2016 recorded capital expenditure of $0.004 million and its forecasts of $0.2 million each for 2017 and 2018. Fuel Cells 106. We should adopt SCE’s forecast for O&M for its fuel cell program of $0.379 million. Human Resources 107. Pursuant to Public Utilities Code § 706, only the Test Year 2018 officer compensation amounts adopted in this decision should be collected from SCE’s ratepayers. 108. The 2019 and 2020 officer compensation amounts should not be collected from SCE’s ratepayers. 109. SCE should refund to customers any amounts tracked in the OCMA, as part of SCE’s revenue requirement and rate change advice letter implementing this decision. Human Resources Department and Executive Officers Human Resources Operating Unit 110. SCE’s Test Year 2018 forecast of $43.792 million for HR Department O&M expenses should be adopted. Executive Officers - 404 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 111. It is reasonable for ratepayers to fund 40% of SCE’s Executive Incentive Compensation (EIC) Plan request. 112. Ratepayers should fund $9.926 million in Executive Incentive Compensation for Test Year 2018. Benefits and Other Compensation Short Term Incentive Program 113. In order to accurately remove the costs of incentives tied to "core earnings" and utility financial performance from the STIP, 40% of the total forecast value should be removed from SCE’s 2018 STIP expenses. Long Term Incentives 114. Our approach should to LTI should remain unchanged, and we should deny SCE recovery of its Test Year 2018 forecast LTI program expenses. Recognition Programs 115. SCE’s request for $1.456 million in Test Year 2018 Recognition Program expenses should be adopted. Pension Costs 116. SCE’s updated request for approval of annual pension cost forecasts equal to $57.741 million for 2018, 2019 and 2020 should be adopted. Medical Programs 117. SCE’s forecast medical program costs, based on SCE’s escalation rate, should be adopted. 118. The Commission should reconsider this approach in future GRCs if presented with evidence that SCE’s forecast methodology resulted in a significant over- or under-collected balance in the Medical Programs Balancing Account. Executive Benefits Program - 405 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 119. The precedent established in SCE’s 2009, 2012 and 2015 GRCs allows 50% rate recovery of SCE’s Test Year 2018 forecast for Executive Benefits 120. SCE should be authorized to recover $10.135 million for Test Year 2018 Executive Benefits, which is 50% of its forecasted expenses. Operational Services Business Resiliency 121. SCE’s forecast for Business Resiliency O&M expenses should be adopted. 122. SCE’s unopposed request for Test Year 2018 capital expenditures related to Business Resiliency should be adopted. Corporate Environmental Services 123. The updated value for 2016 CES capital expenditures recommended by ORA and accepted by SCE should be adopted. 124. SCE’s otherwise unopposed CES capital expenditure forecast for 2016-2018 should be adopted. 125. SDG&E's proposed calculation of its 20% share and overhead costs for marine mitigation with escalation, which is $991,000, $1.015 million, and $1.038 million (all nominal dollars) in 2018, 2019, and 2020, respectively, should be approved. Corporate Real Estate CRE O&M 126. SCE’s unopposed request for Test Year 2018 O&M expenses related to Corporate Real Estate should be adopted. CRE Capital 127. Although the Commission has at times found an approach such as ORA’s proposed across the board reductions to SCE’s CRE request to be appropriate (e.g., when a request has no explainable relationship to well established and - 406 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 stable recorded costs), in this instance we have an extensive record to support our decisions on a project-specific basis. Service Center Modernization Program 128. SCE’s explanations for its failure to initiate and/or complete its supposedly urgent service center modernization projects that previously received funding are unsupported by record evidence and are therefore unconvincing. 129. Because SCE did not explain its management of the service center modernization funds that we authorized in our prior decisions, SCE should complete the list of prioritized projects in its testimony, but should be denied recovery of these project costs from ratepayers. 130. SCE should record the costs of completing the following service center modernization projects in a below-the-line account: Bishop, Kernville, Redlands, Ridgecrest, San Joaquin, and Santa Ana. Bishop Service Center 131. SCE should proceed with the Bishop Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.2 of this decision. 132. SCE should record all the costs of the Bishop Service Center modernization project, from the date of inception through completion, in a below-the-line account. Kernville Service Center 133. SCE should proceed with the Kernville Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.3 of this decision. - 407 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 134. SCE should record all the costs of the Kernville Service Center modernization project, from the date of inception through completion, in a below-the-line account. Redlands Service Center 135. SCE should proceed with the Redlands Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.4 of this decision. 136. SCE should record all the costs of the Redlands Service Center modernization project, from the date of inception through completion, in a below-the-line account. Ridgecrest Service Center 137. SCE should proceed with the Ridgecrest Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.5 of this decision. 138. SCE should record all the costs of the Ridgecrest Service Center modernization project, from the date of inception through completion, in a below-the-line account. San Joaquin Service Center 139. SCE should proceed with the San Joaquin Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.6 of this decision. 140. SCE should record all the costs of the San Joaquin Service Center modernization project, from the date of inception through completion, in a below-the-line account. Santa Ana Service Center - 408 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 141. SCE should proceed with the Santa Ana Service Center modernization project as described in its testimony, and at the funding levels shown in Section 9.2.3.1.7 of this decision. 142. SCE should record all the costs of the Santa Ana Service Center project, from the date of inception through completion, in a below-the-line account. Santa Barbara Service Center 143. SCE’s forecasted capital expenditures for relocation of its Santa Barbara Service Center should be adopted. 144. The progress and completion of the relocation of SCE’s Santa Barbara Service Center should be reviewed in each of SCE’s future GRCs until its completion in order to determine whether SCE has diverted any funds approved in this decision to other uses. In the event that SCE diverts any funds, the question of whether the financial responsibility for this project should be placed on SCE’s shareholders should be reviewed. Barstow Service Center 145. SCE’s forecasted capital expenditures for modernization of the Barstow Service Center should be adopted. Blythe Service Center 146. SCE’s forecasted capital expenditures for modernization of the Blythe Service Center should be adopted. Shaver Lake Service Center 147. SCE’s forecasted capital expenditures for modernization of the Shaver Lake Service Center should be adopted. Operational Support Program Infrastructure Upgrade Projects - 409 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 148. SCE’s forecast capital expenditures for nine infrastructure upgrade projects should be adopted. Substation Maintenance and Test Buildings (Substation Reliability Upgrades) 149. SCE’s forecast capital expenditures for Substation Maintenance and Test Buildings and Substation Reliability Upgrades should be adopted. Facility Repurpose Projects 150. SCE’s request to proceed with the “Storage of Critical Electrical Equipment Spares Project” should be denied, but SCE should be authorized to recover the 2018 and 2019 forecast IT infrastructure and equipment expenditures associated with its request. Projects Less Than $3 Million 151. SCE’s forecast capital expenditures for Projects Less Than $3 Million should be adopted. Blanket Capital Program Non Electric Capital Maintenance 152. TURN’s recommended funding levels for Non Electric Capital Maintenance, $14.49 million for 2017 and $15.215 million for 2018, should be adopted. Substation Capital Maintenance 153. The Commission should adopt TURN’s recommendation to use recorded 2016 expenditures ($10.766 million) as the basis for the 2017 and 2018 forecasts of Substation Capital Maintenance, without escalation for 2017 or 2018, or imposing a reduction from the 2016 level. Energy Efficiency 154. SCE’s forecast capital expenditures for Energy Efficiency Projects should be adopted. - 410 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Ergonomic Equipment 155. SCE’s forecast capital expenditures for Ergonomic Equipment should be adopted. Ongoing Furniture Modifications 156. SCE’s forecast capital expenditures for Ongoing Furniture Modifications should be adopted. Various Major Structures 157. The Commission should not authorize SCE’s unsupported forecast for its Various Major Structures (VMS) Program because SCE’s position that its managers may redirect Commission-approved funding to entirely unrelated purposes suggests that the VMS budget is essentially a generic contingency fund. 158. Funding for SCE’s Various Major Structures (VMS) Program should be authorized at the level equal to the average of SCE’s recorded spending from 2011-2016, $7.894 million, and should not be escalated to a higher level during the 2018-2020 GRC period. Corporate Health and Safety 159. SCE's 2018 O&M forecast of $5.470 million for Account 925 expenses associated with SCE's Corporate Health & Safety organization should be adopted. Corporate Security 160. SCE’s forecast of Corporate Security O&M expenses for Test Year 2018 should be adopted. 161. SCE’s capital expenditure forecast for Corporate Security, adjusted to include final 2016 recorded capital expenditures, should be adopted. Supply Management - 411 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 162. SCE’s forecast of Supply Management O&M expenses for Test Year 2018 should be adopted. 