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ALJ/TRP/lil Date of Issuance 8/20/2014 Decision 14-08-032 August 14, 2014 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2014 (U39M).

Application 12-11-009 (Filed November 15, 2012)

And Related Matter.

Investigation 13-03-007

DECISION AUTHORIZING PACIFIC GAS AND ELECTRIC COMPANY’S GENERAL RATE CASE REVENUE REQUIREMENT FOR 2014-2016

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DECISION AUTHORIZING PACIFIC GAS AND ELECTRIC COMPANY’S GENERAL RATE CASE REVENUE REQUIREMENT FOR 2014-2016 .................. 1 Introduction ..................................................................................................................... 2 1. Procedural Background ....................................................................................... 13

1.1. Framework for Preparing this Decision................................................... 16 2. Balancing Safety and Risk Concerns with Just and Reasonable Rates ........ 18

2.1. Role of Cost-Benefit Analysis in Revenue Requirements Determinations ............................................................................................ 26

3. Natural Gas Distribution ..................................................................................... 30 3.1. Introduction ................................................................................................. 30 3.2. Gas System Operations and Distribution Control ................................. 31

3.2.1. System Operations Support .......................................................... 34 3.2.2. Technology Support Personnel .................................................... 34 3.2.3. Contractor Support ......................................................................... 35 3.2.4. Distribution Control Center Capital Expenditures ................... 35

3.3. Gas Distribution Mapping and Records .................................................. 38 3.4. Gas DIMP ..................................................................................................... 43

3.4.1. Leak Survey Enhancements .......................................................... 44 3.4.2. Cross-Bore Sewer Remediation Project ....................................... 46 3.4.3. Program Management ................................................................... 49 3.4.4. Emergent Work ............................................................................... 51 3.4.5. Tee Cap Replacement (MWC JSL) ................................................ 53 3.4.6. Balancing Account Proposal for DIMP ....................................... 55

3.5. Pipe, Meter and Other Preventative Maintenance (MWC DF, FH, DG, EX and GM) .............................................................. 56 3.5.1. Introduction ..................................................................................... 56 3.5.2. Locate and Mark Underground Facilities (MWC DF) .............. 57 3.5.3. Gas Distribution Preventive Maintenance (MWC FH) ............. 59

3.5.3.1. Dedicated Paint Crew and other Projects with no Maintenance Activity Type (MAT) Code .................... 60

3.5.3.2. Atmospheric Corrosion (AC) Monitoring ................... 62 3.5.3.3. Low Pressure Regulator Vent Raising (MAT FHJ) ..... 63

3.5.3.3.1. Gas Meter Protection (MWC 27) ................ 66 3.6. Leak Survey and Repair ............................................................................. 66

3.6.1. Leak Survey and Repair Balancing Account .............................. 79

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3.6.1.1. Corrective Pipeline Maintenance (MWC FI) ............... 80 3.7. Gas Field Services and Response (MWC DD) ........................................ 86

3.7.1. Pilot Relights (MAT DDD) ............................................................ 87 3.7.2. Gas Service Representative (GSR) Scheduling/Dispatching ... 88 3.7.3. Leak Repairs and AC (MWC HY) ................................................ 91 3.7.4. Regulator Replacements (MWC 74) ............................................. 92

3.8. Gas Distribution Capital and Investment Planning ............................... 94 3.8.1. Gas Pipeline Replacement Program (GPRP) .............................. 95 3.8.2. Gas Distribution Reliability (MWC 50) ..................................... 101 3.8.3. Gas Distribution HPR Replacement .......................................... 105 3.8.4. Tools and Equipment (MWC 05) ................................................ 106

3.9. NB and Work at the Request of Others .................................................. 107 3.10. Technical Training and Research and Development ........................... 108 3.11. Gas Operations Information Technology (IT) and

Infrastructure Costs .................................................................................. 110 3.11.1. Path Finder Project ....................................................................... 111 3.11.2. Back-up Radios for Gas Service Representatives ..................... 113 3.11.3. Mobile Platform Technology Solutions ..................................... 114 3.11.4. Mobile Extensions and Enhancements ...................................... 116 3.11.5. Mobile Device Replacement/Upgrade Project ........................ 117

3.12. Building Projects, American Gas Association (AGA) Fees, and Publicly Available Standard (PAS) 55 Certification (MWC AB) ........ 119 3.12.1. Gas Operations Headquarters Building .................................... 120 3.12.2. Gas Control Center ....................................................................... 123 3.12.3. Gas Control Hot Backup Facility ................................................ 126 3.12.4. Gas Training Center ..................................................................... 128 3.12.5. Antioch and San Carlos Service Centers and Vaca

Dixon Yards ................................................................................... 131 3.12.6. Vaca Dixon Yard ........................................................................... 132 3.12.7. Miscellaneous Building Projects Under $1 Million ................. 133

3.12.7.1. Publicly Available Specification (PAS) 55 Certification .................................................... 133

3.12.7.2. AGA Fees ........................................................................ 134 4. Electric Distribution ............................................................................................ 134

4.1. Policy and Introduction ............................................................................ 134

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4.2. Electric Operations Technology .............................................................. 134 4.2.1. Introduction ................................................................................... 134 4.2.2. Electric Distribution Geographic Information

System/Asset Management (GIS/AM) .................................... 135 4.2.3. Workforce Mobilization and Scheduling Projects ................... 139 4.2.4. Data Historian for Electric Distribution .................................... 146 4.2.5. Customer Connection Online (CCO) ......................................... 148 4.2.6. Outage Reporting and Analysis System Replacement ........... 150 4.2.7. Graphic Work Design Tools ........................................................ 151 4.2.8. Advanced Applications for DCC ............................................... 153 4.2.9. SAP Work Management Enhancements ................................... 154

4.3. Applied Technology Services (ATS)....................................................... 155 4.4. Electric Mapping and Records Management (MWC GE) ................... 158 4.5. Electric Distribution Maintenance (EDM) ............................................. 162

4.5.1. Introduction ................................................................................... 162 4.5.2. Overhead Line Maintenance (MWC 2A) and

Underground (MWC 2B) ............................................................. 164 4.5.3. Idle Facilities Removal (MWC 2A and MWC KA) .................. 166 4.5.4. Infrared Inspection and Tags (MWC 2A and MWC KA) ....... 169 4.5.5. Incandescent Streetlight Replacement (MWC 2A) .................. 172 4.5.6. Permit Updates (MWC 2A) ......................................................... 174 4.5.7. Underground Oil Switch Replacements (MWC 2B and

MWC KB) ....................................................................................... 175 4.5.8. SCADA Safety Monitoring (MWC 2C) ...................................... 178 4.5.9. Network Transformer and Protector Replacement

(MWC 2C) ...................................................................................... 179 4.5.10. Network SwivelocTM Manhole Cover Replacement

(MWC 2C) ...................................................................................... 180 4.5.11. Overhead Preventive Maintenance and Equipment Repair

(MWC KA) ..................................................................................... 181 4.5.12. Streetlight Burnouts and Group Replacements (MWC KA) .. 182 4.5.13. Insulator Washing ........................................................................ 186

4.6. Pole Test, Treat, Restoration and Joint Utilities Coordination ........... 186 4.7. Pole Replacements .................................................................................... 191 4.8. Vegetation Management .......................................................................... 198

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4.8.1. Routine Tree Work ....................................................................... 199 4.8.2. Fire Risk Reduction ...................................................................... 200 4.8.3. Environmental Compliance ........................................................ 201 4.8.4. Balancing Account and Tracking Account ............................... 203

4.9. New Business and Work at the Request of Others .............................. 203 4.9.1. Processing New Customer Connections (MWC EV) .............. 203 4.9.2. Electric Distribution Work Requested by Others

(MWC 10) ....................................................................................... 205 4.9.3. Electric Distribution Customer Connections (MWC 16)......... 207

