ALJ/RMD/rbg/hkr **DRAFTAgenda ID #8129 (Rev. 3)
Ratesetting
3/12/2009
Decision PROPOSED DECISION OF ALJ DeANGELIS (Mailed 11/18/ 2008)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Application of SOUTHERN CALIFORNIA EDISON COMPANY (U338E) for Authority to, Among Other Things, Increase Its Authorized Revenues For Electric Service in 2009, And to Reflect That Increase In Rates. / Application 07-11-011(Filed November 19, 2007)
And Related Matter. / Investigation 08-01-026
(See Appendix A for a list of appearances.)
DECISION ON TEST YEAR 2009 GENERAL RATE CASE
FOR SOUTHERN CALIFORNIA EDISON COMPANY
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A.07-11-011, I.08-01-026 ALJ/RMD/rbg/hkr **DRAFT
TABLE OF CONTENTS
(Cont’d)
TitlePage
TABLE OF CONTENTS
TitlePage
DECISION ON TEST YEAR 2009 GENERAL RATE CASE FOR SOUTHERN CALIFORNIA EDISON COMPANY
1.Summary
1.1.Forecast Test Year Ratemaking
1.2.Procedural History
1.3.Burden of Proof
1.4.Standard of Proof
2.Generation Expenses
2.1.Nuclear Generation
2.1.1.SONGS 2 & 3 Operation and Maintenance
2.1.2.NRC License Renewal Feasibility Study – FERC Account524
2.1.3.Nuclear Energy Institute Fees – FERC Account 517
2.1.4.SONGS Refueling and Maintenance Outages – FERC Accounts 517,520, 524, 525, 528, 529, and 532
2.1.5.Palo Verde - FERC Accounts 517, 519, 520, 523, 524, 528532
2.2.Coal Generation
2.2.1.Four Corners Generating Station - Staffing Increase
Costs-FERC Accounts 500-502, 505-507, and 510-514
2.2.2.Mohave Generating Station-FERC
Subaccounts 506.013 and 514.013
2.3.Hydroelectric Generation Forecasting Method – FERC Accounts 535-545
2.3.1.Operations of Reservoirs, Dams and Waterways -
FERC Account 537
2.3.2.Cloud Seeding – FERC Account 536
2.3.3.San Gorgonio Hydro Project – FERC Accounts 536,
537, 538, 540, 542, 543, 544
2.3.4.Future Adjustment No. 1 Hydro Staffing Increases – FERC Accounts 537, 538, 539, 543, 544, 545
2.3.5.Future Adjustment Nos. 4 & 7 Housing & Asbestos Abatement Project – Poole and Rush Creek - FERC Account 542
2.3.6.Alleged Discrepancies on Hydro Projects
2.3.7.Alleged Rule 1.1. Violation
2.3.8.Future Adjustment No. 8 - Hydro Vegetation Management Expenses – FERC Account 539
2.4.Gas–Fired Generation
2.4.1.Mountainview O&M Expenses
2.4.2.Peaker O&M - FERC Accounts 546, 548, 549,
551, 553, 554
2.4.3.One-Way Balancing Account for Peaker O&M
2.4.4.Integration with Mountainview–Staffing & Information Technology – FERC Accounts 546, 548, 549, 551-554
2.4.5.Information Technology Equipment Purchases–
One Time Expenses - FERC Account 549
2.5.Solar Two Decommissioning Project
2.6.Project Development Division–Request to Include
RD&D – FERC Accounts 506 and 549
2.7.Pebbly Beach Generation Station–Catalina Island Forecasting Method – FERC Accounts 548, 549, 553
3.Transmission & Distribution Expenses – FERC Accounts 560-573 Transmission Expenses; FERC Accounts 580-598
Distribution Expenses
3.1.Operations Supervision and Engineering – FERC Account 560
3.1.1.Operations Engineering - FERC Subaccount 560.100
3.1.1.1.Engineering Advancement
3.1.1.2.Additional Engineering Staff
3.1.1.3.Standards and Publications Contract Group
3.1.1.4.Reallocation of Overhead
3.1.1.5.Desktop Software Upgrade
3.1.1.6.Project Management Organization Work Order Write-Offs
3.2.Allocated Division Overhead to Clearing Accounts – FERC Subaccounts 560.980, 568.980, 580.980, and 590.980
3.3.Transmission Station Expenses - FERC Account 562
3.4.Vehicle Costs Transmission & Distribution Business