163. SCE’s capital expenditure forecast for Supply Management, adjusted to include final 2016 recorded capital expenditures, should be adopted. Supplier Diversity 164. SCE’s forecast of Supplier Diversity O&M expenses for Test Year 2018 should be adopted. 165. Pursuant to Section 8 of the Commission’s General Order 156, each utility (rather than the Commission or another party) shall determine its short- , mid- , and long-term goals for the use of Diverse Business Enterprise, so the Commission should not direct SCE to set additional aspirational goals as NDC recommends. Transportation Services Operating Costs Fuel Operating Costs 166. SCE’s forecast amount for outside fuel pumping service costs is reasonable. The total value jointly calculated by SCE and TURN for Test Year 2018 fuel operating costs, $15.654 million, should be adopted. Capital 167. SCE’s capital expenditure forecast for Transportation Services, adjusted to include final 2016 recorded capital expenditures, should be adopted. Administrative & General Ethics and Compliance 168. We should adopt SCE’s forecast of Administrative and General (A&G) expenses for Ethics and Compliance for 2018 of $9.863 million. Regulatory Affairs - 412 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Regulatory Affairs Labor: FERC Account 920/921 169. We should adopt SCE’s forecast of $15.214 million of Test Year 2018 expenses for its Regulatory Affairs Department in FERC Accounts 920/921. Regulatory Affairs – Integrated Planning Power Procurement: FERC Account 557 170. We should adopt SCE’s forecast of $10 million for Test Year 2018 for Integrated Planning Power Procurement, FERC Account 557. Corporate Communications Corporate Communications Operations Labor: FERC Account 920/921 171. We should adopt SCE’s forecast of $5.071 million of Test Year 2018 expenses for its Corporate Communications Operations Department in FERC Accounts 920/921. Corporate Communications - Outside Services: FERC Account 923 172. We should adopt SCE’s forecast of $1.689 million for FERC Account 923 for: 1) ethnic media services; 2) communications measurement; and 3) communications quality assurance. Local Public Affairs Local Public Affairs – FERC Account 920/921 173. We should adopt SCE’s forecast of $7.904 million for Test Year 2018 for Local Public Affairs, FERC Account 920/921. Corporate Membership Dues and Fees – FERC Account 930 174. We should not allow any portion of the Edison Electric Institute dues as recoverable from ratepayers. 175. We should adopt a forecast of $168,701 FERC Account 930 for the ratepayer funded portion of dues and memberships costs. Financial Services - 413 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 176. We should adopt SCE’s 2018 forecast for the Financial Services Department of $43.3 million for Accounts 920/921 and TURN’s recommendation of $13.251 million for Financial Services Accounts 923/930. Audits 177. We should adopt the SCE forecast of $8.657 million for the Audit Service Department in 2018. Legal - Removal of Costs Resulting from Alleged Imprudence 178. We should adopt a 10 percent reduction of the forecast for Outside Counsel and reduce the In-House forecast an additional 5 percent for a total of 15 percent. Law In-House, FERC Accounts 920/921 179. Following application of the 15 percent reduction discussed above, we should adopt a forecast of $21.587 million for In-House Counsel. FERC Accounts 923/925/928 Outside Counsel 180. We should adopt a forecast of $12.532 million. FERC Account 930 Corporate Governance 181. For FERC Account 930, we should exclude equity compensation and adopt a forecast of $3.1 million. Claims 182. We should adopt SCE’s Administrative Expense forecast of $3.025 million associated with the Claims Reserves. 183. We should adopt a forecast of $14.948 million for Claims Reserves. Workers’ Compensation 184. Neither ORA nor TURN challenge the forecasted Workers Compensation administrative expense of $6.783 million and we should adopt it. - 414 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 185. We should adopt for Workers’ Compensation Reserve expense, a forecast of $7.773 million. Disability Program 186. SCE’s forecast of $833,000 for Disability Administration should be adopted. 187. We should adopt a forecast for the Disability Program of $17.766 million. Property and Liability Insurance Property Insurance 188. We should adopt as reasonable property insurance expense forecast of $14.070 million for Test 2018. Liability Insurance 189. We should adopt for total liability insurance expense the forecast of $92.427 million. Ratemaking Proposals Modification of the Pole Loading and Deteriorated Pole Programs Balancing Account (PLDPBA) 190. The current account structure of the Pole Loading and Deteriorated Pole Programs Balancing Account should continue for this GRC cycle, with no changes. ORA’s Proposal to Establish a One Way Storms Balancing Account 191. We should deny ORA’s proposal to create a one way balancing account for Distribution Storm Expenses (FERC Sub Account 598.170). ORA’s Recommendation to Establish a Grid Modernization Memorandum Account 192. ORA’s proposal is moot because this decision addresses the details of SCE’s Grid Modernization proposals, specifically authorizing some while - 415 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 denying others, so there is no need to track SCE’s expenditures for possible future recovery. ORA’s Recommendation to Establish a DER Memorandum Account 193. ORA’s proposal is moot because we have addressed SCE’s funding requests for DER related projects directly, as part of our discussion of distribution automation, where we adopted TURN’s recommendation for lower funding levels for DER related distribution. Therefore, there is no need to order SCE to track these authorized expenditures in a memorandum account. 194. SCE’s uncontested proposals for memorandum accounts and balancing accounts should be approved. Jurisdictional Issues 195. SCE’s uncontested jurisdictional allocation factors should be approved. Sales and Customer Forecast Retail Electricity Sales 196. SCE’s forecasts of retail sales and number of customers, as adjusted based on the adopted forecast of new meters, should be approved. Customer Accounts and New Meter Connections 197. TURN’s forecast of new Residential and Non-Residential meters should be approved. 198. SCE’s forecast of new Agricultural meters should be approved. Other Operating Revenues 199. SCE’s total OOR forecast of $126.426 million in 2018 should be adopted. Cost Escalation 200. SCE’s uncontested cost escalation method should be adopted. Post Test Year Ratemaking 201. The following PTYR escalation rates should be adopted: - 416 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Category O&M: Labor Escalation Rates809 O&M: Benefits Escalation Rates Medical Programs Dental Programs Vision Service Plan Disability Programs (=updated labor escalation rates) Group Life Insurance Misc. Benefit Programs810 Executive Benefits 401 (k) (=updated labor escalation rates) Capital Additions (applied to 2018 capital additions, based on the 2018 authorized capital expenditures authorized in this decision) 2019 2.89% 2020 2.94% 7.00% 4.20% 3.00% 2.89% 0.00% 2.20% 0.00% 2.89% 7.00% 4.20% 3.00% 2.94% 0.00% 2.27% 0.00% 2.94% 2.49% 2.49% 202. SCE’s Z-factor mechanism should be adopted. 203. SCE’s proposal to implement PTYR updates by advice letter should be adopted. Rate Base Components The Tax Cuts and Jobs Act Revenue Requirement 204. SCE should normalize the benefits of the TCJA including deferred taxes reflected on SCE’s regulatory books of account based on the differences between SCE’s regulatory tax liability, including Cost of Removal, and its actual tax liability, as calculated on its actual depreciable basis and consistent with IRC section 168(i)(9)(A)(i) and Treasury Regulation § 1.167(l)-1(h)(1)(iii). 205. The net excess deferrals relating to the unprotected assets consisting of: Accrued Vacation, ITCC, Mixed Service Costs, AFUDC, and Other Historical 809 SCE-59 at 11, table III-4. 810 SCE-59 at 12, table III-5. - 417 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Basis Differences, should be returned to ratepayers. Consistent with the return of other funds due to implementation of the TCJA, these funds should be returned on an amortized basis over 2018-2020. 206. We should adopt TURN’s calculation of SCE’s operational cash requirement by applying the new tax rate only to the 2018 year-end balance reducing the workers’ compensation estimate by $12.144 million. 207. We should adopt the use of the 21% tax rate for both beginning- and end-of-2018, reducing the unfunded pension estimate by $16.413 million. 208. SCE should have a broadened Tax Memorandum account. 209. The benefits of the TCJA should flow to the ratepayers. 210. Ratepayers should begin receiving the benefit of the TCJA now and continuing through the remainder of this GRC cycle, 2018-2020. Customer Advances 211. We should adopt the CIAC forecast. Customer Advances – Electric Construction 212. We should adopt a forecast of $84.7 million for 2018 Customer Advances for Electric Construction. Customer Advances – Temporary Services 213. We should adopt a forecast for 2018 of $6.122 million for Customer Advances- Temporary Services. Materials and Supplies Generation M&S 214. SCE’s forecast of Generation M&S should be adopted. T&D M&S 215. SCE’s forecast for T&D M&S should be adopted. - 418 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Working Cash 216. We should adopt elimination of the Cash Bank Balances of $6.9 million from the Working Capital forecast. The other Operational Cash Requirements are not contested and should be adopted. Lead Lag Study Revenue Lag Days 217. We should adopt a Revenue Lag Day estimate of 45.01 days, accepting SCE’s proposal, as adjusted by TURN. Income Tax Lag 218. ORA’s proposal of 96.98 days Federal Income Tax lag and of 117.20 days California Income Tax Lag should be adopted. Fuel and Purchased Power Expense Lag 219. We should adopt 36.4 lag days for purchased power, $206.3 million for fuel, $4,574.2 million for purchased power, and working cash requirements of $7.2 million for fuel, and $107.8 million for purchased power as adjusted for use of the United States Postal Service for 31 percent of payments. Other O&M Expense Lag (ISO Charges) 220. We should adopt ISO charges at 12.1 expense lag days for Other O&M Expense Lag. Depreciation & Deferred Income Tax Lag 221. It is appropriate to continue to compensate for Expense Lag Days calculation. Customer Deposits 222. SCE should continue to offset rate base by the amount of its customer deposits as an adjustment for working cash. - 419 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 223. SCE should have permission to use a portion (up to 10 percent) of its customer deposits to promote the Company’s use of minority and community banks. 