4.10. Electric Emergency Recovery .................................................................. 209 4.10.1. Electric Emergency Recovery Balancing Account ................... 211

4.11. Distribution System Operations .............................................................. 213 4.12. Electric Distribution Lines and Equipment Capacity .......................... 218

4.12.1.1. Overloaded Transformers ............................................ 220 4.12.1.1.1. Mainline Loop Program ............................ 221

4.13. Substation Asset Strategy (SAS) .............................................................. 222 4.13.1. SAS Expense Forecast .................................................................. 222 4.13.2. SAS Capital Expenditures ........................................................... 224

4.14. Electric Engineering – Distribution Planning, Operations and Power Quality ............................................................................................ 225

4.15. Electric Distribution Reliability ............................................................... 228 4.15.1. Overhead Conductor Replacement ............................................ 229 4.15.2. Line Reclosers(MWC 08) ............................................................. 231 4.15.3. Distribution Circuit/Zone Reliability–FLISR Installations

(MWC 49) ....................................................................................... 231 4.16. Underground Asset Management .......................................................... 236

4.16.1. Network Cable Replacement ...................................................... 236 4.16.2. TGRAM/TGRAL Switch Replacement ..................................... 238 4.16.3. Tie Cable and COE Cable Replacement .................................... 240

4.17. Distribution Automation and System Protection ................................. 243 4.18. Rule 20A Conversions of Overhead Lines ............................................. 249 4.19. Streetlight Program ................................................................................... 251

4.19.1. Rate Design .................................................................................... 256 4.20. Electric Distribution Support Activities ................................................. 257

4.20.1. Technical Training Curriculum (MWC DN) ............................ 257

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4.20.2. Electric Distribution Productivity Offset (MWC AB and MWC 05) ............................................................. 259

4.20.3. Edison Electric Institute Dues (MWC AB) ................................ 261 4.20.4. Electric Operations Focused on Real Estate Projects

(MWC 78) ....................................................................................... 263 5. Customer Care ..................................................................................................... 265

5.1. Introduction ............................................................................................... 265 5.2. Customer Inquiry Assistance (MWC DK) ............................................. 265

5.2.1. Training for CSRs .......................................................................... 266 5.2.2. Improvement in Average Speed of Answer (ASA) Time ....... 268 5.2.3. Expansion of Customer Contact Centers .................................. 271 5.2.4. CSR Supervision and Support .................................................... 272 5.2.5. Staff Additions to the Customer Advocacy Team (CAT) ....... 274 5.2.6. Average Handle Time (AHT) Increase ...................................... 276 5.2.7. Repeat Call Reduction Savings ................................................... 277

5.3. Office Services ............................................................................................ 278 5.3.1. CSR Local Office Staffing ............................................................. 278 5.3.2. Local Office Facilities Improvements ........................................ 280 5.3.3. Compliance Auditor ..................................................................... 283

5.4. Meter to Cash ............................................................................................. 284 5.4.1. Introduction ................................................................................... 284

5.4.1.1. Uncontested Proposals ................................................. 285 5.4.2. Hourly Interval Energy Usage Data Processing ...................... 286 5.4.3. Relocation of Departments to New Facility .............................. 289 5.4.4. Uncollectibles Mechanism ........................................................... 290 5.4.5. Customer Payment Channels ..................................................... 292 5.4.6. Quality Assurance Staffing ......................................................... 293 5.4.7. Revenue Assurance Staffing ....................................................... 294 5.4.8. Energy Data Services (EDS) Meter Reading ............................. 295 5.4.9. Credit Notice Savings................................................................... 298 5.4.10. Net Energy Meter Billing ............................................................. 298 5.4.11. Streetlight Inventory Project ....................................................... 299 5.4.12. SmartMeter™ Opt-Out Processing ............................................ 300 5.4.13. SmartMeter™ Opt-Out Field Collection ................................... 301 5.4.14. Risk Analysis Software (MWC IT) ............................................. 302

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5.5. Metering ...................................................................................................... 303 5.5.1. SMOOP Meter Reading ............................................................... 304

5.5.1.1. Balancing Account Proposals ...................................... 305 5.5.1.2. Forecast Number of Opt-Out Customers .................. 306 5.5.1.3. Meter Read Unit Cost Per Premise ............................. 307

5.5.2. Non-Opt-Out Meter Reading ...................................................... 309 5.5.3. SmartMeter™ Maintenance Expense ......................................... 312 5.5.4. Routine Electric Meter Testing ................................................... 313 5.5.5. Field Meter Operations (FMO) ................................................... 314 5.5.6. MAME ............................................................................................ 315 5.5.7. Gas and Electric Meter Services (GEMS)................................... 316 5.5.8. Installation of New Electric and Gas Meters ............................ 317 5.5.9. Escalation ....................................................................................... 319

5.6. QAP/Safety Net Program ........................................................................ 320 5.7.1. Provide Account Services (MWC IV) ........................................ 321 5.7.2. CCA Support ................................................................................. 323 5.7.3. Retain and Grow Customers (MWC FK) .................................. 323 5.7.4. Manage Customer Care Processes (MWC EZ) ......................... 325

5.7.4.1. Electric and Gas Safety and Reliability Outreach ..... 326 5.7.4.2. Rcustomer Rate Education and Outreach .................. 327

5.7.5. Customer Insight and Strategy (CI&S) ...................................... 328 5.7.6. Pricing Products/Policy and Integrated Planning (PIP) ........ 329

5.8. Customer Retention Expenses (MWC FK) ............................................ 330 5.9. Customer Care IT Program ...................................................................... 332

5.9.1. Customer Interaction and Relationship (CIRM) ...................... 334 5.9.2. Interval Data Processing and Exceptions Management

(IDPEM).......................................................................................... 335 5.9.3. Meter Management Project ......................................................... 337 5.9.4. Customer Self Service and Energy Management

Enhancements Project (Customer Self-Service) ....................... 338 5.9.5. Miscellaneous Other Technology Projects ................................ 338

5.10. SmartMeterTM Program ............................................................................ 339 5.11. Accessibility Improvements .................................................................... 340

6. Energy Supply ..................................................................................................... 340 6.1. Introduction ............................................................................................... 340

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6.2. Hydroelectric Generation ......................................................................... 341 6.2.1. Hydro Expense Overview ........................................................... 341

6.2.1.1. DRA’s Position ............................................................... 343 6.2.1.2. TURN’s Position ............................................................ 344 6.2.1.3. MWC AB Land Conservation Commitment (LCC)

Support ............................................................................ 347 6.2.1.4. MWC AX (Maintain Hydro Reservoirs, Dams and

Waterways) ..................................................................... 348 6.2.1.5. MWC KG (Operate Hydro Generation)/MWC KJ

(License Compliance Hydro Generation) .................. 350 6.2.1.6. MWC KI (Maintain Hydro Structures, Roadways

and Infrastructure) ........................................................ 355 6.2.1.7. MWC JV (Maintain IT Applications and

Infrastructure) ................................................................ 356 6.2.2. Hydro Capital Expenditures Overview .................................... 358

6.2.2.1. DRA’s Postion ................................................................ 359 6.2.2.2. TURN’s Postion ............................................................. 360 6.2.2.3. MWC 2F (Building Information Technology

Applications and Infrastructure)................................. 365 6.2.2.4. MWC 2L (Install/Replace for Hydro Safety and

Regulator Requirements) ............................................. 366 6.2.2.5. TURN’s Proposed Reductions Relating to Three

Capital Spending Projects ............................................ 367 6.2.2.5.1. Crane Valley Dam Rebuild ....................... 368 6.2.2.5.1.1. Lake Nora Walkway ............................... 369 6.2.2.5.2. Helms Upgraded Cooling Water

System .......................................................... 370 6.2.2.6. MWC 2M/2N/2P (Install/Replace Hydro

