SCE-10 : Results of Operations (R/O) - Southern California Edison

Application No.:Exhibit No.: SCE-10, Vol. 01Witnesses:T. CameronR. GarwackiJ. GilliesP. HuntD. SnowA. VarvisR. Worden(U 338-E)2012 General Rate CaseResults of Operations (R/O)Volume 1 – Requested Revenue Requirements,Ratemaking, Sales Forecast, OOR, Cost Escalation,Post-Test Year RatemakingBefore thePublic Utilities Commission of the State of CaliforniaRosemead, CaliforniaNovember 2010

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of ContentsSection Page WitnessI. INTRODUCTION............................................................................................. 1 D. SnowII. RESULTS OF OPERATIONS.......................................................................... 2A. Results Of Operations At Present Rates................................................ 3B. Results Of Operations At Proposed Rates............................................. 8III. RATE PROPOSAL ......................................................................................... 10A. Proposed GRC Revenue Changes ....................................................... 10B. Consolidation Of Rate Changes .......................................................... 11IV. RECOVERY OF GRC RELATED REVENUE REQUIREMENTS ............. 13A. Ratemaking Overview......................................................................... 14B. Commission Jurisdictional Revenue Requirement ............................. 15 A. Varvis1. Transmission And Distribution Jurisdictional Study .............. 17a) Introduction ................................................................. 18b) Cost Separation Methodology..................................... 19(1) CAISO/Non-CAISO O&M CostSeparation Methodology ................................. 19(2) CAISO/Non-CAISO Other OperatingRevenue Separation Methodology .................. 19(3) CAISO/Non-CAISO Plant CostSeparation Methodology ................................. 19C. Functionalization Of Commission Jurisdictional RevenueRequirement ........................................................................................ 20D. SnowD. Recovery Of GRC Revenue Requirement .......................................... 24E. Miscellaneous Ratemaking Issues....................................................... 26-i-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page Witness1. Recovery Of Edison SmartConnect RevenueRequirement ............................................................................ 26a) Background ................................................................. 26b) 2012 Test Period.......................................................... 27c) Forecast Included in 2013 GRC RevenueRequirement ................................................................ 27d) Modification to the ESCBA ........................................ 28e) Delay in Deployment Period ....................................... 28f) Demonstration of No Double Recovery...................... 292. Recovery Of SCE’s Share Of The Solar PhotovoltaicProgram ................................................................................... 293. Recovery Of Market Redesign And TechnologyUpgrade (MRTU) Revenue Requirement ............................... 304. Recovery Of Four Corners Revenue Requirement ................. 315. Recovery Of Fuel Cell Program RevenueRequirement ............................................................................ 346. Continuation Of The Mohave Balancing Account(MBA) ..................................................................................... 357. Continuation Of The Post-Retirement Benefits OtherThan Pensions Balancing Account (PBOPBA) ...................... 358. Continuation Of The Pensions Cost BalancingAccount (PCBA) ..................................................................... 369. Continuation Of Research, Development AndDemonstration Adjustment Clause (RDDAC)........................ 3610. Continuation of the Employee Stock Option Plan TaxMemorandum Account (ESOPTMA) ..................................... 36-ii-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page Witness11. Continuation Of Reliability Investment IncentiveMechanism (RIIM).................................................................. 3712. Interaction With Other Proceedings........................................ 38a) 2007 Wind and Firestorm Catastrophic EventsMemorandum Account Cost RecoveryProceeding................................................................... 38b) Fire Hazard Prevention MemorandumAccount (FHPMA)...................................................... 39c) SONGS 2&3 Steam Generator ReplacementCost Recovery ............................................................. 39d) Four Corners Capital ExpenditureMemorandum Account (FCCEMA)............................ 4013. Elimination Of Six Ratemaking Accounts .............................. 40a) Project Division Development MemorandumAccount (PDDMA) ..................................................... 40b) Results Sharing Memorandum Account(RSMA)....................................................................... 41c) Medical Program Balancing Account(MPBA)....................................................................... 41d) Palo Verde O&M Balancing Account(PVO&MBA) .............................................................. 41e) Community Choice Aggregators’ImplementationCost Balancing Account(CCAICBA) ................................................................ 42f) Non-Discretionary Services CostMemorandum Account (NDSCMA)........................... 42V. SALES AND CUSTOMER FORECAST....................................................... 43 J. GilliesA. Sales Forecast Summary ..................................................................... 43-iii-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page WitnessB. Methodology ....................................................................................... 43C. Historical Trends ................................................................................. 44D. Economic Outlook............................................................................... 46E. Weather Assumptions ......................................................................... 47F. Other Factors Influencing the Forecast ............................................... 48G. Total Retail Sales Forecast by Customer Class................................... 49H. Customer and New Meter Connection Forecasts................................ 50I. September 2009 Forecast of Customers and New MeterConnections......................................................................................... 51VI. PRESENT RATE REVENUE ........................................................................ 53 R. GarwackiA. Total System Present Rate Revenue.................................................... 