224. $231.9 million, less 10 percent devoted to the community bank program, should be used as a rate base offset. We should grant an offsetting interest expense based on the three-month commercial paper interest rate expense. AFUDC 225. The Commission should adopt SCE’s proposed AFUDC rates. Rate Base Components – Additional Issues Long-Term Incentives 226. We should disallow Long-Term Incentives. The authorized rate base should correspondingly increase by $4.3 million. Other Accounts Receivable 227. We should adopt TURN’s recommendation, based on 2016 recorded data as reasonable and adopt $50.8 million for 2018 Accounts Receivable for this account. Depreciation 228. Straight line depreciation following Standard Practice U-4 remains the proscribed means for determining depreciation rates. 229. We should maintain in most instances the net salvage ratios which were previously adopted by D.15 11 021. 230. We should adopt the net salvage ratios as set forth by the following table: - 420 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Account (all values are negative) 2015 GRC SCE TURN Adopted       Transmission Plant 352 - Structures and Improvements 35% 35% 35% 35% 353 - Station Equipment 15% 10% 10% 10% 354 - Towers and Fixtures 60% 75% 35% 60% 355 - Poles and Fixtures 72% 90% 100% 72% 356 - Overhead Conductors & Devices 80% 100% 60% 80% 357 - Underground Conduit 0% 0% 5% 0% 358 - Underground Conductors & Devices 15% 19% 15% 15% 359 - Roads and Trails 0% 0% 5% 0%       Distribution Plant 361 - Structures and Improvements 25% 30% 30% 25% 362 - Station Equipment 25% 31% 30% 25% 364 - Poles, Towers and Fixtures 210% 263% 210% 210% 365 - Overhead Conductors & Devices 115% 144% 100% 115% 366 - Underground Conduit 30% 38% 50% 30% 367 - Underground Conductors & Devices 60% 75% 75% 60% 368 - Line Transformers 20% 25% 35% 20% 369 - Services 100% 125% 70% 100% 370 - Meters 5% 0% 0% 0% 373 - Street Lighting & Signal Systems 30% 38% 100% 30% 231. We should adopt service lives as shown by the following summary of accounts table: - 421 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Account 2015 GRC SCE TURN Adopted TRANSMISSION PLANT 350.2 Easements 60 60 60 352 Structures and Improvements 55 S 3.0 55 L 1.0 55 L 1.0 353 Station equipment 45 R 0.5 40 L 0.5 45 R 0.5 354 Towers & Fixtures 65 R 5 65 R 5 65 R 5 355 Poles & Fixtures 50 R 0.5 65 SC 65 SC 356 Overhead Conductors & Devices 61 R 3 61 R 3 61 R 3 357 Underground Conduit 55 R 3.0 55 R 3.0 55 R 3.0 358 Underground Conductors & Devices 40 R 2.5 45 S 1.0 45 S 1.0 359 Roads and Trails 60 SQ 60 R 5.0 60 R 5.0 DISTRIBUTION PLANT 360.2 Easements 60 60 60 361 Structures and Improvements 42 R 2.5 50 L 0.5 50 L 0.5 362 Station Equipment 45 R 1.5 65 L 0.5 65 L 0.5 364 Poles, Towers & Fixtures 47 L 0.5 55 R 1.0 55 R 1.0 365 Overhead Conductors & Devices 45 R 0.5 55 R 0.5 55 R 0.5 366 Underground Conduit 59 R 3.0 59 R 3.0 59 R 3.0 367 Underground Conductors & Devices 45 R 0.5 43 R 1.5 43 R 1.5 368 Line Transformers 33 R 1 33 S 1.5 33 S 1.5 369 Services 45 R 1.5 45 R 1.5 370 Meters 20 R 3.0 20 R 3.0 20 R 3.0 373 Street Lighting & Signal Systems 40 L 0.5 48 L 1.0 48 L 1.0 38 R 3.0 45 R 0.5 45 R 0.5 55 R 1.5 55 R 1.5 GENERAL BUILDING 390 Structures and Improvements 232. We should adopt a depreciation rate of 2.13% for hydroelectric facilities. 233. We should adopt a 20-year average service life for solar PV assets. 234. We should adopt the decommissioning generation plant annual accrual for Mountainview 3 & 4 of $0.3 million, Solar PV of $3.2 million, and Peakers of $0.2 million. - 422 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 235. SCE should work with TURN, ORA, the Energy Division, and any interested parties to develop a more reliable depreciation study for the Commission to examine and consider in the next GRC. Rate Base- Additional Issues Aged Poles 236. We should not allow recovery for the replacement of aged poles which continued to be used and useful. Advanced Technology Laboratories 237. We should adopt a 2018 forecast of $2.098 million for Fenwick Labs and $.264 million for the Equipment Demonstration and Evaluation Facility. 2014-15 Capital Spending Above Authorized 238. We should accept the recorded capital expenditures for the Infrastructure Replacement and Overhead Conductor programs of $115 million for 2014 and $114 million for 2015. Changes in Accounting 239. We should permanently disallow $4.26 million from gross plant ($1.42 million for each of 2015, 2016, and 2017) for underground location costs (Account 588.281) which was expensed in the 2015 GRC but then subsequently capitalized. 240. We should permanently disallow $9.94 million from gross plant for real property expenses (Account 920.220) which was expensed in the 2012 and 2015 GRCs but has been capitalized since 2013. SPIDACalc Pole Issues 241. We should reduce SCE’s revenue requirement by $120.1 million over the 2018-2020 GRC cycle. - 423 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Compliance 242. SCE has demonstrated its compliance with each of the 37 items listed in its Compliance exhibit. Tax Memorandum Account 243. SCE should establish a two-way tax memorandum account to track any revenue differences resulting from the differences in the income tax expense forecasted in this proceeding, and the tax expenses incurred during the 2018-2020 GRC period as well as the differences in any subsequently forecasted tax expenses forecast in subsequent GRCs and the tax expenses incurred during the respective GRC cycles. CALSLA Issues 244. SCE's management of its streetlight acquisition program in the litigious manner described in Exhibit SCE-26 is an inappropriate and unreasonable use of ratepayer funds and should not continue. O R D E R IT IS ORDERED that: 1. Application 16-09-001 is granted to the extent set forth in this Decision. Southern California Edison is authorized to collect, through rates and through authorized ratemaking accounting mechanisms, the 2018 test year base revenue requirement set forth in Appendix C, effective January 1, 2018. 2. Southern California Edison shall file a Tier 1 Advice Letter within twenty days of the effective date of this decision to implement the revenue requirement and ratemaking adopted herein. The revenue requirement and revised tariff sheets will be effective January 1, 2018. The balance of the General Rate Case - 424 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 Revenue Requirement Memorandum Account shall be amortized in rates thirty days after the effective date of this decision to December 31, 2020. 3. As part of revenue requirement and rate change advice letter filed pursuant to Ordering Paragraph 2, Southern California Edison shall refund to customers any amounts tracked in the Officer Compensation Memorandum Accounts. 4. Southern California Edison Company (SCE) is authorized to implement a Post-Test Year Ratemaking mechanism for both 2019 and 2020, as follows: a. Expenses shall be escalated as proposed by SCE, using the same pricing methodology and pricing indices that we adopt for test year escalation, except for labor expenses [namely: disability programs, executive benefits, and 401(k)]. For labor expenses, SCE shall use Global Insight’s most current forecast. For medical expenses, we adopt SCE’s escalation rate of 8%. We also adopt SCE’s proposed escalation rates for other benefits categories. For all other expenses, we adopt SCE’s proposal of using the latest Global Insight escalation rates. b. Capital-related revenues shall be escalated by increasing gross capital additions in the post test years at a rate of 2.49% per year above the 2018 authorized capital additions. c. SCE’s Z-factor recovery mechanism shall continue. d. We allow SCE to file an advice letter to implement the post-test year revenue requirement. SCE must file an advice letter by December 1st of 2019 and 2020. In these advice letters, SCE must update its post-test year revenue requirement for the following attrition year. For the second attrition year of 2020, SCE shall use the latest Global Insight escalation rates to escalate 2018 authorized level of expenses to 2019 and 2020 levels, but the 2019 authorized level of expenses will not be trued up to reflect the actual escalation factor for 2019. 5. Southern California Edison shall file a Tier 2 Advice Letter within 30 days of the effective date of this decision to establish a two-way tax memorandum - 425 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 account to record any revenue differences resulting from the income tax expenses forecasted in its General Rate Case (GRC) proceedings, and the tax expenses incurred by Southern California Edison during this 2018-2020 GRC period and each subsequent GRC period. a. This tax memorandum account shall remain open and the balance in the account shall be reviewed in every subsequent GRC until a Commission decision closes the account. b. The account shall have separate line items detailing the differences between tax expenses forecasted and tax expenses incurred, specifically resulting from 1) net revenue changes, 2) mandatory tax law changes, tax accounting changes, tax procedural changes, or tax policy changes, and 3) elective tax law changes, tax accounting changes, tax procedural changes or tax policy changes. c. Southern California Edison may track changes in revenue resulting from the application of the Average Rate Assumption Method in accordance with this decision in the Tax Memorandum Account. 