Generating Equipment/Reservoirs, Dams and Waterways/Hydro Structure, Roadways and Infrastructure) ................................................................ 371

6.2.2.7. MWC 11 (Hydro Licensing and License Conditions) ..................................................................... 376

6.2.2.8. MWC 12 (Implement Environmental Projects) ......... 378 6.2.3. FERC Hydro Licensing Balancing Account .............................. 379

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6.3. Nuclear Operations ................................................................................... 380 6.3.1. Nuclear Operations Expense Overview .................................... 381

6.3.1.1. Nuclear Refueling Outage Costs (MWC AB) ............ 383 6.3.1.2. MWC AK - Manage Environmental Operations ...... 389 6.3.1.3. MWC BP - Manage DCPP Business ............................ 389 6.3.1.4. MWC BQ - DCPP Support Services/

Loss Prevention .............................................................. 391 6.3.1.5. DCPP Operating Expense (MWC BR) ........................ 393 6.3.1.6. Overtime Issues ............................................................. 397 6.3.1.7. Escalation Issues ............................................................ 398 6.3.1.8. DCPP Plant Asset Maintenance Expense

(MWC BS) ....................................................................... 399 6.3.1.9. DCPP Personnel Performance Enhancement

(MWC BT) ....................................................................... 402 6.3.1.10. Maintain DCPP Plant Configuration

(MWC BV) ...................................................................... 403 6.3.1.11. Maintain IT Applications and Infrastructure

(MWC JV)........................................................................ 404 6.3.1.12. Obsolete inventory Write-off ....................................... 405 6.3.1.13. NRC Regulatory and Inspection Fees .......................... 407 6.3.1.14. Alliance for Nuclear Responsibility (A4NR) ............. 408

6.3.1.14.1. Proposed Disallowance of SSHAC Costs ............................................................. 409

6.3.1.14.2. Transfer of Seismic Plan Costs out of the GRC ....................................................... 410

6.3.1.14.3. Additional Layer of Review of SSHAC Process ........................................... 412

6.3.1.14.4. Conditions Related to the Rate of Spent Fuel Storage Into Dry Casks ..................... 412

6.3.2. Nuclear Department Capital Costs ............................................ 413 6.3.2.1. Nuclear Operations IT Projects (MWC 2F) ................... 414 6.3.2.2. Transformer Supercooler Replacement ...................... 415 6.3.2.3. Diablo Canyon Access Road .......................................... 417

6.3.3. Nuclear Regulatory Balancing Account .................................... 419 6.4. Fossil and Other Generation Operations ............................................... 420

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6.4.1. Fossil and Other Generation Expense Overview ..................... 420 6.4.1.1. Operate Fossil Generation (MWC KK) ....................... 421 6.4.1.2. Maintain Fossil Generating Equipment

(MWC KL) ...................................................................... 423 6.4.1.3. MWC KM – Maintain Fossil Buildings, Grounds,

& Infrastructure ............................................................. 425 6.4.1.4. MWC KQ – Operate Alternative Generation/

MWC KS – Maintain Alternative Generation Buildings, Grounds and Infrastructure ...................... 426

6.4.2. Fossil and Other Generation Capital Expenditures ................. 427 6.4.3. Decommissioning and Fuel Oil Inventory Costs ..................... 428 6.4.4. Fuel Cell Project Costs Above Authorized Amounts in

D.10-04-028..................................................................................... 428 6.5. Energy Procurement (EP) Administration Costs ................................. 428

6.5.1. Energy Procurement Expense ..................................................... 429 6.5.1.1. MWC CT (Acquire and Manage Electric Supply) ....... 429 6.5.1.2. MWC CV (Gas Procurement) ...................................... 432 6.5.1.3. MWC JV (Maintain IT Applications and

Infrastructure) ................................................................ 433 6.5.2. Energy Procurement Capital ....................................................... 434

6.5.2.1. Build IT Applications and Infrastructure (MWC 2F)........................................................................ 434

6.6. Energy Supply Ratemaking ..................................................................... 435 6.6.1. Treatment of Department of Energy Litigation Proceeds ...... 435

7. Shared Services and IT ....................................................................................... 437 7.1. Introduction ............................................................................................... 437 7.2. Safety Department .................................................................................... 439

7.2.1. Safety, Engineering, and Occupational Safety and Health Administration Compliance (MWC FL) .................................... 439

7.2.2. Applications and Infrastructure Maintenance (MWC JV and 2F) .......................................................................... 442

7.3. Transportation Services ............................................................................ 443 7.3.1. Transportation Services Fuel Expense ....................................... 444 7.3.2. MWC JV: Risk Management Improvements ........................... 446 7.3.3. TS Capital Expenditures .............................................................. 447

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7.3.3.1. Fleet Auto Equipment (MWC 04) ............................... 448 7.3.3.2. MWC 05 – Capital Tools and Equipment .................. 451 7.3.3.3. MWC 28 – PEV Charging Infrastructure ................... 452 7.3.3.4. MWC 2F – Build IT Applications and

Infrastructure ................................................................. 453 7.4. Supply Chain ............................................................................................. 454

7.4.1. Materials and Logistics and Planning ....................................... 454 7.4.2. Materials and Supplies Inventory .............................................. 456

7.5. Supply Chain – Sourcing Operations ..................................................... 457 7.5.1. Diversity and Sustainability Programs (MWC JL) .................. 458 7.5.2. Upgrade to SRM Purchasing System (MWC JV) ..................... 459 7.5.3. Supply Chain Sourcing Capital Expenditures ......................... 462

7.6. Corporate Real Estate ............................................................................... 463 7.6.1. Real Estate Forecast Overview ................................................... 463 7.6.2. Methodology Supporting Real Estate Forecasts

(MWC 22, 23, JH, BI) .................................................................... 464 7.6.2.1. Overhead Cost Adders ................................................. 465 7.6.2.2. Construction Unit Costs ............................................... 466 7.6.2.3. Discussion ....................................................................... 470

7.6.3. Base Building and Seismic Safety Programs (MWC BI and 22) .......................................................................... 472

7.6.4. Real Estate Planning and Transactions/Real Estate Solutions Programs (MWCs JH and 23) .................................... 476

7.6.5. MWC JV – IT Applications and Infrastructure ........................ 483 7.7. Environmental Program ........................................................................... 485

7.7.1. Environmental Program Expenses ............................................. 485 7.7.1.1. MWC JE: Land Stewardship Management

Program........................................................................... 486 7.7.1.2. MWC JV: Environmental Health and Safety

(EHS) Compliance Management ................................. 487 7.7.2. Environmental Program Capital Expenditures ....................... 489

7.7.2.1. MWC 12: Environmental Capital ............................... 489 7.8. Enterprise-Wide IT Costs ......................................................................... 491

7.8.1. Baseline Portfolio .......................................................................... 492 7.8.2. Technology Reliability Portfolio ................................................. 494

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7.8.2.1. Lifecycle Initiatives ........................................................ 494 7.8.2.2. Disaster Recovery .......................................................... 495 7.8.2.3. Telecommunications Network Enhancement ........... 498 7.8.2.4. Identity and Access Management ............................... 500 7.8.2.5. Records Management Archival ................................... 501 7.8.2.6. Service Management ..................................................... 502 7.8.2.7. Forecasting Methodologies Based on PG&E’s

Concept Cost Estimating Tool ..................................... 504 8. Human Resources (HR) ..................................................................................... 510

8.1. Introduction ............................................................................................... 510 8.2. Workforce Diversity and Inclusion ........................................................ 511 8.3. Employee Compensation ......................................................................... 511

8.3.1. Total Compensation Study (TCS) ............................................... 511 8.3.2. Short-Term Incentive Plan (STIP) ............................................... 516 8.3.3. R&R ................................................................................................. 524 8.3.4. Labor Escalation (including Attrition) ....................................... 525 8.3.5. Employee Health Plans (including Escalation) ........................ 527