Unit - FERC Accounts 562, 563, 566, 568, 570, 571, 582,
583, 584, 587, 588, 590, 592, 593, 594, and 596
3.5.Inspect and Patrol Lines Overhead Line Expenses – FERC Subaccount 563.100
3.5.1.Transmission Line Clearance
3.5.2.Transmission Line Patrols
3.5.3.Reallocation of Overhead
3.6.Safety Meetings-Miscellaneous Transmission Expenses –
FERC Subaccount 566.100
3.7.Miscellaneous Transmission Line Expenses – FERC
Subaccount 566.200
3.8.Miscellaneous Expenses from Other Organizations – FERC Subaccount 566.300
3.8.1.Corporate Real Estate and Additional IT Costs
3.8.2.Reallocation of Overhead
3.9.Regulatory, Planning, and Business Development - FERC Subaccount 566.500
3.10.Training Miscellaneous Transmission Expenses - FERC Subaccount 566.700; Training Miscellaneous Distribution Expenses - FERC Subaccount 588.700
3.11.Maintenance of Station Equipment - FERC Account 570
3.11.1.Routine Maintenance of Transmission Circuit
Breakers- FERC Subaccount 570.200
3.11.2.Maintenance of Miscellaneous Station Equipment -
FERC Subaccount 570.400
3.11.2.1.Disconnect Repairs
3.11.2.2.Switchrack Lighting
3.11.2.3.Cable Trench Covers
3.11.2.4.Rack Inspections
3.11.2.5.Work Order Related Expenses - FERC Account570.400
3.12.Maintenance of Overhead Lines – FERC Account 571
3.12.1.Poles and Structures – FERC Subaccount 571.100
3.12.2.Insulators and Conductors – FERC
Subaccount571.200
3.12.2.1.Insulator Washing
3.12.2.2.Work Order Related Expenses
3.12.2.3.Insulator Replacement
3.12.3.Transmission Line Rights-of-Way – FERC Subaccount571.300
3.13.Operation Supervision and Engineering-FERC Account 580
3.13.1.FERC Subaccount 580.100
3.13.1.1.Engineering Advancement
3.13.1.2.Project Management Organization Work Order Write-Offs
3.13.1.3.Customer Service Business UnitSafety Activities
3.13.2.Internal Market Mechanism Distribution Operations & Engineering - FERC Subaccount 580.200
3.13.3.Meter Services Operations and Management - FERC Subaccount 580.300
3.13.4.Research Development and Demonstration
3.14.Distribution Substations – FERC Account582
3.15.Overhead Line Operations – FERC Subaccount 583.400
3.15.1.Overhead Detail Inspections
3.15.2.Pre-Construction Site Readiness Checks
3.15.3.Troublemen Accounting Changes
3.15.4.Distribution Wood Pole Inspections
3.16.Underground Line Expenses - FERC Account584
3.17.Meter Expenses - FERC Account 586
3.17.1.Meter Turn On and Off Services - FERC
Account586.100
3.17.2.Test or Inspect Meters - FERC Subaccount 586.400
3.18.Miscellaneous Distribution Expenses - FERC Account 588
3.18.1.Mapping Staff - FERC Subaccount 588.000
3.18.2.Management and Supervision - FERC
Subaccount588.300
3.18.2.1.Distribution Construction and Maintenance
Stand-by Time
3.18.2.2.Management and Supervision
3.18.2.3.Safety Activities
3.18.2.4.Design Joint Pole Staffing
3.18.2.5.Business Process and Technology Improvement Program/Job Orders
3.18.2.6.Reallocation of Overhead
3.18.3.Miscellaneous Other - FERC Account 588.800
3.18.3.1.Work Order Write-Offs
3.18.3.2.Non-Capital Furniture & Equipment
3.18.4.Service Guarantees – FERC Subaccount 588.900
3.19.Maintenance of Station Equipment - FERC Account 592
3.19.1.Maintenance of Distribution Circuit Breakers - FERC Subaccount 592.200
3.19.2.Maintenance of Station Equipment - FERC Subaccount592.400
3.19.2.1.Miscellaneous Substation Maintenance Labor Disconnect Repairs
3.19.2.2.Switchrack Lighting
3.19.2.3.Trench Covers
3.19.2.4.Steel Structures
3.20.Maintenance of Overhead Lines - FERC Account 593