531. Methodology For The Development Of Total SystemPresent Rate Revenue Estimates ............................................. 53a) Forecast Of Sales......................................................... 53b) Revenue Class And Rate Group StatisticalData ............................................................................. 53c) Forecast Of Billing Determinants By RateSchedule ...................................................................... 55(1) Description Of ForecastingMethodology ................................................... 55(2) Forecast Of Billing Determinants ................... 552. Total System Present Rate Revenue Forecast ......................... 56B. GRC Present Rate Revenue................................................................. 57 D. Snow1. Determination Of The GRC Present Rate Revenue ................ 572. GRC Present Rate Revenue Forecast ...................................... 58-iv-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page WitnessVII. COST ESCALATION..................................................................................... 60 T. CameronA. O&M Cost Escalation ......................................................................... 601. Purpose .................................................................................... 602. Escalation Rates ...................................................................... 60a) Labor ........................................................................... 60b) Nonlabor...................................................................... 623. Methodology and Estimates .................................................... 63a) Labor Escalation.......................................................... 63(1) Historical period -2005 Through 2009............ 63(2) Forecast Period 2010 - 2014............................ 63b) Nonlabor Escalation .................................................... 64(1) Global Insight Indexes .................................... 64(2) Adjustment of Nonlabor EscalationRates To Reflect Labor Costs Bookedin Nonlabor Expense ....................................... 64(3) Nonlabor Escalation For Palo Verde............... 65(4) Nonlabor Escalation For Four Corners ........... 66(5) Health Care Escalation.................................... 66B. Capital Cost Escalation ....................................................................... 671. Purpose .................................................................................... 672. Escalation Rates ...................................................................... 67a) Capital ......................................................................... 68-v-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page Witness(1) Adjustment of Escalation Rates toReflect Labor Included in CapitalExpenditures.................................................... 68VIII. OTHER OPERATING REVENUE ................................................................ 70 D. SnowA. Account-By-Account Summary Of OOR ........................................... 701. Revenue Account 450 – Forfeited Discounts.......................... 712. Revenue Account 451 – Miscellaneous ServiceRevenues ................................................................................. 713. Revenue Account 453 – Sales of Water and Power................ 724. Revenue Account 454 – Rent From Electric Property............ 725. Revenue Account 456 – Other Electric Revenues .................. 726. Other OOR .............................................................................. 72a) Non-Tariffed Products And Services .......................... 72b) Revenues With Specific Treatment............................. 73c) Gain Or Loss On Sale Of Property.............................. 73B. Added Facilities Rates......................................................................... 73IX.SUMMARY OF OPERATION AND MAINTENANCEEXPENSES BY FERC ACCOUNT ............................................................... 76A. Operation And Maintenance Expense Forecast DevelopmentAnd Summary By FERC Account ...................................................... 77B. General Ledger/CARS/SAP................................................................ 78C. GRC O&M Data Management............................................................ 81D. Adjustments Included In Business Unit Activities ............................. 821. Company-Wide Adjustments Included In BusinessUnit Activities ......................................................................... 82-vi-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page Witnessa) Ratemaking Treatment For Non-Utility-Related Expenses......................................................... 822. Business Unit Adjustments ..................................................... 83E. Analyze Forecasting Options And Business Needs ............................ 84F. 2012 O&M Forecast............................................................................ 85G. Summary Of Results ........................................................................... 85X. POST-TEST YEAR RATEMAKING ............................................................ 94 P. HuntA. Background ......................................................................................... 951. Rate Case Plan......................................................................... 952. Operational Cost Changes....................................................... 96B. Need For Revenue Requirement Increases ......................................... 961. Inflation And Productivity ...................................................... 962. Enhancing SCE’s Financial Standing ..................................... 97C. Features Of Our Proposed Mechanism ............................................... 981. Annual PTYR Mechanism Advice Letter ............................... 982. O&M Escalation...................................................................... 98a) Latest Global Insight Escalation Rates WillBe Used ....................................................................... 98b) Escalation Rates Will Be “Trued Up” ToActual, But Previous Forecast Errors Will NotBe Recovered Or Refunded......................................... 99c) Other Differences From Escalation RatesCalculated Through The Test Year ............................. 99d) Projected Labor And Non-Labor EscalationRates For 2013 And 2014............................................ 99-vii-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingTable Of Contents (Continued)Section Page Witnesse) Benefit Escalation Rates............................................ 1003. Capital-Related Cost Increases.............................................. 1004. Nuclear Refueling Outages ................................................... 