A.02-05-004, I.02-06-002 ALJ/MSW/sid DRAFT
ALJ/MSW/sid DRAFT Agenda ID #3268
Ratesetting
4/1/2004 Item 29
Decision PROPOSED DECISION OF ALJ WETZELL (Mailed 2/13/2004)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Application of Southern California Edison Company (U 338-E) For Authority to, Among Other Things, Increase Its Authorized Revenues For Electric Service in 2003, And to Reflect That Increase in Rates. / Application 02-05-004(Filed May 3, 2002)
Investigation on the Commission’s Own Motion into the Rates, Operations, Practices, Service and Facilities of Southern California Edison Company. / Investigation 02-06-002
(Filed June 6, 2002)
(See Appendix A for a list of appearances.)
OPINION ON BASE RATE REVENUE REQUIREMENT
AND OTHER PHASE 1 ISSUES
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A.02-05-004, I.02-06-002 ALJ/MSW/sid DRAFT
TABLE OF CONTENTS
Title Page
OPINION ON BASE RATE REVENUE REQUIREMENT
AND OTHER PHASE 1 ISSUES 2
1. Introduction 2
1.1. Summary of Decision 2
1.2. Background 4
2. Preliminary Matters 6
2.1. The Utility’s Showing 7
2.2. SCE’s Financial Health 10
2.3. Comparative Rate Levels 12
2.4. Forecasting Issues 14
2.4.1. Averaging and Other Methodologies 15
2.4.2. Capital Expenditures & PBR 17
2.4.3. Witness Qualifications 19
3. Generation 19
3.1. San Onofre Nuclear Generating Station 20
3.1.1. SONGS 2 & 3 Capital 20
3.1.1.1. Introduction 20
3.1.1.2. Forecasting Methods 21
3.1.1.3. Used Fuel Storage Project 24
3.1.1.4. Marine Mitigation Projects 25
3.1.1.5. Offsite Sirens and Monitors Project 26
3.1.1.6. Blanket Work Orders 27
3.1.1.7. Conclusion – SONGS 2 & 3 Capital Expenditures 28
3.1.2. SONGS 2 & 3 Base O&M Expenses 29
3.1.2.1. Introduction 29
3.1.2.2. Training Credits Adjustment 30
3.1.2.3. Deferred Activities Adjustment 31
3.1.2.4. Awards and Recognition Adjustment 32
3.1.2.5. Nuclear Rate Regulation 34
3.1.2.6. Site Projects 35
3.1.2.7. Workers’ Compensation Adjustment 39
3.1.2.8. Labor Scarcity Adjustment 40
3.1.2.9. Plant Security Adjustment 43
3.1.2.10. Maintenance/FERC Account 524 45
3.1.2.11. Maintenance/FERC Accounts 530, 531, and 532 46
3.1.2.12. Nuclear Support/FERC Account 524 47
3.1.2.13. Nuclear Support/FERC Account 528 48
3.1.2.14. Nuclear Support/FERC Account 532 49
3.1.2.15. Other Methodological Issues 50
3.1.2.16. Removal of Outage Expenses 51
3.1.2.17. NRC Licensee Fees 52
3.1.2.18. Conclusion – SONGS 2 & 3 Base O&M 53
3.1.3. SONGS 2 & 3 Outage O&M 55
3.1.3.1. Cost Recovery Proposal 55
3.1.3.2. Reinstatement of Excluded Costs 56
3.1.3.3. Mobilization Adjustment 57
3.1.4. SONGS 1 Shutdown O&M 57
3.1.5. SDG&E’s Share of SONGS Costs 59
3.2. Palo Verde Nuclear Generating Station 60
3.2.1. Palo Verde Capital Expenditures 60
3.2.2. Palo Verde O&M Expenses 61
3.3. Mohave Generating Station 62
3.3.1. Mohave Capital Expenditures 63
3.3.2. Mohave O&M Expenses 66
3.4. Four Corners Generating Station 69
3.4.1. Four Corners Capital Expenditures 69
3.4.2. Four Corners O&M Expenses 70
3.5. Hydroelectric Generation 72
3.5.1. Hydroelectric Capital Expenditures 72
3.5.2. Hydroelectric O&M Expenses 73
3.6. Other Generation 75
3.7. Generation Capital Additions for 1997-1998 76
3.7.1. Introduction 76
3.7.2. Evaluation Criteria 79
3.7.3. Cost-Effectiveness Analyses 85
3.7.4. Performance Improvements 86
3.7.5. Budget Variances 87
3.7.6. Project Timing 88
3.7.7. Casualty Loss Projects 88
3.7.8. Conclusion – 1997-98 Capital Additions 89
4. Transmission and Distribution (T&D) 90
4.1. Introduction 90
4.2. Level of Reliability Performance 91
4.3. Wood Pole Inspections 94
4.3.1. Introduction 94
4.3.2. Historical Pole Inspections 94
4.3.3. Proposed Penalty 99