3.20.1.Line Clearing Expenses-Tree Trimming
and Removal - FERC Subaccount 593.200
3.20.2.Overhead Line Maintenance - FERC
Subaccount 593.300
3.21.Maintenance of Underground Lines - FERC Account 594
3.21.1.Maintenance of Streetlight and Signal System -
FERC Subaccount 596.400
4.Customer Service
4.1.Expenses–Operations Division – FERC Accounts
901-905, 580, 586, 587, and 597
4.2.Vehicles – FERC Subaccounts 586.100, 586.400,
902.00, 903.00
4.3.Community Choice Aggregation – FERC Account 903
4.4.Rural Related Expenses and Ledgers – FERC
Subaccount903.000
4.5.Credit Fraud Staffing and GPS – FERC Subaccount 903.200
4.6.Service Guarantee Credits – FERC Subaccount 903.500
4.7.Electric Service Provider Services - FERC
Subaccount903.700
4.8.Customer Communication Organization – Phone
Center – FERC Subaccount 903.800
4.9.Uncollectible Expense – FERC Account 904
4.10.Market Research and Communication – FERC Subaccount905.900
4.11.Policy Adjustments-Miscellaneous – FERC
Subaccount905.300
4.12.Electric Transportation – FERC Subaccount 912.100
4.13.Energy Policy Act and Other Compliance
4.14.Load Management & Conservation
4.15.Safety
4.16.Customer Outreach
4.17.System Impact
4.18.Other Operating Revenues
4.18.1.Community Choice Aggregation – FERC Subaccount456.412
4.18.2.Residential Late Payment Charge – FERC
Account 450
4.18.3.Field Assignment Charge – FERC
Subaccount 451.600
4.18.4.Joint Pole Attachment Fees – FERC
Account 454.500
4.19.Tariff Rule 17-D Adjustment of Bill for Billing Errors
5.Information Technology Expenses-Computing Services
5.1.Information Technology Expenses-Computing Services -
Outside Services - FERC Account 923
5.2.Information Technology Expenses-Computing Services -
Salaries, Office Supplies, and Expenses - FERC
Accounts 920/921
5.3.Information Technology Expenses –NERC Critical
Infrastructure Protection
5.4.Information Technology Expenses -New
Technology Evaluation
6.Administrative & General Expenses
6.1.Total Compensation Study
6.2.Results Sharing - Short Term Incentives for Non-Executives - FERC Accounts 500, 588, 905 and 920/921
6.3.Spot Bonus and Awards to Celebrate Excellence Programs – FERC Accounts 566.200, 566.300, 580.100, 588.300, 588, and 920/921
6.4.Executive Compensation – FERC Accounts 920/921
and 923
6.5.Board of Directors and Corporate Governance – FERC
Account 930.2
6.6.Human Resources Department Expenses – FERC
Accounts 920, 921, 923, and 926
6.6.1.Talent Management - FERC Accounts 920/921
6.6.2.Outside Services – Total Compensation –
Client Services - FERC Account 923
6.6.3.Client Services - FERC Account 923
6.7.Pension and Benefits - FERC Account 926
6.7.1.Medical Program
6.7.2.Disability Programs
6.7.3.Miscellaneous Benefit Programs
6.7.4.Executive Pension and Benefits
6.7.5.Executive Benefits Retirement Severance Benefits
of Top Executives-FERC Accounts 920/921
6.8.Four Corners Pension and Benefits & Participant Credits
and Capitalized Pension and Benefit Expense – FERC
Accounts 925 and 926
6.9.Law Department Salaries and Related Expenses - FERC
Accounts 920/921
6.10.Outside Counsel - Outside Service - FERC Account 923
6.11.Claims
6.11.1.Additional Claims Personnel - FERC
Accounts 920/921
6.11.2.Additional Claims Reserves - FERC Account 925
6.12.Workers’ Compensation
6.12.1.Additional Workers’ Compensation Personnel -
FERC Account 925
6.12.2.Workers’ Compensation Reserve - FERC
Account 925
6.13.Ethics and Compliance - FERC Accounts920/921 and 923