6. Southern California Edison shall notify the Energy Division of the California Public Utilities Commission of any tax-related changes, tax-related accounting changes or any tax-related procedural changes that materially affect or may materially affect revenues. “Materially affect” is defined as a potential increase or decrease of $3 million or more. 7. If Southern California Edison requests an Internal Revenue Service private letter ruling, Southern California Edison shall file and serve a copy of its request to the Internal Revenue Service as a Tier 1 Advice Letter at least 30 days before sending the request to the Internal Revenue Service. 8. Any request by Southern California Edison for a private letter ruling concerning application or interpretation of the Tax Cut and Jobs Act shall seek a response to the question, “Is including Cost of Removal/Negative Net Salvage in - 426 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 the ARAM calculation for the return of excess deferred taxes to ratepayers inconsistent with normalization requirements?” 9. In the event that Southern California Edison Company receives a relevant Internal Revenue Service ruling contradicting this decision, stating it is a normalization violation to include Cost of Removal in book depreciation for purposes of calculating Average Rate Assumption Method, then Southern California Edison shall comply with the Internal Revenue Service’s interpretation of the applicable tax laws by filing a Tier 2 advice letter with this Commission to seek an appropriate adjustment to its revenue requirement and/or rate base. 10. Southern California Edison shall file a Tier 2 Advice Letter within 30 days of the effective date of this decision to establish a Customer Service Re-platforming memorandum account to record any costs, capital expenditures, and benefits of Customer Service Re-platforming during this 2018-2020 GRC period and each subsequent GRC period. These items may be reviewed for recovery in the next GRC. 11. Southern California Edison (SCE) shall file a Tier 2 Advice Letter within 30 days of the effective date of this decision to establish a one-way Rule 20A balancing account that tracks the annual capital and expense costs for Rule 20A undergrounding projects, on a forecast and recorded basis. Overcollected balances in the account shall remain available for future Rule 20A projects. The Commission shall review the balances in the account in SCE’s next General Rate Case proceeding. 12. San Diego Gas & Electric Company’s (SDG&E’s) request for an authorized revenue requirement for Marine Mitigation is granted. SDG&E shall file a Tier 1 Advice Letter within twenty days of the effective date of this decision outlining its method to calculate its revenue requirement. SDG&E shall continue tracking - 427 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 its Marine Mitigation costs and revenue requirement differences in its Marine Mitigation Memorandum Account as required by Decision 15-11-021, as modified. SDG&E shall implement its marine mitigation revenue requirement and ratemaking adopted herein for marine mitigation concurrently with its General Rate Case. 13. Within 45 days of the effective date of this decision, Southern California Edison Company shall issue a true-up of marine mitigation costs billed to San Diego Gas & Electric Company reflecting the categorization of costs as expense. 14. The parties should consider and discuss during the next GRC the means to accurately determine the portion of In-House Counsel costs and other expenses which are incurred in connection with findings of utility imprudence. This consideration should include timekeeping or other means to accurately evaluate the allocation of expenses. 15. SCE shall work with TURN, ORA, the Energy Division, and any interested parties to develop a more reliable depreciation study for the Commission to examine and consider in the next GRC. 16. Southern California Edison Company shall transfer the General Rate Case Revenue Requirement Memorandum Account balance, as of the effective date of this decision, to its Authorized Base Revenue Requirement Balancing Account. 17. Southern California Edison Company and San Diego Gas & Electric Company are not permitted to recover any cost twice. If a cost permitted for recovery here is also recovered from the nuclear decommissioning trust (or any other source), Southern California Edison Company and/or San Diego Gas & Electric Company shall refund the revenue requirement associated with that cost to ratepayers, with interest. - 428 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 18. Southern California Edison Company and San Diego Gas & Electric Company are authorized to file an application to recover costs in the event that California Coastal Commission does require additional reef construction, or other measures. In that application, Southern California Edison Company shall demonstrate that it has made a reasonable effort to represent ratepayers’ interests in front of all applicable regulatory bodies and that its cost forecast is reasonable. Southern California Edison Company and San Diego Gas & Electric Company shall recover any such costs as operations and maintenance expense, not capital expenditures. 19. Southern California Edison Company (SCE) shall meet and confer with the California City-County Street Light Association (CALSLA) and all interested officials from affected jurisdictions in order to prepare a joint proposal to address each of the concerns raised in CALSLA's testimony regarding SCE's streetlight acquisition program, including (1) the information that interested jurisdictions receive, or do not receive, during the acquisition process, (2) the possibility of including mast arms and luminaires attached to shared distribution poles in streetlight acquisition agreements, (3) more efficient transfer of streetlights following Commission approval of a sale, (4) exploration of the question of the impact of delays on receipt of LED rebates, and (5) any other issues that the Commission could address. The joint proposal should be provided either as part of SCE's testimony when it files its next GRC application, or as a supplemental exhibit in that proceeding as soon as possible after the filing date. Both sides are encouraged to seek assistance from the Commission's Alternative Dispute Resolution program if that would expedite their efforts or avoid conflict. - 429 - PROPOSED DECISION A.16-09-001 ALJ/SCR/EW2/jt2 20. Southern California Edison Company shall file its next General Rate Case for test year 2021 pursuant to the applicable Rate Case Plan adopted in Decision 89-01-040, as modified. 21. In its next General Rate Case (GRC), Southern California Edison Company (SCE) shall provide tables with at least five years of recorded spending information associated with each individual expense or expenditure forecast in excess of $1 million. SCE shall also provide summary tables, aggregating this information at the level of major categories (e.g. Transmission and Distribution Infrastructure Replacement, Human Resources). SCE shall provide its own comparable forecast and the Commission’s adopted forecast from this GRC as a component of or accompaniment to these tables, both for individual forecasts and summary tables. SCE shall briefly explain any changes in scope of the forecasts, if they are not directly comparable. In the summary tables, SCE shall include any expenses or expenditures that were included in this GRC request, even if the individual expense or expenditure was not actually approved in this decision or implemented by SCE. 22. Application 16-09-001 is closed. This order is effective today. Dated ________________, at San Francisco, California. - 430 - A.16-O9-001 PROPOSED DECISION APPENDIX A A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege APPENDIX A List of Acronyms ACRONYMS MEANING A. Application AB Assembly Bill ACE Awards to Celebrate Excellence ADIT Accumulated Deferred Income Taxes AFUDC Allowance for Funds Used During Construction ALJ Administrative Law Judge API Asset Priority Index ARs Automatic Reclosers ARAM Average Rate Assumption Method BCD Business Customer Division BRRBA Base Revenue Requirement Balancing Account C&I Commercial and Industrial CAISO California Independent System Operator CALSLA California City-County Street Light Association CCA Community Choice Aggregator CEMA Catastrophic Event Memorandum Account CEO Chief Executive Officer CIAC Contributions in Aid of Construction CIC Cable-in-Conduit CIP Critical Infrastructure Protection CMS Consolidated Mobile Solution COR Cost of Removal CFC Consumer Federation of California CPI Consumer Price Index -1- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege CPI-U Consumer Price Index for All Urban Consumers CPI-W Consumer Price Index for Urban Wage Earners and Clerical Workers CPUC California Public Utilities Commission CRE Corporate Real Estate CSAT Comprehensive Situational Awareness for Transmission CSP Common Substation Platform CS Customer Service CUE Coalition of Utility Employees CWIP Construction Work In Progress D. Decision DA Distribution Automation DER Distributed Energy Resources DESI Distributed Energy Storage Integration DR Demand Response DRP Distributed Resources Plan DSEEP Distribution System Efficiency Enhancement Program DSP Distribution Substation Plan DVVC Distribution Volt VAR Control EDEF Equipment Demonstration and Evaluation Facility eDMRM Electronic Document Management/Records Management EEI Edison Electric Institute EIC Executive Incentive Compensation ECM Enterprise Content Management EPIC Electric Program Investment Charge EPRI Electric Power Research Institute ERRA Energy Resource Recovery Account ESC Edison SmartConnect® ESCBA Edison SmartConnect Balancing Account -2- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege FAN Field Area Network FCC Final Cost Centers FCI Facility Condition Index FERC Federal Energy Regulatory Commission FTE Full Time Equivalent GAA Grid Analytics Application GCM Grid Connectivity Model GIPT Grid Interconnection Processing Tool GMS Generation Management System GO General Order GO2 General Order 2 GRC General Rate Case GRSM Gross Revenue Sharing Mechanism HR Human Resources IT Information Technology ITCC Income Tax Component of Contributions kV kilovolt kW kilowatt LGBT Lesbian, Gay, Bisexual and Transgender LTI Long Term Incentives LTIP Long-Term Incentive Plan LTPT Long-Term Planning Tools M&S Materials and Supplies MBEs Minority Business Enterprises MEDs Major Event Days MSO Meter Services Organization MSPs Managed Services Providers NDC National