4.3.4. Ratemaking Adjustments for Deferred Inspections 103
4.3.5. Reporting Requirement 107
4.4. T&D Capital 107
4.4.1. Introduction 107
4.4.2. ORA’s Plant Recommendations 108
4.4.3. Wood Pole Replacement Costs 110
4.5. T&D O&M Expenses 113
4.5.1. ORA’s Proposals 113
4.5.2. Jurisdictional Separation 115
4.6. Line and Service Extension Rules 115
4.7. Electric Transportation 117
4.7.1. Introduction 117
4.7.2. ORA’s Recommendations 118
4.7.3. Aglet’s Recommendations 119
5. Customer Service 122
5.1. Introduction 122
5.2. O&M Expenses and Related Issues 122
5.2.1. Overview 122
5.2.2. Customer Service Operations 123
5.2.2.1. Forecast Method 123
5.2.2.2. Uncollectible Factor 124
5.2.2.3. Authorized Payment Agencies (APAs) 126
5.2.2.4. Internet Site Maintenance 128
5.2.2.5. Direct Access Costs 129
5.2.3. Customer Service & Information 130
5.2.3.1. Public Goods Charge Funding 130
5.2.3.2. Air Conditioner Cycling Programs 132
5.2.3.3. Load Control Programs 133
5.2.3.4. Economic and Business Development Costs 133
5.2.3.5. LA County’s Proposals 138
5.2.3.5.1. Introduction 138
5.2.3.5.2. Billing and Consumption Data 138
5.2.3.5.3. Energy Efficiency Financing 139
5.2.3.5.4. Ratepayer Impact Analysis 140
5.3. Service Fees and Other Operating Revenues 142
5.3.1. Ratemaking Policy Considerations 142
5.3.2. Late Payment Charge 144
5.3.3. Service Establishment Charge 147
5.3.4. Direct Access Customer Charge 148
5.3.5. Level of Service Charges 149
5.4. Capital 150
5.4.1. SCE’s Showing 150
5.4.2. Real Time Energy Metering (RTEM) 153
5.5. Service Guarantees 155
6. Administrative and General 159
6.1. Introduction 159
6.2. Financial Organizations and Capitalized Expenses 159
6.2.1. Account 930 – Participant Credits 159
6.2.2. Capitalized Pension and Benefits (P&B) 161
6.3. Legal And Regulatory, Workers’ Compensation, Insurance 162
6.3.1. Account 923 (ORA Audit Recommendations) 162
6.3.2. Accounts 923 & 928 (Forecast Methodology) 163
6.3.3. Account 928 (GRC Expenses) 163
6.3.4. Account 930 (Board Meetings) 164
6.3.5. Property and Liability Insurance Expense 165
6.3.5.1. Account 924 (Property Insurance Expenses) 165
6.3.5.2. Account 925 (Liability Insurance) 166
6.4. Shared Services 166
6.4.1. Shared Services Expenses 166
6.4.1.1. Business Resources 166
6.4.1.2. Investigations Division 169
6.4.1.3. Shared Services Support Group 170
6.4.1.4. Corporate Real Estate 171
6.4.1.4.1. Market Studies, Title & Mapping 171
6.4.1.4.2. Landscape Maintenance 172
6.4.1.4.3. Account 935 Forecasting Method 173
6.4.2. Shared Services Capital 173
6.4.2.1. Introduction 173
6.4.2.2. Adequacy of SCE’s Showing 174
6.4.2.3. Projects Over $1 Million 174
6.4.2.3.1. Strategic Facilities Plan 174
6.4.2.3.2. Corporate Fitness Center 177
6.4.2.3.3. Seismic Upgrades 179
6.4.2.4. Blanket Work Orders - Major Structures 180
6.5. Information Technology 181
6.5.1. Introduction 181
6.5.2. IT Expenses 181
6.5.3. IT Capital Expenditures 184
6.5.4. Y2K Retention Bonuses 186
6.5.5. IBM Charges 187
6.6. Capitalized Software 187
6.7. Human Resources (HR) 188
6.7.1. HR Departmental Costs 188
6.7.1.1. Total Compensation Division 188
6.7.1.2. HR Service Center 189
6.7.1.2.1. Dues and Memberships 189
6.7.1.2.2. FERC Account 923 191
6.7.1.3. Outside Services for Executives 191
6.7.2. Employee Compensation Issues 192
6.7.2.1. Total Compensation Study 192
6.7.2.2. Executive Compensation 196
6.7.2.2.1. Executive Bonuses 196
6.7.2.2.2. Executive Retirement Benefits 199
6.7.2.2.3. Executives and Philanthropy 200
6.7.2.3. Incentive Plans 201
6.7.2.3.1. Spot Bonuses 201
6.7.2.3.2. Results Sharing 203
6.7.2.3.3 ACE Program 207
6.7.2.4. Other Compensation Issues 208
6.7.2.4.1. Pensions 208
6.7.2.4.2. 401(k) Plan 210