8.3.5.1. Health Plan Escalation Rates ....................................... 529 8.3.5.2. Non-Contested Health and Insurance Items ............. 531

8.3.6. Post-Retirement Employee Benefits ........................................... 531 8.3.7. Disability Trust Contributions .................................................... 531 8.3.8. 401(k) Funding .............................................................................. 531 8.3.9. Supplemental Executive Retirement Plan ................................. 532 8.3.10. Service Awards ............................................................................. 535 8.3.11. Tuition Support Payments and Relocation Costs .................... 537

8.4. Workers’ Compensation ........................................................................... 538 8.5. Workforce Management Program .......................................................... 538

9. A&G Expenses ..................................................................................................... 539 9.1. Introduction ............................................................................................... 539 9.2. Finance Organization Costs ..................................................................... 540

9.2.1. Finance Department A&G Costs ................................................ 540 9.2.2. Company-Wide A&G Costs ........................................................ 541 9.2.3. IT Projects ....................................................................................... 542

9.3. Risk and Audit Department Costs and Insurance Expenses .............. 542 9.3.1. Department Cost Expense ........................................................... 542

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9.3.1.1. VP Risk Officer ............................................................... 543 9.3.1.2. ERM ................................................................................. 543 9.3.1.3. Corporate Security......................................................... 544 9.3.1.4. ACHQ .............................................................................. 546

9.3.2. Insurance ........................................................................................ 547 9.3.2.1. Corporation Property and Liability Insurance ......... 547 9.3.2.2. Non-Nuclear Property Insurance ................................ 548 9.3.2.3. Excess Liability Insurance ............................................ 549 9.3.2.4. D&O Liability Insurance .............................................. 551

9.3.3. AEOC .............................................................................................. 552 9.3.4. IT Projects for the Risk and Audit Department ....................... 555

9.4. HR Department and HR Technology Costs .......................................... 555 9.4.1. HR Department Costs .................................................................. 555

9.4.1.1. HR Delivery .................................................................... 556 9.4.1.2. PG&E Academy ............................................................. 556 9.4.1.3. Talent Management ...................................................... 558

9.4.2. HR Department IT Projects ......................................................... 559 9.5. Regulation and Rates Department .......................................................... 562

9.5.1. A&G Salary Increases (Account 920) ......................................... 563 9.5.2. State Agency Relations Department .......................................... 565 9.5.3. CCEEB ............................................................................................ 566 9.5.4. Regulation and Rates IT Projects ................................................ 566 9.5.5. Allocation of FERC and ISO Relations Department Costs ..... 569

9.6. Law Department and Related Costs ....................................................... 570 9.6.1. Department Cost Expense ........................................................... 570 9.6.2. Settlements, Judgments, and Claims ......................................... 570 9.6.3. Law Department IT Projects ....................................................... 572

9.7. PG&E Corporation and Executive Offices; Corporate Secretary Dept. Costs ................................................................................ 573 9.7.1. Department Cost Expense ........................................................... 573 9.7.2. Director Fees and Expenses ......................................................... 574

9.8. Corporate Affairs – Communications Department Costs ................... 575 9.8.1. Department Cost Expense ........................................................... 575 9.8.2. IT Project Expense and Capital – Digital Channel

Optimization Project .................................................................... 577

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9.9. Corporate Affairs – External Department Costs .................................. 578 9.10. UCC and Allocation Issues ...................................................................... 578 9.11. Miscellaneous Promotional Items ........................................................... 580

10. Results of Operations (RO) ................................................................................ 581 10.1. Treatment of Tax Deductions .................................................................. 582

10.1.1. Tax Deductions for Employee Stock Option Plans .................. 582 10.1.2. Meals and Entertainment Deductions ....................................... 585 10.1.3. Recognitions of Bonus Depreciation Rate Changes ................ 587

10.2. Depreciation Expense and Reserve ........................................................ 588 10.2.1. Overview ........................................................................................ 588 10.2.2. Uncontested Depreciation Parameters ...................................... 590 10.2.3. Removal Cost/Negative Net Salvage ........................................ 591 10.2.4. ASL Estimates ................................................................................ 602

10.3. Other Operating Revenue ........................................................................ 605 10.3.1. Reimbursed Revenues .................................................................. 606 10.3.2. Timber Sales................................................................................... 607 10.3.3. Water Sales ..................................................................................... 608

10.4. Escalation Rates ......................................................................................... 609 11. Rate Base, Working Cash and Finance Issues................................................. 611

11.1. Allowance for Funds Used During Construction ................................ 611 11.2. Inclusion of Nuclear Fuel Costs in Rate Base ........................................ 617 11.3. Customer Deposits .................................................................................... 624 11.4. Miscellaneous Working Cash Issues ...................................................... 630

11.4.1. Lag Days for Income Tax Payments and Revenue Collection ....................................................................................... 631

11.4.2. Goods and Service Lag Days ...................................................... 634 11.4.3. Deferred Debits ............................................................................. 636 11.4.4. Accrued Vacation .......................................................................... 637 11.4.5. Prepaid Expenses .......................................................................... 639 11.4.6. Adjustments to Other Receivables ............................................. 641

11.5. Fuel Oil Inventory Carrying Costs ......................................................... 643 11.6. Financial Health ......................................................................................... 644

12. Attrition Adjustment Mechanism .................................................................... 646 12.1. Overview .................................................................................................... 646 12.2. DRA’s ARA Proposal................................................................................ 648

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TABLE OF CONTENTS (Cont’d)

Title Page

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12.3. TURN’s Proposed ARA ............................................................................ 649 12.3.1. Wage Escalation ............................................................................ 653 12.3.2. Health Plan Escalation ................................................................. 654 12.3.3. Materials and Services ................................................................. 655 12.3.4. Capital Attrition Increases ........................................................... 656 12.3.5. Z-Factor Adjustments .................................................................. 661 12.3.6. Other Miscellaneous Attrition Adjustments ............................ 663

13. Settlements and Joint Proposals........................................................................ 664 13.1. Joint Proposal on Accessibility Issues .................................................... 665 13.2. Settlement on Customer Outreach for Communities of Color

and Related Initiatives .............................................................................. 667 13.3. Small Business Utility Advocates Settlement ....................................... 669 13.4. Joint Proposal on DOE Litigation Refund Treatment .......................... 670 13.5. Settlement Regarding Allocation Methodology for Public

Purpose Program Labor ........................................................................... 670 14. Assignment of Proceeding ................................................................................. 670 15. Comments on the Proposed Decision .............................................................. 670 Findings of Fact ........................................................................................................... 671 Conclusions of Law ..................................................................................................... 724 ORDER .......................................................................................................................... 731

Appendix A – Service List Appendix B – List of Acronyms Appendix C – Results of Operations Tables Appendix D – Attrition Tables Appendix E – Disposition of Net Salvage and Average Service Life Parameters Appendix F – Approved Settlements and Joint Proposals

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DECISION AUTHORIZING PACIFIC GAS AND ELECTRIC COMPANY’S GENERAL RATE CASE REVENUE REQUIREMENT FOR 2014-2016

Introduction

This decision approves test year revenue requirements increases of

$460 million, (for a 6.9% increase) for Pacific Gas and Electric Company (PG&E)

pursuant to its 2014 General Rate Case (GRC) Application 12-11-009 and

Investigation 13-03-007, as summarized in Appendix C, Table 1. The adopted

2014 revenue requirements shall become effective upon filing of tariffs pursuant

to the directives of this decision.1 The adopted revenue requirement reflects our

careful assessment of PG&E’s 2014 test year base revenue requirements

necessary to provide safe and reliable service. Appendix C of this decision

contains the results of operations supporting tables for PG&E, which

incorporates the forecasted costs we find to be reasonable, and which are

adopted in today’s decision.