Diversity Coalition NEM Net Energy Metering -3- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege NERC North American Electric Reliability Corporation NSR Net Salvage Ratio O&M Operations and Maintenance OBs Opening Briefs OCMA Officer Compensation Memorandum Accounts OCP Overhead Conductor Program OOR Other Operating Revenue OpX Operational Excellence ORA Office of Ratepayer Advocates OS Operational Services OU Operating Unit PBGS Pebbly Beach Generating Station PBOPs Post-retirement Benefits Other than Pensions PCB Polychlorinated Biphenyl PDD Project Development Division PDDMA Project Development Division Memorandum Account PG&E Pacific Gas and Electric Company PLP Pole Loading Program PLPBA PLP Balancing Account PMO Program Management Organization PPA Power Purchase Agreement PPO Planning and Performance Organization PHC Prehearing Conference PTYR Post-Test Year Ratemaking PVNGS Palo Verde Nuclear Generating Station R. Rulemaking RD&D Research, Development and Demonstration RCS Remote Controlled Switches RFIs Remote Fault Indicators -4- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege RIIM Reliability Investment Incentive Mechanism RO Results of Operations RS Results Sharing RSDMA Residential Service Disconnection Memorandum Account RSE Risk Spend Efficiency SAIDI System Average Interruption Duration Index SAIFI System Average Interruption Frequency Index SB Senate Bill SBUA Small Business Utility Advocates SCE Southern California Edison Company SDD Supplier Diversity and Development Department SDG&E San Diego Gas & Electric Company SED Safety and Enforcement Division SEIA Solar Energy Industries Association SERP Substation Equipment Replacement Program SIR Substation Infrastructure Replacement SM Supply Management SMT System Modeling Tool SoCalGas Southern California Gas Company SRIIM Safety and Reliability Investment Incentive Mechanism PV Photovoltaic SOMA SmartConnect Opt-Out Memorandum Account SONGS San Onofre Nuclear Generating Station SRIIM Safety and Reliability Investment Incentive Mechanism STIP Short-Term Incentive Program T&D Transmission and Distribution TAMA Tax Memorandum Account TCJA Tax Cuts and Jobs Act TCS Total Compensation Study -5- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED DECISION [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege TD&D Technology Demonstration and Deployment TD&D TSD Transportation Services Department TURN The Utility Reform Network TY Test Year VAR Volt-Ampere Reactive WAN Wide Area Network WCR Worst Circuit Rehabilitation WMDVE Women, Minority, and Disabled Veteran Enterprise (END OF APPENDIX A) -6- A.16-O9-001 PROPOSED DECISION APPENDIX A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege APPENDIX B DECISION TABLE I CAPITALIZED SOFTWARE – CONTINGENCIES II. Operating System Software II. Operating System Software II. Operating System Software II. Operating System Software Operating System Software Database Platform Upgrade Business Intelligence Tools Upgrade Enterprise Integration Tools Upgrade Enterprise Platform Core Refresh ADOPTED  2018 Project Forecast 2017 Project Forecast SCE-04, Vol. 2, Chapter II. Operating System Software SCE FORECASTS  2018 Contingency PROJECT  2017 Contingency EXHIBIT  2017   2018  - - 5.946 11.300 5.946 11.300 - - - - - - 0.050 0.083 0.300 0.500 0.250 0.417 0.050 0.167 0.300 1.000 0.250 0.833 1.333 1.450 8.000 8.700 6.667 7.250 III. Cybersecurity & Compliance Perimeter Defense - - 13.000 13.500 13.000 13.500 III. Cybersecurity & Compliance Interior Defense - - 8.500 8.000 8.500 8.000 III. Cybersecurity & Compliance Data Protection - - 6.000 6.000 6.000 6.000 III. Cybersecurity & Compliance SCADA Cybersecurity - - 8.750 9.070 8.750 9.070 0.567 0.983 3.400 5.900 2.833 4.917 2.675 4.038 16.050 24.230 13.375 20.192 III. Cybersecurity & Compliance III. Cybersecurity & Compliance CCS for Generator Interconnections Grid Modernization Cybersecurity A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  III. Cybersecurity & Compliance IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization IV. Technology Consolidation & Optimization V. OU Software V. OU Software PROJECT  IT Support for NERC CIP Compliance SCE FORECASTS  DECISION ADOPTED  - - 12.920 5.970 12.920 5.970 Data Warehouse Consolidation 0.783 0.333 4.700 2.000 3.917 1.667 Lotus Notes Migration 0.650 0.500 3.900 3.000 3.250 2.500 0.333 0.383 2.000 2.300 1.667 1.917 - 0.375 - 2.250 - 1.875 0.067 0.250 0.400 1.500 0.333 1.250 User Experience Technologies 0.083 0.133 0.500 0.800 0.417 0.667 Application Distribution 0.067 0.200 0.400 1.200 0.333 1.000 0.083 0.250 0.500 1.500 0.417 1.250 - - - - - - - - - - - - 1.250 0.667 7.500 4.000 6.250 3.333 Disaster Recovery Optimization Enterprise Schedulers Consolidation Database Backup Optimization Modernize Tools for Software Development CITRIX VDI Capacity Increase SCE.com Strategic Upgrade Digital Customer Self Service V. OU Software Alerts and Notifications 0.717 0.817 4.300 4.900 3.583 4.083 V. OU Software Meter Data Management System Upgrade 0.470 - 6.700 - 6.233 - V. OU Software NMS Upgrade - - - - - - -2- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  PROJECT  SCE FORECASTS  DECISION ADOPTED  V. OU Software 2015 GRC Rate Changes - - - - - - V. OU Software SmartConnect Monitor&Analy sis (SCMAS) - 0.160 - 0.960 - 0.800 V. OU Software 2018 GRC Rate Changes 0.167 0.167 1.000 1.000 0.833 0.833 V. OU Software Contact Center Optimization - 0.483 - 2.900 - 2.417 V. OU Software WM - Portfolio Management 1.000 1.033 6.000 6.200 5.000 5.167 0.333 0.500 2.000 3.000 1.667 2.500 0.167 0.083 1.000 0.500 0.833 0.417 - 0.333 - 2.000 - 1.667 - - 2.500 3.500 2.500 3.500 0.950 - 5.700 - 4.750 - - - - - - - - - - - - - 0.250 0.583 1.500 3.500 1.250 2.917 - - 0.370 - 0.370 - V. OU Software V. OU Software V. OU Software V. OU Software Scope Cost Management Tool (SCMT) Work Management Dashboard Transmission Telecomm Work Order Lifecycle Click Schedule Refresh Release 1&2 V. OU Software Vegetation Management V. OU Software Pole Loading Application Replacement Tool V. OU Software Design Manager (DM) Refresh V. OU Software V. OU Software Graphic Design Tool (GDT) and Tract Deployment Refresh Consolidated Mobile Solution (CMS) -3- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software PROJECT  Field Tools Upgrade Enhanced Business Resiliency for Energy Management System Comprehensive Situational Awareness for Transmission (CSAT) Centralized Remedial Action Scheme (CRAS) RGOOSE Conversion Energy Management System (EMS) Refresh Outage Management System Distribution Management System (DMS) Refresh Grid Interconnection Processing Tool SCE FORECASTS  DECISION ADOPTED  - 0.167 - 1.000 - 0.833 0.500 0.667 3.000 4.000 2.500 3.333 0.333 0.667 2.000 4.000 1.667 3.333 - - - - - - 0.983 - 5.900 - 4.917 - 1.203 0.445 7.220 2.670 6.017 2.225 0.447 - 3.500 - 3.053 - - - - - - - 1.140 1.044 6.841 6.263 5.701 5.219 V. OU Software Grid Analytics Applications 2.104 0.059 12.621 0.353 10.518 0.294 V. OU Software Long Term Planning Tool 1.045 0.996 6.268 5.976 5.223 4.980 0.830 0.834 4.981 5.005 4.151 4.171 0.055 - 0.330 - 0.275 - V. OU Software V. OU Software Grid Connectivity Model Transient Devices (HW for Test Smart -4- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  PROJECT  SCE FORECASTS  DECISION ADOPTED  Form Tool) V. OU Software V. OU Software V. OU Software High-Z Impedence Fault Detection Secure DNP Ver5 Support for EMS Grid Management Dashboards V. OU Software PSMP 2.0 V. OU Software Substation Health Assessment Tool (previously Asset Mgmt) V. OU Software Substation 3D Design V. OU Software Electronic Work Order Package Product Automation (e-WOP Ph 2) V. OU Software Fast Repsonse Energy Storage V. OU Software Generation Automation Upgrade & Control Systems Refresh V. OU Software V. OU Software V. OU Software V. OU Software Dam Monitoring and Surveillance CAISO Market Enhancement Program (IMEP) Energy Planning Platform (EPP) Upgrade PCI Replacement - - - - - - - - - - - - 0.333 - 2.000 - 1.667 - - 0.167 - 1.000 - 0.833 - 0.433 - 2.600 - 2.167 - 0.210 - 1.260 - 1.050 - - - - - - - - - - - - 0.500 0.333 3.000 2.000 2.500 1.667 0.167 0.333 1.000 2.000 0.833 1.667 0.667 0.667 4.000 4.000 3.333 3.333 - 0.333 - 2.000 - 1.667 -5- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software V. OU Software PROJECT  Energy Trading and Risk Management (ETRM) Aggregated Demand Response (ADR) Commodity Management Platform (CMP) Generation Management System (GMS) Upgrade Usage Measurement System (UMS) Work Management and Reliability-Cent ered Maintentance PPD Control Systems Refresh Gas Solar Control Systems Refresh Enterprise Content Management Electronic Document Management / Records Management (eDMRM) V. OU Software Plant Ledger System Upgrade V. OU Software Legal Re-platform SCE FORECASTS  DECISION ADOPTED  0.500 0.583 3.000 3.500 2.500 2.917 0.500 0.400 3.000 2.400 2.500 2.000 0.145 - 0.870 - 0.725 - - - - - - - - - - - - - - 0.200 - 1.200 - 1.000 - 0.083 - 0.500 - 0.417 - - - - - - - - 1.570 0.600 1.570 0.600 0.567 0.867 3.400 5.200 2.833 4.333 - - - - - - - - - - - - 0.367 - 2.200 - 1.833 - -6- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege EXHIBIT  PROJECT  SCE FORECASTS  DECISION ADOPTED  V. OU Software Reg Affairs - TM2 Replacement - - - - - - V. OU Software Integrated Budget Planning - - - - - - V. OU Software Union Negotiations - - - - - - V. OU Software C-CURE 9000 - - - - - - V. OU Software Facilities Management System - - - - - - V. OU Software EHSync Env Clearance Ph 2 0.157 0.062 0.940 0.370 0.783 0.308 V. OU Software Crisis Information Management System - - - - - - V. OU Software Seismic Risk Assessment - 0.333 - 2.000 - 1.667 V. OU Software Ariba Deployment and Supplier Portal Decommission 0.167 - 1.000 - 0.833 - V. OU Software Mobile Field Response - - - - - - V. OU Software Safety Observation - - - - - - 24.751 23.856 212.777 201.077 188.026 177.221 TOTALS (End of Appendix B) -7- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION APPENDIX C RESULTS OF OPERATIONS 2018 -8- A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 General Rate Case Results of Operations Model Table of Contents Appendices 1. 2. 3. 4. 5. 6. 