6.14.Regulatory Policy and Affairs Department – FERC
Accounts 920/921
6.15.Financial Organizations
6.15.1.Controller’s Central Services and Corporate
Accounting Groups - FERC Accounts 920/921
6.15.2.Audit Services - FERC Accounts 920/921
6.15.3.Treasurer’s Organization - FERC
Accounts 920/921 and 930
6.16.Tax Department
6.17.Property and Liability Insurance
6.17.1.Corporate Property Insurance - FERC Account 924
6.17.2.Corporate Liability Insurance - FERC Account 925
6.18.Corporate Communications – FERC Accounts 920/921,
923 and 930
6.18.1.Forecast Methodology - FERC Accounts 920/921
6.18.2.Design Costs - FERC Account 930
6.19.Power Procurement Business Unit
6.19.1.MRTU New Software Applications – FERC Accounts920/921 and 923
6.19.2.Power Procurement Business Unit - FERC Accounts 920/921 and 923
6.20.Risk Control – FERC Accounts 920/921 and 923
6.21.Operations Support Business Unit – FERC
Accounts 920/921 and 923
7.Depreciation
8.Rate Base, Plant-In-Service, and Capital Expenditures
8.1.General Plant-In-Service Issues - Plant Weighting
8.2.Generation Capital
8.2.1.Nuclear Generation
8.2.2.Coal Generation
8.2.2.1.Four Corners
8.2.2.2.Mohave
8.2.3.Hydroelectric Generation
8.2.3.1.Big Creek and Poole Housing Projects
8.2.4.California Independent System Operator & Western Energy Coordinating Council Projects
8.2.5.Hydro Project Benefit/Cost Ratio
8.2.6.Lundy Powerhouse Project
8.2.7.Gas-Fired Generation
8.2.7.1.New Compressors
8.2.7.2.Spare Combustion Turbine
8.2.8.Pebbly Beach
8.3.Transmission & Distribution Capital
8.3.1.Customer Growth
8.3.1.1.Cost Per-Meter
8.3.1.2.Transformers
8.3.1.3.Customer Growth
8.3.2.Load Growth Capital Expenditures
8.3.3.Distribution Infrastructure Replacement
8.3.3.1.Deteriorated Distribution Pole Replacements
8.3.3.2.Suspected PCB Transformers
8.3.3.3.Street Light Replacement
8.3.3.4.Capacitor Bank & Switch Replacement
8.3.3.5.Deteriorated Underground Structure
Replacement
8.3.3.6.Underground Mainline Oil Switch
8.3.3.7.Underground Cable Replacement
8.3.3.8.Cable in Conduit Replacement Program
8.3.3.9.Worst Circuit Rehabilitation
8.3.4.Substation Infrastructure Replacement Program
8.3.4.1.Transformer A–Banks
8.3.4.2.Transformer B-Banks
8.3.4.3.Distribution Circuit Breakers
8.3.4.4.Distribution Protection & Control
8.3.4.5.Routine Capital Replacements
8.3.4.5.1On-Line Gas Monitoring For Bulk
Transformers
8.3.4.5.2.Rule 20B Circuit Breakers
8.3.4.5.3Overhead Lines
8.3.4.5.4Critical Electric Infrastructure
8.3.5.Reliability Investment Incentive Mechanism
8.3.6.Operational Technology
8.3.6.1.Phasor Measurement & Grid Stability System
8.3.6.2.Distribution Control & Monitoring System
8.3.6.3.Circuit Automation
8.3.6.4.Critical Video Substation Surveillance
8.3.6.5.Energy Management System
8.3.6.6.Centralized Remedial Action Scheme
8.3.7.Customer Requests
8.3.7.1.Purchase and Upgrade of Distribution
Systems on Military Bases
8.3.7.2.Rule 20A Conversions
8.4.Customer Service Capital
8.4.1.Structures and Improvements
8.4.2.Furniture and Equipment
8.4.3.Specialized Equipment
8.4.4.Meters
8.5.Information Technology & Enterprise Resource
Planning Capital
8.5.1.Enterprise Resource Planning Program
8.5.2.NERC Critical Infrastructure Project
8.5.3.Market Redesign and Technology Upgrade
8.6.Operations Support Capital – Corporate Real Estate
8.6.1.“Uncontested” Capital Projects Greater
Than $1 Million
8.6.2.DRA’s Recommendations for Larger Capital
Projects -Category1
8.6.3.TURN’s Recommendations for Larger Capital