This decision also authorizes attrition rate adjustments of 4.57% for 2015

and 5% for 2016 as set forth in Appendix D to provide funds necessary for PG&E

to continue to provide safe and reliable service to customers beyond the test year,

1 Decision (D.) 13-04-023 granted PG&E’s unopposed motion, filed February 15, 2013, seeking an order to make its 2014 test year GRC revenue requirement effective as of January 1, 2014, even in the event the Commission issues a final decision after that date. D.13-04-023 also granted PG&E’s request to allow for the recovery of interest, based on a Federal Reserve three-month commercial paper rate, (see Federal Reserve three-month Commercial Paper Rate – Non-Financing, from the Federal Reserve Statistical Release H.15 or its successor. http://www.federalreserve.gov/releases/H15/data.html.), to the extent necessary to keep PG&E and its ratepayers relatively indifferent to the timing of the Commission’s final decision regarding the 2014 GRC revenue requirement.

http://www.federalreserve.gov/releases/H15/data.html

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while offering a reasonable opportunity to earn the rate of return previously

found reasonable by the Commission.

PG&E’s final updated request for its total 2014 forecasted revenue

requirement increase is $1.160 billion, representing a 17.5% increase, and

requested attrition year increases of $436 million and $486 million for 2015 and

2016, respectively.

PG&E requested test year 2014 revenue increases of $514 million in Electric

Distribution, $446 million in Gas Distribution, and $199 million in Electric

Generation for the test year. PG&E claims these significant increases in revenue

requirements are needed for:

- delivering energy safely to customers, maintaining reliability, and providing responsive customer service;

- capital investments to replace aging infrastructure;

- increased capacity to meet customer growth;

- depreciation associated with plant investments; and

- complying with governmental regulations and orders to address nuclear operations, hydroelectric relicensing, and potential risks to public safety applicable to electric and gas systems and facilities.

The authorized increase in revenue requirement reflects the costs forecast

for test year 2014 for delivering electricity to PG&E’s customers, and for

operating and maintaining PG&E’s gas distribution and electric distribution and

generation utility infrastructure. 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, which are addressed in a separate

proceeding. The gas department revenue requirement authorized in this

decision does not include the commodity cost of gas procured to serve gas

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customers or gas transmission and storage, which are addressed in separate

proceedings.

PG&E’s revenue requirement estimates are classified by the Federal

Energy Regulatory Commission (FERC) Uniform System of Accounts,

augmented by Major Work Category (MWC), which PG&E uses for operational

planning, budgeting and managing purposes. Consistent with prior GRCs, costs

have been separated into Unbundled Cost Categories and aggregated into

functional areas by MWC or FERC account. The adopted revenue requirements

are presented in Appendix C in “Results of Operations” format.

PG&E’s GRC forecast utilizes 2011 as the recorded base year for

developing 2014 expense forecasts. PG&E’s 2014 rate base forecast utilizes

recorded year-end 2011 as a starting point, and adds forecasted annual capital

expenditures for 2012-2014 to arrive at a rate base forecast for test year 2014. As

a result, our adopted 2014 rate base incorporates forecasts for cumulative capital

expenditures each year from 2012 through 2014 for each respective cost category.

Although PG&E also presents forecasts of capital expenditures for 2015 and 2016,

no other party had the resources to undertake a comprehensive scrutiny of 2015

and 2016 capital forecasts. Accordingly, while we make limited findings in this

decision that relate, in some instances, to 2015 and 2016 activities, without the

benefit of a robust review from other parties, we have insufficient evidentiary

basis to make comprehensive findings as to the overall reasonableness of PG&E’s

2015 and 2016 capital forecasts. We instead adopt a simplified methodology for

an attrition revenue requirement for 2015 and 2016, as set forth in Appendix D,

as described in Section 12 of this decision. Our adopted 2014 revenue

requirements in comparison to PG&E’s requested amounts are as follows:

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2014 Revenue Requirements: PG&E Requested Versus Commission Adopted $ in Millions

Authorized Revenues at Existing Rates

PG&E Proposed Increase

Adopted $ Increase

Adopted % Increase

Electric Distribution

$3.650 $ 514 $125 3.4%

Gas Distribution $1.295 $ 446 $264 20.4% Electric Generation $1.689 $ 199 $ 71 4.2% Total GRC $6.634 $1,160 $460 6.9%

PG&E asks the Commission to adopt the total and rate component changes

necessary to implement the change in revenue requirements resulting from this

proceeding. We authorize PG&E to implement rate changes based on the

adopted Results of Operations Revenue Requirements set forth in Appendix C

which shall be consolidated with rate changes implemented in PG&E’s Annual

Gas and Electric True-Up filing scheduled to be effective as directed herein.

As the basis for the revenue requirements increases that we adopt herein,

we make the following major findings regarding PG&E’s proposals:

Gas Distribution

Our adopted gas distribution funding includes:

Support for a Gas Distribution Control Center to provide real-time visibility and remote control of dynamic gas pressure and flows within the system.

Mapping and Records project funding to collect, transport, standardize and electronically archive as-built and gas service paper records.

Distribution Integrity Management Program funding to enhance safety mitigating risk factors such as corrosion, natural forces, excavation damage, material, weld, or joint failure, or equipment failure.

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Pipe, Meter, and other Preventive Maintenance funding to forestall equipment degradation and failure and to promote a safer system.

Funding to meet a superior standard of safety in detection and repair of gas distribution pipeline hazardous leaks, using various enhanced techniques. It is PG&E’s responsibility to determine the frequency of routine leak surveys. PG&E must evaluate the optimal phase-in of all enhanced measures to reduce hazardous leaks.

A two-way balancing account is adopted for leak-survey, leak repair, meter set leak repair atmospheric corrosion inspections and tee cap repair to adjust the recoverable costs to the extent the actual scope of work differs from the forecast up to a prescribed cap.

Funding for natural gas vehicles, capacity reliability, leak replacement emergency response, and high pressure regulator replacement.

Funding to accelerate the rate of replacement of aging distribution pipeline, focused on pipe materials with the highest leak rate. Adopted funding redirects more money to plastic pipe replacement, and results in a slightly higher total mileage rate of replacement compared to PG&E’s forecast.

Increasing staffing of gas service representatives, to more quickly respond to gas odor calls and other emergency calls.

Electric Distribution

Adopted Electric Distribution Funding includes the following provisions:

Funding for the Electric Distribution Geographic Information System/Asset Management (GIS/AM) project to validate, enhance, and convert legacy mapping and asset connectivity data to a single GIS.

Mapping and Records Management initiatives for: (1) Records Quality Assurance; (2) Field Asset Inventory;

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(3) Conversion of Paper Records to Electronic Format; and (4) Electronic Records Update.

Inspection, testing, repair and replacement of electric distribution facilities, and new initiatives to proactively replace aging assets that pose safety and/or reliability risks. Requested funding is reduced for idle facilities removal.

Increasing resources to reduce electric outages and mitigate wildfire risk, with focus on vegetation management, wildfire patrols, and modification of recloser controls in high-risk fire areas.

Upgrading PG&E’s weather prediction model to better prepare for storms and expanding use of SmartMeter™ data to restore services sooner to customers affected by outages.

Expanding use of Supervisory Control and Data Acquisition equipment to monitor, control, and remotely shut off electricity during emergencies.

Funding for accelerated pole inspections to complete a 10-year inspection cycle on schedule. For ratemaking purposes, however, the portion of pole inspections that constitute deferred maintenance will be paid out of shareholder earnings.

Funding to complete the replacement of poles previously scheduled for replacement in prior years. A reduction is adopted, however, to assign a share of responsibility to PG&E shareholders, rather than ratepayers, for pole replacement deferrals previously funded by ratepayers.

A two-way balancing account is adopted to cover the costs of responding to major emergencies and catastrophic events, where such costs cannot be recovered through the Catastrophic Event Memorandum Account mechanism.