7. Summary Appendices Appendix C CPUC RO Appendix C CPUC RO Comparison Appendix C Total Company RO Appendix C Post-Test Year SoE Appendix C Juris Allocation % Appendix C Net-To-Gross Appendix C Sales Forecast 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. O&M Expense Appendices Appendix C Generation Summary Appendix C Steam Appendix C Nuclear Appendix C Hydro Appendix C Other Production Appendix C Transmission Appendix C Distribution Appendix C Customer Accounts Appendix C CS&I Appendix C A&G Appendix C Total O&M Expense Appendix C OOR -9- 20. 21. Tax Expense Appendices Appendix C Other Taxes Appendix C Income Taxes 22. 23. 24. 25. 26. Capital & Rate Base Appendices Appendix C Depreciation Appendix C Plant Appendix C Average Lag Appendix C Working Cash Appendix C Rate Base A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C 2018 CPUC Results of Operations $ in Thousands Appendix C 2018 CPUC Results of Operations Line Item 1. Total Operating Revenues 2. 3. 4. 5. 6. 7. 8. Operating Expenses: Production Steam Nuclear Hydro Other Total Production O&M 9. 10. 11. 12. 13. 14. 15. 16. 17. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Revenue Credits Total O&M 18. Escalation 19. Depreciation 20. 21. 22. Taxes Other Than On Income Taxes Based On Income Total Taxes 23. Total Operating Expenses 24. Net Operating Revenue 25. Rate Base 26. Rate of Return 27. Revenues at Present Rates 28. Increase/(Decrease) Over Present Revenue Requirement In Rates 29. Balancing/Memorandum Account Undercollection 30. Net Increase/(Decrease) Over Present Rates 31. 32. Decrease Over Present Revenue Requirement In Rates Net Decrease Over Present Rates Adopted 5,169,930 PVRR Adjustment Rate Base Adjustment (40,033) 6,251 76,747 41,446 81,962 206,406 – – – – – 90,970 496,193 155,395 10,909 21,277 602,534 47,274 (151,292) 1,479,666 – – – – – – – – – (28,323) – – – – – – – – (60) – – (259) – (319) Adopted CPUC Total SCE Request (Based on Feb 2018 Tax Update Testimony) Difference (Adopted Less SCE Request) 5,101,574 5,534,406 (432,832) 6,251 76,747 41,446 81,962 206,406 7,845 76,747 41,446 81,965 208,003 (1,594) – – (3) (1,597) 90,970 496,193 155,395 10,849 21,277 602,534 47,015 (151,292) 1,479,347 91,118 532,099 159,329 11,954 21,007 647,853 50,607 (153,070) 1,568,900 (148) (35,906) (3,934) (1,106) 270 (45,319) (3,592) 1,778 (89,553) 95,169 – – 95,169 103,952 (8,784) 1,571,266 – – 1,571,266 1,752,338 (181,072) 324,801 38,919 363,720 (9,962) (52,128) (62,090) 314,839 (7,096) 307,743 – – – – (6,113) (6,113) 3,453,843 – (6,431) 3,447,412 3,788,910 (341,499) 1,716,087 (40,033) (21,892) 1,654,163 1,745,496 (91,333) 22,552,795 – (287,700) 22,265,095 22,939,281 (674,187) 7.61% – 7.43% 7.61% 5,640,432 5,640,432 5,640,432 7.61% 314,839 (13,209) 301,630 (470,502) (538,858) (106,026) 41,469 41,469 41,469 (429,033) (497,389) (64,557) -9.55% -8.82% - 10 - 13.55% (432,832) – (432,832) A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C 2018 CPUC Results of Operations Comparison $ in Thousands Comparison of Revenue Requirements (Excludes Balancing/Memo Account Recovery) 2018 2019 2020 $ $ $ CPUC Adopted vs. SCE Request SCE-60 (Feb 2018) CPUC Adopted 5,101,574 SCE Request SCE-60 (Feb 2018) 5,534,406 Difference (432,832) Decrease From SCE Request (7.82%) 5,421,553 5,965,179 (543,626) (9.11%) 5,822,853 6,468,180 (645,327) (9.98%) CPUC Adopted vs. Revenues at Present Rates CPUC Adopted 5,101,574 Revenues at Present Rates 5,640,432 Difference (538,858) Increase Over Present Rates (9.55%) 5,421,553 5,640,432 (218,879) (3.88%) 5,822,853 5,640,432 182,421 3.23% SCE Request vs. Revenues at Present Rates SCE Request Revenues at Present Rates Difference Increase Over Present Rates 5,965,179 5,640,432 324,747 5.76% 6,468,180 5,640,432 827,748 14.68% 5,534,406 5,640,432 (106,026) (1.88%) - 11 - Increase Over Prior Year 2019 2020 Increase $ Increase $ 319,979 430,773 (110,794) 401,300 503,001 (101,701) Increase Over Prior Year 2019 2020 Increase % Increase % 6.27% 7.78% 7.40% 8.43% A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C 2018 Total Company Results of Operations $ in Thousands Appendix C 2018 Total Company Results of Operations Line Total Company Item 1. Total Operating Revenues 2. 3. 4. 5. 6. 7. 8. Operating Expenses: Production Steam Nuclear Hydro Other Total Production O&M 9. 10. 11. 12. 13. 14. 15. 16. 17. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Revenue Credits Total O&M 18. Escalation 19. Depreciation 20. 21. 22. Taxes Other Than On Income Taxes Based On Income Total Taxes 23. Total Operating Expenses 3,970,877 24. Net Operating Revenue 2,143,425 25. Rate Base 26. Rate of Return 6,114,303 6,251 76,747 41,446 81,962 206,406 172,193 499,722 155,395 12,901 21,277 641,611 55,909 (202,203) 1,563,211 101,037 1,825,129 382,198 99,302 481,500 28,168,867 7.61% - 12 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Post Test Year Summary of Earnings $ in Thousands Appendix C Post Test Year Summary of Earnings Line Item 1. Total Operating Revenues 2. 3. 4. 5. 6. 7. 8. Operating Expenses: Production Steam Nuclear Hydro Other Total Production O&M 9. 10. 11. 12. 13. 14. 15. 16. 17. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Revenue Credits Total O&M 18. Escalation 19. Depreciation 20. 21. 22. Taxes Other Than On Income Taxes Based On Income Total Taxes 23. 2019 PVRR Rate Base Adjustment Adjustment CPUC 5,488,729 (40,033) (27,143) CPUC 5,421,553 5,888,849 (40,033) 6,251 76,747 41,446 81,962 206,406 6,251 76,747 41,446 81,962 206,406 – – – – – 90,970 496,193 155,395 11,524 21,277 596,836 49,941 (155,776) 1,472,766 90,970 496,193 155,395 12,425 21,277 596,590 53,848 (158,678) 1,474,426 – – – – – – – – – (25,963) 5,822,853 – – – – – 90,970 496,193 155,395 11,581 21,277 596,836 50,189 (155,776) 1,473,072 – – – – – – – – – 142,218 – – 142,218 187,662 – – 187,662 1,646,455 – – 1,646,455 1,746,062 – – 1,746,062 334,447 41,748 376,195 – – – – (5,858) (5,858) 334,447 35,890 370,337 357,868 135,154 493,022 – – – – (5,603) (5,603) 357,868 129,550 487,418 Total Operating Expenses 3,637,941 – (6,163) 3,631,777 3,901,172 – (5,895) 3,895,276 24. Net Operating Revenue 1,850,788 (40,033) (20,980) 1,789,776 1,987,677 (40,033) (20,067) 1,927,576 25. Rate Base 24,323,030 – (275,712) 24,047,318 26,122,019 – (263,725) 25,858,294 26. Rate of Return 7.44% 7.61% - 13 - – – – (57) – – (248) – (305) 7.61% – – – – – CPUC 6,251 76,747 41,446 81,962 206,406 7.61% – – – – – CPUC 2020 PVRR Rate Base Adjustment Adjustment – – – (55) – – (237) – (292) 7.61% 6,251 76,747 41,446 81,962 206,406 90,970 496,193 155,395 12,371 21,277 596,590 53,610 (158,678) 1,474,134 7.45% A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Results of Operations Jusidictional Allocation % $ in Thousands Appendix C Results of Operations Jusidictional Allocation % Total Line Description Company 1. Total Operating Revenues 2. 3. 4. 5. 6. 7. 8. Operating Expenses: Production Steam Nuclear Hydro Other Total Production 9. 10. 11. 12. 13. 14. 15. 16. 17. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Revenue Credits Total O&M 18. Escalation 19. Depreciation 20. 21. 22. 23. 24. Taxes Other Than On Income Taxes Other Than On Income - Property Taxes Other Than On Income - Payroll Taxes Based On Income Total Taxes 25. FERC CPUC Jurisdictional Allocation % % for 2018 FERC CPUC Total 6,045,947 944,373 5,101,574 15.6% 84.4% 100.0% 6,251 76,747 41,446 81,962 206,406 – – – – – 6,251 76,747 41,446 81,962 206,406 – – – – – 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 47.2% 0.7% – 15.5% – 6.1% 15.5% 25.2% 5.3% 52.8% 99.3% 100.0% 84.5% 100.0% 93.9% 84.5% 74.8% 94.7% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 172,193 499,722 155,395 12,841 21,277 641,611 55,650 (202,203) 1,562,893 81,223 3,529 – 1,993 – 39,077 8,635 (50,911) 83,546 101,037 5,868 95,169 5.8% 94.2% 100.0% 1,825,129 253,863 1,571,266 13.9% 86.1% 100.0% 318,357 63,841 93,189 475,387 63,471 3,888 106,398 173,758 19.9% 6.1% 114.2% 36.6% 80.1% 93.9% (14.2%) 63.4% 100.0% 100.0% 100.0% 100.0% Total Operating Expenses 3,964,446 517,035 3,447,412 13.0% 87.0% 100.0% 26. Net Operating Revenue 2,081,501 427,338 1,654,163 20.5% 79.5% 100.0% 27. Rate Base 27,881,167 5,616,072 22,265,095 20.1% 79.9% 100.0% 28. Rate Of Return 7.47% 7.61% 7.43% - 14 - 90,970 496,193 155,395 10,849 21,277 602,534 47,015 (151,292) 1,479,347 254,886 59,953 (13,209) 301,630 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Net-to-Gross Multiplier Appendix C Net-to-Gross Multiplier Total Company Line Description 1. Revenues 1.00000 2. 3. 4. 5. Uncollectibles Tax Multiplier Tax Rate Jurisdictional Factor Tax Rate (Jurisdictionalized) Uncollectibles Tax Multiplier 0.00211 1.00000 0.00211 0.99789 6. 7. 8. 9. Franchise Fees Tax Mutliplier Tax Rate Jurisdictional Factor Tax Rate (Jurisdictionalized) Franchise Fees Tax Mutliplier 0.00914 1.00000 0.00914 0.98875 10. 11. 12. 13. 14. Other State(s) Income Tax Multiplier Tax Rate Jurisdictional Factor Tax Rate (Jurisdictionalized) Other State(s) Income Tax Multiplier – 0.98875 – 0.98875 15. 16. 17. 18. 19. State Income Tax Multiplier Tax Rate Jurisdictional Factor Tax Rate (Jurisdictionalized) State Income Tax Multiplier 0.08840 0.98875 0.08741 0.90134 20. 21. 22. 23. 24. Federal Income Tax Multiplier Tax Rate Jurisdictional Factor Tax Rate (Jurisdictionalized) Federal Income Tax Multiplier 0.21000 0.98875 0.20764 0.69370 25. 26. Uncollectibles and Franchise Fees Multiplier Net to Gross Multiplier 1.01138 1.44154 - 15 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege Southern California Edison 2018 GRC Appendix C Sales Forecast Appendix C Sales Forecast Line 1. 2. 3. 4. Item Sales Forecast (GWh) Residential Commercial Industrial 5. 6. 7. Other Public Authority Agricultural Total Sales Forecast 8. 9. 10. 11. Customer Forecast Residential Commercial Industrial 12. 13. 14. Other Public Authority Agricultural Total Sales Forecast 1 Total Company 27,722 1,499 42,086 7,888 4,377 83,572 4,486,121 20,948 582,516 1 1) Includes Street Lights - 16 - 10,651 46,606 5,146,842 DECISION A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Reports Generation $ in Thousands Appendix C Reports Generation Line Total CPUC Item 1. 2. 3. 4. 5. Steam Nuclear Hydro Other Total Production (Constant 2015$) 6,251 76,747 41,446 81,962 206,406 6. Escalation 7. Total Production (Nominal 2018$) 220,699 8. 9. 10. 11. 12. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 75,360 126,024 5,022 206,406 13. 14. 15. 16. 17. Escalation: Labor Non-Labor Other Total Escalation 18. Total O&M (Nominal 2018$) 14,294 6,786 7,508 – 14,294 220,699 - 17 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Steam $ in Thousands Appendix C Steam Line FERC Total CPUC Description 1. 