Projects - Category 1
8.6.4.Approved Capital Expenditures for Larger Capital Projects
8.6.5.DRA’s Recommendations for Larger Blanket Work Orders - Category 2
8.6.6.Contingency Percentages Added to Cost Estimate
9.Rate Base - Other than Plant in Service
9.1.Working Cash – Revenue Lag Days
9.1.1.DRA Adjustment for Uncollectibles and
Averaging of Methods
9.1.2.TURN’s Adjustment for Meter to Service
Billing Lag
9.2.Working Cash – Federal Income and Corporate State
Taxes Lag Days
9.3.Working Cash – Pensions and PBOPs Lag Days
9.4.Working Cash – Minimum Cash Balance
9.5.Working Cash – Other Operational Cash Adjustments
9.5.1.Prepayments
9.5.2.Other Accounts Receivable
9.6.Unfunded Pension Reserves
9.7.T&D Materials and Supplies
9.8.Mohave Materials and Supplies
9.9.Mountainview Emission Credits
9.10.Working Cash – Customer Deposits
9.11.Differences Related to Other Issues
10.Market Redesign and Technology Upgrade
11.Distribution Service Request Pricing
12.SDG&E’s Request for SONGS Cost Recovery
13.Non-Tariffed Products and Services
14.Post-Test Year Ratemaking
14.1.Major Exogenous Cost Changes
14.2.Annual Advice Letter Filing
14.3.Nuclear Refueling Outages
15.Ratemaking Proposals
16.Kilowatt-hour Sales and Customer Forecasts
16.1.New Meters and Customer Forecasts
16.2.Sales
17.Philanthropy – Corporate Giving
18.Supplier Diversity
19.Workforce Diversity
20.Escalation Rates
21.Taxes
22.Audit
22.1.Privileged Audit Reports
22.2.Pre-Payments for Tax Consultants
22.3.Allowance for Funds Used During Construction
23.Proposed Settlements
23.1.Reliability Investment Incentive Mechanism Proposal
23.1.1.Responses to the RIIM Settlement
23.1.2.Discussion of Provisions for Capital Expenditures
23.1.3.Discussion of Provisions for Employee Targets
23.1.4.Conclusions Regarding RIIM Revision Proposal
23.2.Public Access Proposal
24.Purchase of Receivables
25.Comments on Proposed Decision
26.Assignment of Proceeding
Findings of Fact
Conclusions of Law
ORDER
APPENDIX A / List of AppearancesAPPENDIX B / Transportation Increase in O&M by Activity - Allocation of Forecast - $(000) 2006$
APPENDIX C / TY 2009 Revenue Requirement
APPENDIX D / Post-TY 2010 and 2011 Revenue Requirement
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A.07-11-011, I.08-01-026 ALJ/RMD/rbg/hkr **DRAFT
DECISION ON TEST YEAR 2009 GENERAL RATE CASE
FOR SOUTHERN CALIFORNIA EDISON COMPANY
1.Summary
This decision authorizes a $4.644 billion base revenue requirement for test year (TY) 2009 for Southern California Edison Company (SCE). We find that the authorized revenue requirement provides SCE with sufficient funding to provide safe and reliable service at just and reasonable rates. The adopted revenue requirement represents a 23.9% increase over the 2006 authorized revenue requirement of $3.749 billion, a 13.1% increase over SCE’s 2006 recorded base revenues of $4.106 billion, a 7.1% increase over the projected revenue at present rates of $4.334 billion, and an 10.78% reduction from the 2009 revenue requirement requested by SCE of $5.205 billion,[1] which represented a 20.1% increase over the projected revenues at present rates. The adopted methodology for calculating post-test year revenue requirement results in a revenue requirement for 2010 of $4.783 billion and for 2011 of $4.927 billion. As a result of our decision today, SCE’s projected total company revenue requirement for 2009 is approximately $12.4 billion. This proceeding is closed.