The one-way Vegetation Management Balancing Account and Incremental Inspection and Removal Cost Tracking Account are continued.

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The Electric Tariff Rule 20A work credit allocation amount of $41.3 million that was adopted in the 2011 GRC decision is continued through 2016.

PG&E’s proposed rate design for LED street lights is adopted.

Customer Care

Adopted Customer Care funding includes:

A new methodology is adopted for setting PG&E’s uncollectible factor based on elements of PG&E’s and The Utility Reform Network’s (TURN) proposals.

PG&E’s proposed changes to customer fees (i.e., the non-sufficient funds fee and reconnection fees) are adopted.

PG&E is authorized to close its Service Disconnection Memorandum Account and recover costs through the annual true up rate processes.

Ongoing cost recovery of capital-related revenue requirement associated with the SmartMeter™ program up to the authorized cost cap is consolidated with the 2014 GRC revenue requirement.

The electric and gas SmartMeter™ Balancing Accounts are closed, including elimination of the SmartMeter™ Benefits Realization Mechanism, and the electric and gas Meter Reading Cost Balancing Accounts.

The SmartMeter™ program reporting requirements are concluded.

Cost-recovery of the capital-related revenue requirement associated with the SmartMeter™ Opt-Out Program is consolidated with the 2014 GRC revenue requirement.

Energy Supply

Adopted Energy Supply Funding includes:

Funding for hydroelectric operations to maintain reliability and support aging infrastructure. Funding includes

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relicensing costs, new licensing conditions, and dam safety modifications to achieve more stringent safety guidelines from the FERC and Division of Safety of Dams.

TURN’s proposed reduction to remove ratepayer funding for certain lower priority hydro projects is adopted.

Increasing the use of automation and employing efficiencies to improve use of the existing water supply is approved.

Investment in facilities to address the risks to public safety is approved.

Diablo Canyon Power Plant Funding includes performing a dual refueling scheduled for 2014, investing in projects intended to minimize extended shutdowns, and implementing cybersecurity precautions.

Capital expenditures are authorized for the fuel cell project approved in Decision 10-04-028.

PG&E’s updated forecasts for fossil decommissioning of existing and retired power plants are approved.

PG&E’s forecast 2014 weighted average fuel oil inventory is approved.

Two-way balancing accounts are approved for managing the capital and expense forecasts associated with new FERC Hydro licensing implementation and for nuclear energy safety and security related rulemakings and orders.

PG&E’s proposal is approved to credit back to customers the savings associated with the first three years of its photovoltaic generation program.

The joint recommendation of PG&E, TURN and Marin Energy Authority is approved to credit back to customers funds received from the successful litigation with the Department of Energy.

Shared Services

Adopted Shared Services Funding includes provisions for:

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Funding for additional safety professionals to support field operations, and implement Information Technology (IT) solutions to improve safety work management.

Funding for vehicle fleet replacements; real estate improvements to maintain aging infrastructure and seismically upgrade buildings to ensure reliability of buildings that house critical business operations, but with reductions in PG&E’s forecasts to reflect lower cost assumptions in certain cases.

A significant upgrade to PG&E’s primary procurement system; as well as funding for major Information Technology initiatives, but subject to a 14% reduction for IT forecasts prepared using the Concept Cost Estimating Tool, as proposed by the Division of Ratepayer Advocates (DRA).

Human Resources

Adopted funding for Human Resources includes:

Funding for PG&E’s Short-Term Incentive Plan (STIP) for eligible non-officer employees is approved subject to exclusion of funding for the metrics for Customer Satisfaction and Earnings from Operations (EFO), and further applying a 10% reduction to reflect a sharing of costs and benefits between ratepayers and shareholders.

Funding for employee health plan and post-retirement benefits are approved.

Funding is approved for PG&E’s Rewards and Recognition Program.

DRA’s recommendations as to the treatment of Long-Term Incentive Plan and Paid Time Off in future total compensation studies are denied.

The Greenlining Institute’s recommendation regarding cultural sensitivity training is denied.

Administrative and General (A&G)

Funding for A&G Department costs including:

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A 50/50 sharing between ratepayers and shareholders of the costs of Directors’ and Officers’ liability insurance.

A reduction in PG&E’s forecast for the PG&E Academy and Talent Management programs.

Denial of increased ratepayer funding for additional

regulatory department personnel.

Denial of ratepayer funding for PG&E’s Currents website

and Next 100 blog.

Results of Operations

The Results of Operations include the following major provisions:

Only bonus depreciation enacted by the date provided for update filings is incorporated in test year revenue requirements.

PG&E’s forecast of Other Operating Revenue is increased to reflect increased timber sales revenue and increased water sales.

PG&E’s forecasts for depreciation parameters for uncontested asset accounts are adopted.

For deprecation parameters for contested asset accounts, PG&E’s forecasts for average service lives and survivor curves are adopted.

For depreciation parameters for contested asset accounts, cost to cover negative net salvage rates are increased over current rates but at a reduced level relative to PG&E’s forecasts to mitigate ratepayer impacts and to reflect the principle of gradualism.

Rate Base, Working Cash and Finance Issues

The existing ratemaking policy of excluding nuclear fuel inventory from rate base is continued, subject to further review and possible revision in PG&E’s next cost of capital proceeding.

The revenue requirements for customer deposits are reduced by imputing financing costs based on short-term interest rates.

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PG&E computations for working cash are approved.

Settlement and Joint Proposals

We adopt the settlements and joint proposals as described in Section 13,

and as set forth in Appendix E of this decision.

The authorizations adopted in this decision are made pursuant to

applicable statutory divisions of the Public Utilities Code, Commission Standard

Practices, the Commission’s Rules of Practice and Procedure, and prior decisions,

orders, and resolutions of the Commission.

Requirements for the 2017 General Rate Case

We also approve the following uncontested proposals that PG&E has

presented to improve its showing on safety and risk in its next GRC filing for test

year 2017 (2017 GRC):

PG&E will provide additional testimony on its integrated planning process; affirmatively showing that risk management through integrated planning forms the foundation of the system safety and compliance projects and programs forecast in its 2017 GRC.

PG&E will prioritize projects and programs in the 2017 GRC by using risk-based criteria and will demonstrate how the projects and programs it is forecasting mitigate the system safety risks listed on PG&E’s risk registers.

PG&E will provide enhanced testimony on its overall risk program from its Chief Risk Officer as well as Line of Business-specific risk testimony from the risk or asset management leads from Electric Operations, Energy Supply and Gas Operations.

PG&E will use the proposed reporting procedures it has used throughout this GRC cycle to account for its spending by MWC, comparing authorized amounts to budgeted and spent amounts, and explaining significant differences.

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1. Procedural Background

Pacific Gas and Electric Company (PG&E) tendered its 2014 General Rate

Case (GRC) Notice of Intent on July 2, 2012, and served a Notice of Availability

on the service list from its 2011 GRC. The Division of Ratepayer Advocates

(DRA)2 accepted the tendered documents on September 14, 2012. PG&E filed its

GRC application on November 15, 2012, for Phase 1, proposing to increase gas

and electric base revenue requirements by $1.282 billion based on a 2014 test

year, with additional increases for attrition covering 2015 and 2016 amounting to

$492 million and $504 million, respectively.

PG&E describes the steps it took to prepare its 2014 GRC in compliance

with prior Commission decisions in Exhibit 42, Chapter 8. PG&E listed 35 items

related to prior decisions and described the compliance activity or status of each

item. PG&E complied with directives from the last GRC to provide testimony

and workpapers on proposed new types of costs, as well as the processes and

criteria used to develop these materials. PG&E has provided budget reports for

its spending by Major Work Category (MWC) that describe reallocations each

year.