2. 3. 4. 5. 6. 7. 8. 500 Operation Supervision and Engineering 501 Fuel 502 Steam Expenses 505 Electric Expenses 506 Miscellaneous Steam Power Expenses 507 Rents 509 Allowances Total Operation 5,925 – – – 326 – – 6,251 9. 10. 11. 12. 13. 14. 510 Maintenance Supervision and Engineering 511 Maintenance of Structures 512 Maintenance of Boiler Plant 513 Maintenance of Electric Plant 514 Maintenance of Miscellaneous Steam Plant Total Maintenance 15. Total Steam (Constant 2015$) 16. Escalation 17. Total Steam (Nominal 2018$) 6,804 18. 19. 20. 21. 22. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 6,085 166 – 6,251 23. 24. 25. 26. 27. Escalation: Labor Non-Labor Other Total Escalation 28. Total O&M (Nominal 2018$) – – – – – – 6,251 553 548 5 – 553 6,804 - 18 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Nuclear $ in Thousands Appendix C Nuclear Line FERC Total CPUC Description 1. 2. 3. 4. 5. 6. 7. 8. 517 Operation Supervision and Engineering 518 Nuclear Fuel Expense 519 Coolants and Water 520 Steam Expenses 523 Electric Expenses 524 Miscellaneous Nuclear Power Expenses 525 Rents Total Operation – – – – – 76,747 – 76,747 9. 10. 11. 12. 13. 14. 528 Maintenance Supervision and Engineering 529 Maintenance of Structures 530 Maintenance of Reactor Plant Equipment 531 Maintenance of Electric Plant 532 Maintenance of Miscellaneous Nuclear Plant Total Maintenance 15. Total Nuclear (Constant 2015$) 16. Escalation 17. Total Nuclear (Nominal 2018$) 82,860 18. 19. 20. 21. 22. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 132 76,615 – 76,747 23. 24. 25. 26. 27. Escalation: Labor Non-Labor Other Total Escalation 28. Total O&M (Nominal 2018$) – – – – – – 76,747 6,113 12 6,101 – 6,113 82,860 - 19 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Hydro $ in Thousands Appendix C Hydro Line FERC Total CPUC Description 1. 2. 3. 4. 5. 6. 7. 535 Operation Supervision and Engineering 536 Water for Power 537 Hydraulic Expenses 538 Electric Expenses 539 Miscellaneous Hydraulic Power Generation Expenses 540 Rents Total Operation – 5,128 – – 26,779 – 31,907 8. 9. 10. 11. 12. 13. 528 Maintenance Supervision and Engineering 529 Maintenance of Structures 530 Maintenance of Reactor Plant Equipment 531 Maintenance of Electric Plant 532 Maintenance of Miscellaneous Nuclear Plant Total Maintenance 14. Total Hydro (Constant 2015$) 15. Escalation 16. Total Hydro (Nominal 2018$) 43,917 17. 18. 19. 20. 21. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 22,361 19,085 – 41,446 22. 23. 24. 25. 26. Escalation: Labor Non-Labor Other Total Escalation 27. Total O&M (Nominal 2018$) – – – – 9,539 9,539 41,446 2,471 2,014 457 – 2,471 43,917 - 20 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Other Production $ in Thousands Appendix C Other Production Line FERC Total CPUC Description 1. 2. 3. 4. 5. 6. 546 Operation Supervision and Engineering 547 Fuel 548 Generation Expenses 549 Miscellaneous Other Power Generation Expenses 550 Rents Total Operation – – – 18,418 2,332 20,750 7. 8. 9. 10. 11. 12. 13. 14. 551 Maintenance Supervision and Engineering 552 Maintenance of Structures 553 Maintenance of Generating and Electric Plant 554 Maintenance of Miscellaneous Other Power Generation Plant 555 Purchased Power 556 System Control and Load Dispatching 557 Other Expenses Total Maintenance – – – 18,771 – – 42,441 61,212 15. Total Other Production (Constant 2015$) 81,962 16. Escalation 17. Total Other Production (Nominal 2018$) 87,119 18. 19. 20. 21. 22. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 46,782 30,158 5,022 81,962 23. 24. 25. 26. 27. Escalation: Labor Non-Labor Other Total Escalation 28. Total O&M (Nominal 2018$) 5,157 4,213 944 – 5,157 87,119 - 21 - A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Transmission $ in Thousands Appendix C Transmission Total CPUC Line FERC Description 1. 2. 3. 4. 5. 6. 7. 8. 9. 560 561 562 563 564 565 566 567 Operation Supervision and Engineering Load Dispatching Station Expenses Overhead Line Expenses Underground Line Expenses Transmission of Electricity by Others Miscellaneous Transmission Expenses Rents Total Operation 15,608 5,185 10,301 – – 2,434 20,299 9,088 62,916 10. 11. 12. 13. 14. 15. 16. 568 569 570 571 572 573 Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Station Equipment Maintenance of Overhead Lines Maintenance of Underground Lines Maintenance of Miscellaneous Transmission Plant Total Maintenance 3,716 – 7,440 15,943 – 956 28,055 17. Total O&M (Constant 2015$) 90,970 18. Escalation 19. Total O&M (Nominal 2018$) 95,398 20. 21. 22. 23. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 40,172 41,723 9,075 90,970 24. 25. 26. 27. Escalation: Labor Non-Labor Other Total Escalation 28. Total O&M (Nominal 2018$) 4,428 4,054 374 – 4,428 - 22 - 95,398 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Distribution $ in Thousands Appendix C Distribution Total CPUC Line FERC Description 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 580 582 583 584 585 586 587 588 589 Operation Supervision and Engineering Station Expenses Overhead Line Expenses Underground Line Expenses Street Lighting and Signal System Expenses Meter Expenses Customer Installations Expenses Miscellaneous Distribution Expenses Rents Total Operation 21,611 27,817 79,763 – 6,887 30,654 6,460 105,012 – 278,204 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 590 591 592 593 594 595 596 597 598 Maintenance Supervision and Engineering Maintenance of Structures Maintenance of Station Equipment Maintenance of Overhead Lines Maintenance of Underground Lines Maintenance of Line Transformers Maintenance of Street Lighting and Signal Systems Maintenance of Meters Maintenance of Miscellaneous Distribution Plant Total Maintenance – – 13,147 127,734 65,824 – – – 11,285 217,990 21. Total O&M (Constant 2015$) 496,193 22. Escalation 23. Total O&M (Nominal 2018$) 521,439 24. 25. 26. 27. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 239,024 254,374 2,796 496,193 28. 29. 30. 31. Escalation: Labor Non-Labor Other Total Escalation 32. Total O&M (Nominal 2018$) 25,245 21,414 3,831 – 25,245 - 23 - 521,439 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Customer Accounts $ in Thousands Appendix C Customer Accounts Line FERC 1. 2. 3. 4. 5. 6. 7. 901 902 903 904 905 Total CPUC Description Supervision Meter Reading Expenses Customer Records and Collection Expenses Uncollectible Accounts Miscellaneous Customer Accounts Expenses Interest Offset on Customer Deposits Total Customer Accounts (Constant 2015$) 4,400 9,909 97,272 10,909 39,556 4,258 166,304 Rate Base Adjustment (60) (60) 10,835 Total CPUC 4,400 9,909 97,272 10,849 39,556 4,258 166,244 8. Escalation 9. Total Customer Accounts (Nominal 2018$) 177,139 (60) 177,079 10. Less: Account 904 (Uncollectible Accounts) (10,909) 60 (10,849) 11. Total Customer Accounts (Nominal 2018$ - Less Account 904) 166,231 – 166,231 12. 13. 14. 15. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 88,797 66,598 10,909 166,304 (60) (60) 88,797 66,598 10,849 166,244 16. 17. 18. 19. Escalation: Labor Non-Labor Other Total Escalation 7,996 2,839 – 10,835 – 7,996 2,839 – 10,835 20. Total Customer Accounts (Nominal 2018$) 177,139 (60) 177,079 21. Less: Account 904 (Uncollectible Accounts) (10,909) 60 (10,849) 22. Total O&M (Nominal 2018$ - Less Account 904) 166,231 – 166,231 - 24 - 10,835 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Customer Service & Information $ in Thousands Appendix C Customer Service & Information Total CPUC Line FERC Description 1. 2. 3. 4. 5. 6. 7. 907 908 909 910 912 913 Supervision Customer Assistance Expenses Informational and Instructional Advertising Expenses Miscellaneous Customer Service and Informational Expenses Demonstrating and Selling Expenses Advertising Expenses Total Customer Service & Information 2,487 18,790 – – – – 21,277 8. 9. 916 Miscellaneous Sales Expenses Total Customer Service & Information (Constant 2015$) – 21,277 10. Escalation 1,709 11. Total Customer Service & Information (Nominal 2018$) 22,986 12. 13. 14. 15. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 17,521 3,756 – 21,277 16. 17. 18. 19. Escalation: Labor Non-Labor Other Total Escalation 20. Total O&M (Nominal 2018$) 1,578 131 – 1,709 - 25 - 22,986 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C A&G Summary $ in Thousands Appendix C A&G Summary Line FERC 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 920 921 922 923 924 925 926 927 928 930 931 14. 15. 935 Total CPUC Description Administrative and General Salaries Office Supplies and Expenses Administrative Expenses Transferred - Credit Outside Services Employed Property Insurance Injuries and Damages Employee Pensions and Benefits Franchise Requirements Regulatory Commission Expenses General Advertising Expenses-Miscellaneous General Expenses Rents Reduction for A&G Credit for Catalina Utilities Total Operation Maintenance of General Plant Total O&M (Constant 2015$) Rate Base Adjustment 237,306 225,326 (113,491) 40,310 13,213 118,720 40,535 47,274 – 19,126 7,180 (509) 634,991 (259) 237,306 225,326 (113,491) 40,310 13,213 118,720 40,535 47,015 – 19,126 7,180 (509) 634,732 14,817 649,808 (259) 14,817 649,549 16. Escalation 17. Total O&M (Nominal 2018$) 688,465 18. Less: Account 927 (Franchise Requirements) (47,274) 19. Total O&M (Nominal 2018$ - Less Account 927) 641,191 20. 21. 22. 23. Labor, Non-labor, and Other Expense Detail: Labor Non-Labor Other Total O&M (Constant 2015$) 249,536 325,665 74,606 649,808 24. 25. 26. 27. Escalation: Labor Non-Labor Other Total Escalation 28. Total O&M (Nominal 2018$) 688,465 29. Less: Account 927 (Franchise Requirements) (47,274) 30. Total O&M (Nominal 2018$ - Less Account 927) 641,191 (259) 38,657 22,471 16,186 – 38,657 - 26 - Total CPUC 38,657 (259) 688,206 (47,274) (259) 640,932 (259) (259) 249,536 325,665 74,347 649,549 – (259) 22,471 16,186 – 38,657 688,206 (47,274) (259) 640,932 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C A&G Summary $ in Thousands Appendix C A&G Summary Line Description Constant $ 1. Production 2. Steam 3. Nuclear 4. Hydro 5. Other 6. Total Production Labor Total CPUC Non-Labor Other Total 6,085 132 22,361 46,782 75,360 166 76,615 19,085 30,158 126,024 – – – 5,022 5,022 6,251 76,747 41,446 81,962 206,406 40,172 239,024 88,797 – 17,521 249,536 – 710,410 41,723 254,374 66,598 – 3,756 325,665 – 818,140 9,075 2,796 – 10,909 – 27,333 47,274 102,408 90,970 496,193 155,395 10,909 21,277 602,534 47,274 1,630,958 548 12 2,014 4,213 6,786 5 6,101 457 944 7,508 – – – – – 553 6,113 2,471 5,157 14,294 7. 