6.7.2.4.3. Health Care Programs 213
6.7.2.4.4. Miscellaneous Benefits 214
6.7.2.4.5. PBOP Refund Proposal 215
6.7.2.4.6. TURN’s PBOP Proposal 217
6.8. Public Affairs and Corporate Communications 218
6.8.1. Public Affairs 218
6.8.2. Franchise Fees 222
6.8.3. Corporate Communications 223
6.9. Energy Supply and Management (ES&M) 224
6.10. Reimbursable Expenses Error Rate 226
7. Other Audit Issues – Affiliates 229
7.1. Introduction 229
7.2. Edison Select Costs 230
7.3. Energy Marketing Affiliate 230
8. Rate Base 231
8.1. Plant Balance Weighting Percentage 231
8.2. Materials and Supplies Inventory 233
8.3. Working Cash 235
8.4. Customer Advances for Construction 237
8.5. Customer Deposits 238
9. Depreciation and Amortization 243
9.1. Introduction 243
9.2. Depreciation Study 245
9.3. SONGS 2 & 3 Remaining Life 249
9.4. Easements 251
10. Other Results of Operations Issues 252
11. Post Test Year Ratemaking 253
11.1. Introduction 253
11.2. Revenue Balancing Account 254
11.3. SCE’s and Aglet’s PTYR Proposals 255
11.4. Productivity Adjustment 259
11.5. SONGS 2 & 3 Outages 260
11.6. Capital Forecasting Methodology 261
11.7. Escalation Factors 264
11.8. Exogenous Cost Changes (Z-Factors) 265
11.9. Filing Procedure 266
12. Jurisdictional Allocation Method 268
13. Performance Incentives 269
13.1. Introduction 269
13.2. The Case for Performance Incentives 271
14. Issues Raised by Commissioner Wood and the Energy Division 278
14.1. Introduction 278
14.2. Integrated Resource Planning and UtilityOwned Generation 279
14.3. Supplier Diversity 286
14.4. Workforce Diversity 290
15. Disposition of Memorandum Account 294
16. Comments on Proposed Decision 296
17. Assignment of Proceeding 297
Findings of Fact 297
Conclusions of Law 325
ORDER.. 331
APPENDIX A - List of Appearances
APPENDIX B - List of Abbreviations and Acronyms
APPENDIX C - 2003 Results of Operation
APPENDIX D - 2004 and 2005 Summaries of Earnings
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A.02-05-004, I.02-06-002 ALJ/MSW/sid DRAFT
OPINION ON BASE RATE REVENUE REQUIREMENT
AND OTHER PHASE 1 ISSUES
1. Introduction
1.1. Summary of Decision
Returning Southern California Edison Company (SCE) to conventional cost-of-service ratemaking after a six-year hiatus, we set the company’s authorized base rate revenue requirement at $2.756 billion for the 2003 test year. On an annualized basis, this represents an increase of $15 million (0.5%) above SCE’s present base rate revenue of $2.741 billion for 2003. SCE had requested an increase of $251 million (9.2%). The test year revenue requirement authorized herein will be implemented in accordance with Decision (D.) 03-05-076 and related determinations made in this decision.
SCE’s base rate revenue requirement covers the costs of operating, maintaining and investing in the utility’s generation, distribution, and central office functions. It excludes such costs as fuel, power procurement, and public purpose programs. In D.03-07-029 we provided for the reduction of SCE’s retail rates by $1.249 billion annually upon the utility’s recovery of the balance of its Procurement Related Obligations Account (PROACT). This reduction was calculated using an estimate of the total bundled service ratepayer revenue responsibility of $8.472 billion, which includes the share of the Department of Water Resources revenue requirement paid by SCE’s customers. Thus, the base rate revenue requirement that we authorize today, while substantial, represents approximately one-third of the consolidated revenue requirement being paid by SCE’s bundled service customers. The adopted test year base revenue requirement increases the bundled revenue requirement by 0.2%.