PG&E also argues that the requirement for an annual report describing

improvements to PG&E’s website has outlived its usefulness and should be

discontinued. No party has opposed PG&E’s request to discontinue the

2 The Division of Ratepayer Advocates changed its name to the Office of Ratepayer Advocates (ORA) September 26, 2013, pursuant to Senate Bill (SB) 96. For purposes of this decision, we refer to ORA by its previous name, Division of Ratepayer Advocates, as was used during the course of most of the litigation in this proceeding.

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reporting on PG&E’s website improvements. We accordingly relieve PG&E of

this obligation.

Protests to PG&E’s application were filed on December 17, 2012.

Prehearing Conference (PHC) Statements were filed on January 8, 2013. Protests

and/or PHC Statements were filed by DRA, The Utility Reform Network

(TURN), the City and County of San Francisco (CCSF), the Greenlining Institute

(Greenlining), the Center for Electrosmog Prevention (CEP), the Coalition of

California Utility Employees (CCUE), Merced And Modesto Irrigation Districts

(Irrigation Districts), the Marin Energy Authority (MEA), the Alliance for Retail

Energy Markets, the Direct Access Customer Coalition, Engineers and Scientists

of California (ESC), and the National Asian American Coalition and Ecumenical

Center for Black Church Studies.

PG&E replied to the protests on December 21, 2012. On January 11, 2013,

the Commission held a duly noticed PHC to determine parties, create the service

list, identify issues, consider the schedule, and address other matters necessary to

proceed. The assigned Commissioner issued a Scoping Memo on

January 22, 2013.3 On February 6, 2013, motions for party status were granted for

the Alliance for Nuclear Responsibility and the Small Business Utility Advocates.

On March 21, 2013, the Commission issued Order Instituting Investigation

(I.) 13-03-007, the companion investigation to this GRC. The purpose of

I.13--03-007, which was consolidated with Application (A.) 12-11-009, is to allow

3 On June 9, 2014, an amended scoping memo was issued, indicating that prospective recommendations relating to safety consultant reports would be treated in a separate decision after the Commission adopts 2014-2016 revenue requirements.

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the Commission to (1) address matters raised by parties other than PG&E, and

(2) issue orders on matters for which PG&E might not be the proponent.

During May and June 2012, public participation hearings for this

proceeding were held in San Francisco, San Bruno, Fresno, Bakersfield,

Santa Rosa, Oakland, Chico, San Jose, Soledad, and San Luis Obispo. Speakers

addressed a variety of issues ranging from impacts of proposed rate increases on

customers to PG&E’s safety measures and structure reliability. In addition, a

number of letters and e-mails were received concerning the GRC application.

Many of the public comments received expressed opposition to the rate increases

due to a variety of concerns, including the state of the California economy, and

customers’ economic circumstances. Others expressed support for PG&E’s

proposed revenue increase based on the view that the rate increase would

support necessary infrastructure improvements to promote safe and reliable

service. We have considered this public input in developing this decision.

DRA presented testimony on May 3, 2013. DRA recommended a

$146 million decrease in Electric Distribution, an $83 million increase in Gas

Distribution, and a $99 million decrease in Electric Generation (EG) compared to

the most recent authorized revenues.

Intervenors presented testimony on May 17, 2013. PG&E presented

rebuttal testimony on May 28, 2013. Evidentiary hearings were held beginning

July 15, 2013 and continued through August 9, 2013. During the hearings, the

testimony of various parties, together with several cross-examination exhibits

and various errata and updates were admitted into evidence. Motions were also

filed for approval of Settlements on certain limited issues. A Joint Comparison

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Exhibit was served on August 23, 2013. Opening Briefs were filed on

September 6, 2013 and reply briefs on September 27, 2013.4 On October 4, 2013,

PG&E submitted its update testimony (Exh. 375; (PG&E-32)), limited to updating

its non-labor escalation rates. No party contested the update, and we reflect

those results in Appendix C.

1.1. Framework for Preparing this Decision

This decision is organized in the sequence of topics generally set forth in

the common briefing outline utilized in this proceeding. Since evidence and

arguments in this proceeding are voluminous, we focus discussion on the major

points of contention and do not summarize every nuance of each party’s

positions.

Similarly, due to the volume of the record and issues, we have not

explicitly described every single issue raised during the proceeding. To do so

would have increased the size of this decision even beyond its current length.

That does not mean, however, that we have overlooked issues raised by parties.

We have reviewed the record, as well as the arguments made, and considered all

issues raised in deciding revenue requirements and related policy directives

adopted herein. In all other respects, this decision does not address revenue

requirements for electric transmission, gas transmission and storage, Public

Purpose Programs (PPPs) and conservation programs, except for allocating

common costs.

4 By ruling dated April 4, 2014, the ALJ granted a March 18, 2014 of PG&E to reopen the record and to receive updates to correct certain errors, as set forth in the motion. We have reflected the corrected data in our adopted results.

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PG&E’s gas distribution and electric distribution and generation revenue

requirement claimed cost increases cover: Operations and Maintenance (O&M)

expense; Customer Services expense; Administrative and General (A&G)

expense; payroll taxes, franchise fees, and uncollectibles; a fair return on rate

base; taxes and depreciation; and Other Operating Revenue.

As a basis for deciding issues in this proceeding, we determine whether

PG&E has met the burden of proving that it is entitled to the relief sought in this

proceeding, and of affirmatively establishing the reasonableness of all aspects of

the application. With the burden of proof placed on PG&E, the Commission has

held that the standard of proof PG&E must meet is that of a preponderance of

evidence. Preponderance of the evidence usually is defined in terms of

probability of truth, e.g., such evidence as, when weighed with that opposed to

it, has more convincing force and the greater probability of truth. PG&E must

present more evidence that supports the requested result than would support an

alternative outcome.

In Decision (D.) 11-05-018 (PG&E’S 2011 GRC), the Commission required

that as part of its showing in the current proceeding , PG&E fully describe any

reprioritizations and deferrals of costs explicitly identified in the Settlement

Agreement or costs that can reasonably be imputed from the Settlement

Agreement. PG&E was to fully explain its reprioritization process, justify

deferrals of specific activities and projects, and justify the implemented higher

reprioritized activities and projects that were not identified in the prior GRC.

For previously deferred activities and projects being requested again,

PG&E was to fully explain why they are needed now when they were able to be

deferred before. As stated in D.11-05-018, we critically evaluate previously

requested activities or projects that were deferred and requested again, keeping

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in mind that the utility has the obligation to maintain its operations and plant in

the condition to provide efficient, safe and reliable service, even if that condition

requires more expenditures than the Commission had authorized.

2. Balancing Safety and Risk Concerns with Just and Reasonable Rates

We have reviewed this record to determine whether or to what extent

PG&E’s GRC proposal is founded on an appropriate and explicit safety and

security risk assessment. We have previously adopted the Legislature’s overall

policy statement: “It is the policy of the state that the commission and each gas

corporation place safety of the public and gas corporation employees as the top

priority. The commission shall take all reasonable and appropriate actions

necessary to carry out the safety priority policy of this paragraph consistent with

the principle of just and reasonable cost-based rates.”5

Public Utilities Code Sections 961 and 963, enacted by SB 705 (Ch. 522,

Stats. 2011), require each gas corporation to develop and implement a plan for

the “safe and reliable operation of its commission-regulated gas pipeline facility

that implements the policy of paragraph (3) of subdivision (b) of Section 963,

subject to approval, modification, and adequate funding by the commission.”

Pub. Util. Code § 451 requires that each public utility in California must

“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.”

5 Pub. Util. Code § 963(b)(3).

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Consistent with this statutory guidance, we face the task of adopting an

appropriate level of utility funding to ensure safe and reliable service, while

keeping rates affordable, and allowing a fair rate of return. We expect the

utilities to make safety a foundational priority. When evaluating the revenue

requirements requested by PG&E, the Commission has placed a priority on

programs that enhance safety and reliability of the natural gas and electric power

infrastructure and operations.