1.1.Forecast Test Year Ratemaking
Our decision today is guided by a fundamental tenet of forecast test year ratemaking that inclusion of a particular expense category in a general rate case (GRC) authorization does not create a specific obligation for the utility to spend the authorized amount during the test year. Utility management is generally provided discretion regarding use of funds and is not bound by the adopted forecast. However, as we have observed in prior decisions, there are limits to that management discretion and when a utility’s GRC expense estimate includes the performance of a task it had planned to accomplish with previously authorized funds, the Commission wants to know why the utility did not spend its funds as planned and we will be hesitant to charge ratepayers twice for the same expense.[2]
In this proceeding, SCE seeks additional funds for activities explicitly authorized by the Commission in the past. SCE seeks funds to redress maintenance postponed due to unanticipated load and customer growth in 20062007. To address this unforeseen customer and load growth, SCE diverted millions of dollars in capital replacements[3] away from its Infrastructure Replacement project, including funds for preventative maintenance of distribution and substation equipment, such as circuit breakers and other similar equipment. SCE also seeks funds related to the July 2006 “heat storms,” when approximately 1,300 distribution transformers were either damaged or destroyed.[4] Because of these and other circumstances, SCE spent approximately $300 million[5] more than authorized in its 2006 GRC, with a large percentage of this amount related to unanticipated customer growth needs.[6] In considering that SCE spent above amounts authorized in test year 2006, we also take into consideration that SCE’s authorized rate of return for 2006 was 8.77% and its recorded rate of return for 2006 was 8.70%. This 0.07% difference equals approximately $8.4 million.
SCE asks the Commission to find SCE’s explanation, unforeseen customer and load growth, justifies, in part, the magnitude of its requested increases. SCE explains, for example, that recorded 2006 capital additions were $1.463 billion and for 2009 SCE seeks $3.201 billion, an over 200% increase, to address, among other things, matters deferred because SCE directed funds to other areas impacted by unanticipated load and customer growth. SCE does not quantify the specific amount of funds diverted or identify any additional costs resulting from this decision to defer routine maintenance.
In the past we have found circumstances, such as the unanticipated scope of Year 2000 (Y2K) projects, to justify deferral of certain maintenance work. The circumstances surrounding Y2K and the related Y2K projects were one-time events and, as such, unique. In contrast, we do not find customer and load growth, even when unanticipated, to create unique circumstances. Load growth and customer growth are routine aspects of any rate case. If the adopted forecast overestimates expenses we do not ask a utility to return funds to ratepayers. Similarly, if an adopted forecast underestimates expenses, we do not go back and give the utility funds to complete projects that should have been addressed in the prior GRC cycle. In short, errors in forecasting occur and we do not go back and fix these errors.
Our policy has been explained by Justice Clark, dissenting, in Southern Cal. Edison Co. v. Pub. Util. Comm., (1978) 20 Cal.3d 813, 836, Justice Clark addressed matters related to errors in forecasting as follows: “If the estimated revenues were too high or the estimated costs too low, the utility will bear the loss and fail to recover the projected rate of return. On the other hand, if the estimated revenues are lower than those that actually occur or the estimated costs higher than actual costs, the utility will benefit. Because so many circumstances exist significantly affecting expense and revenue, it is to be anticipated that estimated costs and revenues will rarely, if ever, equal actual ones and that the utility will realize more or less than the predicted rate of return.”
It is also our policy that it would be unjust and unreasonable to make ratepayers responsible for expenses directly attributable to deficient or unreasonably deferred maintenance or to make ratepayers pay a second time for activities explicitly authorized by the Commission in the past. As we stated in Decision No. (D.) 82-12-055:
“For us to authorize Edison’s recovery of deferred maintenance expense would establish an undesirable precedent, whereby the utility is effectively guaranteed that it can earn (or exceed) its authorized rate of return, regardless of its operating efficiency or inefficiency, simply by curtailing current maintenance activities, in the assurance that they could be refinanced later through recovery of deferred maintenance expenses in a succeeding rate case.”