8. 9. 10. 11. 12. 13. 14. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Total O&M (Constant 2015$) 15. 16. 17. 18. 19. 20. 21. Escalation $ Production Steam Nuclear Hydro Other Total Production 22. 23. 24. 25. 26. 27. 28. 29. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Total O&M Escalation $ 4,054 21,414 7,996 – 1,578 22,471 – 64,299 374 3,831 2,839 – 131 16,186 – 30,870 – – – – – – – – 4,428 25,245 10,835 – 1,709 38,657 – 95,169 30. 31. 32. 33. 34. 35. 36. Nominal $ Production Steam Nuclear Hydro Other Total Production 6,632 144 24,375 50,995 82,146 171 82,716 19,542 31,102 133,532 – – – 5,022 5,022 6,804 82,860 43,917 87,119 220,699 37. 38. 39. 40. 41. 42. 43. 44. Transmission Distribution Customer Accounts Uncollectibles Customer Service & Information Administrative & General Franchise Requirements Total O&M (Nominal 2018$) 44,226 260,438 96,794 – 19,099 272,007 – 774,709 42,097 258,205 69,437 – 3,887 341,852 – 849,010 9,075 2,796 – 10,909 – 27,333 47,274 102,408 95,398 521,439 166,231 10,909 22,986 641,191 47,274 1,726,126 - 27 - Rate Base Adjustment – (60) (259) (319) Total CPUC 6,251 76,747 41,446 81,962 206,406 90,970 496,193 155,395 10,849 21,277 602,534 47,015 1,630,639 – 553 6,113 2,471 5,157 14,294 – 4,428 25,245 10,835 – 1,709 38,657 – 95,169 – 6,804 82,860 43,917 87,119 220,699 (60) (259) (319) 95,398 521,439 166,231 10,849 22,986 641,191 47,015 1,725,807 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Other Operating Revenue $ in Thousands Appendix C Other Operating Revenue Total CPUC Line Description 1. 2. 450.000 - Forfeited Discounts Customer Service Operations OOR 3. 4. 5. 6. 451.000 - Miscellaneouse Service Revenues Customer Service Operations OOR Transmission & Distribution OOR Total 451.000 7. 8. 453.000 - Sales of Water & Water Power Financial and Other Miscellaneous Revenues 110 9. 10. 11. 12. 454.000 - Rent from Electric Property Transmission & Distribution OOR Financial and Other Miscellaneous Revenues Total 454.000 29,247 10,505 39,753 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 456.000 - Other Electric Revenue Customer Service Operations OOR CS&I Tariffed Products and Services OOR Transmission & Distribution OOR Financial and Other Miscellaneous Revenues Total 456.000 Gains/Losses on Sale of Property Gross Revenue Sharing Mechanism Authorized Threshold Escalation Total OOR 11,396 - 28 - 8,096 854 8,949 1,039 405 53,988 22,839 78,271 338 12,474 – 151,292 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Taxes Other Than On Income $ in Thousands Appendix C Taxes Other Than On Income Total CPUC Line Description 1. Ad Valorem (Property) Taxes 2. 3. 4. 5. Payroll Taxes Federal Insurance Contribution Act (FICA) Federal Unemployment Tax Act (FUTA) State Unemployment Tax Act (SUTA) Total Payroll Taxes 6. 7. 8. 9. Miscellaneous Taxes ITC Amortization on CTC Property ARAM Expense on CTC Property Total Taxes Other Than Income - 29 - 254,886 52,895 267 2,803 55,964 4,547 (558) – 314,839 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Taxes Based on Income $ in Thousands Appendix C Taxes Based on Income Total CPUC Line Description State Income Taxes 1. Operating Revenue Rate Base Adjustment 5,169,930 Total CPUC 2. 3. 4. Operating Expenses Taxes Other Than On Income Total Expenses 1,574,834 314,839 1,889,673 5,169,930 – 1,574,834 314,839 1,889,673 5. Income Tax Adjustments (Schedule M) 1,920,343 1,920,343 6. State Taxable Income 7. 8. California Income Tax Rate California Tax Expense 9. 10. Arizona Income Tax Rate Arizona Tax Expense – – – 11. 12. New Mexico Income Tax Rate New Mexico Tax Expense – – – 13. Total State Income Taxes 14. Federal Income Taxes Operating Revenue 15. 16. 17. 18. 19. 20. (30,669) (30,669) 8.84% (2,711) (2,711) (2,711) (2,711) 5,169,930 5,169,930 Operating Expenses Taxes Other Than On Income State Income Taxes Less: California Tax Expense (Current Year) Plus: California Tax Expense (Prior Year) Total Expenses 1,574,834 314,839 (2,711) 2,711 1,889,673 1,574,834 314,839 (2,711) 2,711 – 1,889,673 21. Income Tax Adjustments (Schedule M) 1,925,589 1,925,589 22. Federal Taxable Income (35,916) (35,916) 23. 24. Federal Income Tax Rate Federal Tax Expense 21.00% (7,542) (7,542) 25. 26. 27. 28. 29. 30. 31. Deferred Taxes (Plant) Deferred Taxes (AFUDC Debt) Deferred Taxes (Capitalized Interest) Contributions in Aid of Construction Investment Tax Credit Accrued Vacation Pay Total Federal Income Taxes 6 – – 2,654 700 (203) (4,385) 6 – – 2,654 700 (203) (4,385) 32. Total Income Taxes (State & Federal) - 30 - (7,096) (6,113) (13,209) A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Depreciation & Amortization $ in Thousands Appendix C Depreciation & Amortization Line Description CPUC 1. 2. 3. 4. 5. 6. Generation Nuclear Other Production Hydro Mountainview Total Generation 19,295 38,533 27,691 23,508 109,028 7. 8. 9. 10. 11. Transmission Land Substations Lines Total Transmission 764 74,384 47,864 123,013 12. 13. 14. 15. 16. Distribution Land Substations Lines Total Distribution 1,215 65,767 831,216 898,197 17. General 224,540 18. Total Depreciation 19. 20. 21. 22. 23. 24. 25. Amortization Mountainview Intangibles Radio Frequency Hydro Relicensing Miscellaneous Intangibles Capitalized Software Total Amortization 26. Total Depreciation & Amortization 1,354,778 - 31 - Rate Base Adjustment Total CPUC – 19,295 38,533 27,691 23,508 109,028 – 764 74,384 47,864 123,013 – 1,215 65,767 831,216 898,197 224,540 – 1,354,778 1,053 440 2,826 25 212,144 216,488 – 1,053 440 2,826 25 212,144 216,488 1,571,266 – 1,571,266 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege Southern California Edison 2018 GRC Appendix C Plant In Service $ in Thousands Appendix C Plant In Service Line Description CPUC 1. 2. 3. 4. 5. 6. Generation Nuclear Other Production Hydro Mountainview Total Generation 2,029,997 879,810 1,304,470 803,079 5,017,356 7. 8. 9. 10. 11. Transmission Land Substations Lines Total Transmission 96,087 3,014,636 1,922,174 5,032,898 12. 13. 14. 15. 16. Distribution Land Substations Lines Total Distribution 17. General 18. Total Plant 19. 20. 21. 22. 23. 24. Intangible Plant Moutainview Intangibles Radio Frequency Hydro Relicensing Miscellaneous Intangibles Capitalized Software Total Intangible Plant 25. Total Plant in Service 123,339 3,339,657 20,791,201 24,254,198 2,831,566 37,136,016 - 32 - 41,930 17,583 153,158 497 1,077,124 1,290,292 38,426,308 DECISION A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Average Lag In Payment of Operating Expenses $ in Thousands Appendix C Average Lag In Payment of Operating Expenses Total Company Line Description Average Lag Days Dollar Day Lags 1. 2. 3. 4. 5. Total Fuel Purchase Power QF USPS Purchase Power QF EFT Purchase Power Non-QF Subtotal 206,253 767,060 1,736,392 2,070,701 4,780,406 32.2 53.1 44.3 23.6 36.2 6,641,332 40,730,886 76,922,188 48,868,544 173,162,950 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. Company Labor Short-Term Incentive Plan (STIP) Other O&M Expenses Goods & Services Materials Issued from Stores Insurance & Line Rent Provisions Injuries and Damages Funded Pension Provisions Benefits & Unfunded Pension Provisions PBOP Provisions Franchise Requirements Uncollectibles CPUC Fees Subtotal 830,301 69,995 1,043,628 756,341 4,915 31,273 128,420 57,741 (17,873) 3,850 109,780 25,332 – 3,043,702 12.1 258.0 42.7 43.9 – – – (17.8) 3.1 59.5 263.0 – – 44.0 10,046,640 18,058,743 44,569,367 33,203,361 – – – (1,027,790) (55,408) 229,075 28,872,074 – – 133,896,063 20. 21. 22. 23. 24. Depreciation Decommissioning Taxes - Other Than Income Taxes - Based on Income Subtotal 1,825,129 – 382,792.4937 143,393 2,351,315 – – 30.52 102.4 11.2 – – 11,683,411 14,681,797 26,365,208 25. Total Operating Expenses 10,175,423 32.8 333,424,220 26. 27. 28. 29. 30. Average Days Lag in Collection of Revenues Average Days Lag in Payment of Expenses Excess Revenue Lag Average Daily Expense Working Cash - 33 - 45.0 32.8 12.2 27,878 341,292 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Working Cash $ in Thousands Appendix C Working Cash Total CPUC Line Description 1. 2. 3. 4. 5. 6. Operating Cash Requirement Cash Special Deposits Working Funds Prepayments Other Accounts Receivable 7. 8. 9. 10. 11. 12. 13. Less: Employees' Withoulding & Accrued Vacation Long-Term Incentive Plant Workers Compensation and Injuries & Damages Claims User Taxes Edison Smart Connect Adjustment Total Operating Cash Requirement (69,369) – (60,887) (28,043) – (73,311) 14. Lead-Lag Working Cash Requirement 320,506 15. Total Cash Working Capital Requirement 247,194 - 34 - – 386 116 36,801 47,685 A.16-09-001 ALJ/SCR/EW2/jt2 PROPOSED [3-27-19] Internal Review Draft; Subject to ALJ Division Review CONFIDENTIAL; Deliberative Process Privilege DECISION Southern California Edison 2018 GRC Appendix C Rate Base $ in Thousands Appendix C Rate Base Line Description CPUC 1. 2. 3. 4. 5. Fixed Capital Plant in Service Capitalized Software Other Intangibles Total Fixed Capital 6. 7. 8. 9. Adjustments Customer Advances for Construction Customer Deposits Total Adjustments 10. 11. 12. 13. 14. Working Capital Materials & Supplies Mountainview Emissions Credits Working Cash Total Working Capital 15. 16. 17. 18. 19. 20. 21. 22. 23. Deductions for Reserves Accumulated Depreciation Reserve Accumulated Amortization Accumulated Deferred Taxes - Plant Accumulated Deferred Taxes - Capitalized Interest Accumulated Deferred Taxes - CIAC Accumulated Deferred Taxes - Vacation Accrual Unfunded Pension Reserve Total Deductions for Reserves 24. Rate Base Adjustment 25. Rate Base 26. Depreciation & Amortization 37,136,016 1,077,124 213,168 38,426,308 (91,425) (208,711) (300,136) 213,142 4,861 247,194 465,197 (11,446,885) (612,403) (4,028,095) – 121,374 14,407 (86,973) (16,038,575) – 22,552,795 1,571,266 - 35 - Total CPUC 37,136,016 1,077,124 213,168 38,426,308 – (91,425) (208,711) (300,136) – 213,142 4,861 247,194 465,197 – (287,700) (End of Appendix C) Powered by TCPDF (www.tcpdf.org) Rate Base Adjustment (287,700) (11,446,885) (612,403) (4,028,095) – 121,374 14,407 (86,973) (16,038,575) (287,700) 22,265,095 1,571,266