In this context, we also take note of Rulemaking (R.13-11-006) which is

addressing whether and how the Commission should formalize rules to ensure

the effective use of a risk-based decision-making framework to evaluate safety

and reliability improvements presented in GRC applications, develop necessary

performance metrics and evaluation tools, and modify the Rate Case Plan

documentation requirements for the investor owned energy utilities.

DRA and TURN, among other parties, claim that PG&E has failed to

adequately support that its proposed increases are necessary to provide safe and

reliable service, and has not shown that the claimed benefits justify the costs to

be incurred. PG&E also claims, that DRA’s and TURN’s recommended funding

levels would prevent, or at least delay, PG&E’s ability to implement adopting

best practices for its gas distribution business and implementing safety initiatives

in the electric distribution and energy supply businesses. PG&E claims DRA and

TURN recommendations represent a disproportionate focus on minimizing cost

to the detriment of safety. PG&E claims that, DRA’s and TURN’s proposed

funding reductions, if adopted, would directly contravene the Commission’s

commitment to ensure that safety remains PG&E’s top priority. PG&E notes that

many of its proposed projects are not being initiated for cost savings purposes,

but to comply with legal and regulatory requirements, improve customer service,

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enhance safety, increase environmental benefits and for various other non-cost

related reasons.

Ensuring that the management of investor-owned gas utility systems fully

performs its duty of safe operations is a core obligation of this Commission. The

California legislature has enacted statutory language that codifies in more

explicit terms the priority placed upon safety of the public and utility employees.

As provided in Pub. Util. Code § 961(e), the Commission and each gas

corporation must “provide opportunities for meaningful, substantial, and

ongoing participation by the gas corporation workforce in the development and

implementation of the plan, with the objective of developing an industry-wide

culture of safety that will minimize accidents, explosions, fires, and dangerous

conditions for the protection of the public and the gas corporation workforce.”

Among public utility facilities, natural gas transmission and distribution

pipelines present the greatest public safety challenges. Gas pipelines carry

flammable gas under pressure. These pipelines are typically located in public

right-of-ways, at times in densely populated areas. The dimensions of the threat

to public safety from natural gas pipeline systems, including the pace at which

death and life-altering injuries can occur, are more extreme than other public

utility systems. This unique feature requires that natural gas system operators

and this Commission assume a different perspective when considering natural

gas system operations. This perspective must include a planning horizon

commensurate with that of the pipelines; that is, in perpetuity, and awareness of

the extreme public safety consequences of neglecting safe system construction

and operation. In this proceeding, we have approved the largest share of cost

increases for gas distribution.

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Our concern regarding public utility safety covers not just natural gas

service, however, but extends to electric service, as well. On September 23, 2010,

the Commission created an Independent Review Panel (IRP) of experts to

conduct a comprehensive study and investigation of the September 9, 2010,

San Bruno natural gas pipeline explosion and fire. The Commission directed the

Panel to make a technical assessment of the events, determine the root causes,

and offer recommendations for action by the Commission to best ensure such an

accident is not repeated elsewhere. The IRP issued a report in June 2012. Among

the issues addressed in the IRP Report was how to better incorporate safety into

ratemaking.

In accordance with this concern, by letter dated March 5, 2012, from the

Commission’s Executive Director to PG&E’s Senior Vice President of Regulatory

Affairs, PG&E was directed to conduct a review focused on operational and

public safety issues as part of the GRC.6 Pursuant to the above-referenced

March 5, 2012 letter from the Executive Director, the Safety and Enforcement

Division (SED) also commissioned two reports from independent consultants to

evaluate PG&E’s electric and gas operations from a safety and risk perspective,

and in anticipation of PG&E’s testimony which was to include a risk assessment

of its gas distribution, and electric distribution and generation systems.

SED retained the Cycla Corporation (Cycla) and the Liberty Consultant

Group (Liberty) as consultants to evaluate risk assessments, risk mitigation,

programs and policies, as well as PG&E corporate policies, goals, culture and the

efforts being made to bolster PG&E system safety and reliability. These

6 See Exh. 53 (PG&E -18), at 11A-1-3.

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consultant reports were issued to the service list by ruling dated May 17, 2013. A

third consultant report by Overland Consulting was issued by ruling dated

May 31, 2013, and presented the results of a financial audit of PG&E’s Gas

Distribution System. Pursuant to the Executive Director’s letter, PG&E was

directed to include in this GRC “a risk assessment that underlies [PG&E’s] rate

requests” in order to satisfy the GRC’s focused on safety in addition to rates. The

Executive Director further stated that, “[a]s part of the capital investing planning

that PG&E performs, PG&E should perform and provide a risk assessment of its

entire system, both gas and electric, and a comparison to industry best practices.”

The letter continued, “For example, PG&E should give a risk assessment of its

physical system as well as a description of and a justification for the company’s

risk mitigation programs and policies. PG&E should provide to identify and

prioritize areas of risk and include the underlying rationale for [PG&E’s]

assessment.”

Although PG&E is in the process of developing the data and models to do

a system-wide risk assessment, PG&E’s GRC filing does not explicitly include

such a risk assessment and justification of its risk mitigation programs and

policies. Based on the GRC filing, Liberty observed that despite material

progress by PG&E, “one cannot now use PG&E’s risk assessments to assess in

reasonably robust ways the probabilities and consequences of failures associated

with safety and security risks.”7

PG&E was also directed to identify and prioritize areas of risk and to

include the underlying rationale for its assessments. PG&E was to present

7 See Exh 168, Liberty Report at 17.

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testimony detailing the overall policy of the utility’s safety and security

measures, including physical security and cyber security of the system. PG&E

was to detail how safety and security measures are incorporated into its

corporate policies, goals, and culture, and the efforts being made to bolster

system safety and security.

Safe and reliable service means that the utility must have accurate records

about its facilities, have a trained professional workforce, and take appropriate

actions to keep its system facilities safely operational in conformity with

applicable laws, regulations, and policies. The Commission has carefully

reviewed PG&E’s funding request to determine the potential impacts to public

and employee safety at the competing funding level requested by the parties.

PG&E explains that in selecting measures to mitigate identified safety and

reliability risks, it chose the measures that move the utility toward first quartile

safety performance cost-effectively and considered cost in determining the pace

of implementing these measures. PG&E states that it developed implementation

plans to accomplish the selected mitigation measures. The Liberty consultants

concluded, however, that while PG&E identified and quantified spending on

safety and security measures in reasonable detail in its GRC filing, PG&E

“overused” the “safety” label. The Liberty consultants found that much of what

PG&E designates as “safety” falls under what others consider to be baseline and

reliability work. The Liberty Group observed regarding PG&E’s analysis of costs

and benefits that:

The GRC has generally not documented how expenditures to address safety and security are in proportion to or otherwise

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aligned with identified risks identified. [sic] PG&E has generally not demonstrated analytically that the benefits of proposed safety and security risk mitigation measures justify their costs.8

Both the Cycla (gas distribution) and Liberty (electric) studies noted

limitations in PG&E’s showing as to the impact, if any, of its proposed activities

on reducing safety risks. As Cycla explained, PG&E’s GRC filing “does not

present a clear logical linkage between safety risk and the activities designed to

control them.”9 Liberty likewise “could not assess whether the degree of risk

reduction can be expected to reach a level considered satisfactory from customer,

public, and employee perspectives.”10

The Liberty consultants “queried PG&E about the adequacy of its

foundation for concluding that expenditures to address safety and security and

security risks are in proportion to risks properly identified. [The Liberty

consultants] could not find substantial documentation of this type of thinking or

analysis, although [they] consider such support to be consistent with the

expectations created by the March 5 letter [from the Executive Director] and by

the areas of inquiry included in our scope for this study.”11 Cycla likewise did

not find substantial documentation showing that PG&E’s planned expenditures

to address safety and security risks are in proportion to the risks prope