Pursuant to the Commission’s order in D.03-07-029, SCE’s electric rates will be increased on a system average percentage change (SAPC) basis to give effect to the base rate revenue requirement increase adopted today. In Phase 2 of this proceeding, the Commission is evaluating proposals regarding the allocation of revenue requirement responsibility to customer classes and the design of rate structures.
We approve SCE’s request to establish a late payment charge for residential customers along with an exemption for customers enrolled in the California Alternate Rates for Energy (CARE) program. We also approve in part SCE’s request to adjust its charges for returned checks, reconnects, service establishment, and field assignment. We do so to more closely align rates and charges with the principle of cost causation.
We adopt, with revisions, SCE’s proposed “post test-year ratemaking” (PTYR) mechanism to adjust the authorized revenue requirements for 2004 and 2005. The PTYR mechanism ties capital forecasts to actual projects in SCE’s budget subject to the true-up. In connection with the PTYR mechanism, we approve a refueling and maintenance outage expense recovery mechanism for San Onofre Nuclear Generating Station Units 2 & 3 (SONGS 2 & 3).
This decision reviews certain 1997-98 generation capital additions, consideration of which was transferred from Application (A.) 99-04-024 to this proceeding. SCE is authorized to recover costs associated with $30.937 million in capital additions found to be reasonable.
Proposals by SCE and other parties to establish a system of safety, reliability, and customer satisfaction performance incentives are denied. Even though similar performance incentives have been used in connection with SCE’s performance-based ratemaking (PBR) mechanism, they have not been justified in connection with conventional cost of service ratemaking.
Finally, in this decision, we examine certain of the roles fulfilled by SCE on behalf of its customers and other stakeholders. We review and comment on SCE’s role with respect to integrated resource planning and whether it should be prepared to build or buy utility-owned generation capacity to serve its customers. We also review SCE’s Women, Minority, and Disabled Veterans Business Enterprise (WMDVBE) program and the diversity of its workforce.
With this decision, Phase 1 of this general rate case (GRC) proceeding is concluded. Phase 2 of this proceeding addresses SCE’s pricing proposals and will be resolved by future order of the Commission. This proceeding therefore shall remain open.
1.2. Background
In SCE’s last GRC, D.96-01-011 established SCE’s authorized revenue requirement for the 1995 test year. Pursuant to D.96-09-092, SCE has operated under a PBR mechanism since January 1, 1997. Pursuant to D.01-06-038 and D.02-04-055, the PBR mechanism remains in effect, with modifications, until it is superseded by the issuance of a decision in SCE’s next GRC, i.e., the instant proceeding.
On May 3, 2002, SCE filed A.02-05-004 seeking, among other things, an increase in its authorized test year 2003 base rate revenue requirement. SCE originally sought authorization for revenues of approximately $3.065 billion for 2003, which represented an increase of $286 million (10.3%) above the currently authorized base rate revenue as then calculated. During the course of the proceeding, SCE revised both its request and its calculation of present revenue. Based upon its latest calculations, SCE now seeks authorization for base revenue of approximately $2.992 billion for 2003. This represents an increase of $251million (9.2%) above the base rate revenue, now calculated at $2.741 billion. SCE also seeks authority to establish a post test-year ratemaking mechanism that would set the authorized base revenue requirements for 2004 and 2005. In addition, SCE seeks authority to establish a late payment charge for residential customers, and to increase various fees such as charges for returned checks, service establishment, and reconnection.
The Commission instituted Investigation (I.) 02-06-002 on June 6, 2002, to allow the Commission to hear proposals other than SCE’s, and to enable the Commission to enter orders on matters for which the utility may not be the proponent. The Commission ordered that A.02-05-004 and I.02-06-002 be heard on a consolidated evidentiary record.
Prehearing conferences were convened on June 13 and November 1, 2002. Public participation hearings were held at 14 locations throughout SCE’s service territory in October 2002. Direct and rebuttal evidentiary hearings were held before Administrative Law Judge (ALJ) Wetzell on 38 days from November 2002 to March 2003. Briefs were filed on April 18, 2003 and reply briefs were filed on May 28, 2003.[1] SCE and San Diego Gas & Electric Company (SDG&E) served update testimony on May 9, 2003. Phase 1 was submitted for decision on October23, 2003. Final oral argument before the Commission was held following the issuance of the ALJ’s proposed decision.