1015. Treatment Of Major Exogenous Cost Changes..................... 1026. The Commission Should Not Require An ApplicationTo Implement Post Test year Ratemaking ............................ 102D. SCE’s Proposed Capital Expenditure Program Will ProvideA Much-Needed Boost To The California Economy........................ 1031. Overall Economic Impact...................................................... 1032. Regional Economic Impact ................................................... 104E. The Post-Test Year Mechanism Adopted In SCE’s 2009GRC Contains Two Fundamental Analytic Errors ThatShortchanged SCE’s Revenue Requirement ..................................... 105R. Worden1. The “Stranded” Construction Work In Progress ErrorIn The 2009 GRC Adopted Post-Test YearRatemaking Formulas ........................................................... 1082. By Not Providing For Separate Escalation Of TheOther Operating Revenues From Tariffed Services,the 2009 GRC’s Post-Test Year RatemakingMechanism Shortchanged the Authorized RevenueRequirement .......................................................................... 111Appendix A Witness Qualifications................................................................................Appendix B Productivity Gains Offset O&M Cost Increases.........................................Appendix C Economic Benefits of Proposed Capital Expenditures by theSouthern California Edison Company.................................................................Appendix D Economic Development Impact Analysis, SCE CapitalInvestment Program ............................................................................................Appendix E......................................................................................................................-viii-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingList Of FiguresFigurePageFigure II-1 Southern California Edison Company Requested CPUC-Jurisdictional RevenueRequirements ($millions)...................................................................................................................... 3Figure IV-2 Southern California Edison Company Bundled Service Customers AverageRates As of March 1, 2010 (cents/kWh) ............................................................................................. 15Figure V-3 Total Non-Farm Employment Growth in the SCE Service Area ........................................... 45Figure V-4 Residential Building Permits in the SCE Service Area.......................................................... 46Figure V-5 Total Non-Farm Employment Growth in SCE Service Area, Actual andForecast ............................................................................................................................................... 47Figure V-6 Recorded and Normal Cooling Degree Days ......................................................................... 48Figure V-7 Average System Electricity Price, Actual and Forecast ......................................................... 49Figure IX-8 Expense Forecast Development ............................................................................................ 77Figure IX-9 O&M: Natural vs. FERC....................................................................................................... 80Figure X-10 Illustrative Revenue Requirement Example ....................................................................... 107Figure X-11 2009 GRC CapEx Constant 2010 & 2011 (CPUC Jurisdiction) ........................................ 109-ix-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingList Of TablesTablePageTable II-1 Southern California Edison Company Results Of Operations At Present RatesExcluding Rate Requests Included In This Filing ($000) ..................................................................... 6Table II-2 Southern California Edison Company Summary of Approved and ForecastABRR Changes Excluding Rate Requests Included In This Filing ($000) ......................................... 7Table II-3 Southern California Edison Company Summary of Total Operating RevenuesExcluding Rate Requests Included In This Filing ($000) ..................................................................... 7Table II-4 Southern California Edison Company Results of Operations At Proposed RatesCommission Jurisdictional ($000) ....................................................................................................... 9Table III-5 Southern California Edison Company 2012, 2013, and 2014 Revenue ChangesResulting From the 2012 Test Year and 2013 and 2014 PTYR GRC RequestCommission Jurisdictional ($000) ..................................................................................................... 11Table IV-6 Jurisdictional Split Methodology By RO Cost Component ................................................... 16Table IV-7 CPUC-Jurisdictional Factors And Revenue Requirements ($000) ....................................... 17Table IV-8 2012 Results of Operation at Proposed Rates Functionalized ($000) ................................... 22Table IV-9 2013 Results of Operation at Proposed Rates Functionalized ($000) ................................... 23Table IV-10 2014 Results of Operation at Proposed Rates Functionalized ($000) ................................. 24Table IV-11 2012 Results of Operation – Four Corner’s Scenario Comparison ($000) ......................... 33Table IV-12 2013 and 2014 Results of Operation – Four Corner’s Scenario Comparison($000) .................................................................................................................................................. 34Table V-13 Annual Retail Sales by Customer Class (GWh) .................................................................... 50Table V-14 Year-End Customers by Customer Class............................................................................... 50Table V-15 New Gross Meter Connections .............................................................................................. 51Table V-16 September 2009 Forecast of Year-End Customers by Customer Class................................. 51Table V-17 September 2009 Forecast of New Gross Meter Connections ................................................ 52Table VI-18 Revenue Classes By Rate Group .......................................................................................... 55Table VI-19 Average Customers, Sales And Total System Present Rate Revenue 2009through 2014 ....................................................................................................................................... 57Table VI-20 TSPRR and GRCPRR Cost Components............................................................................. 58-x-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingList Of Tables (Continued)TablePageTable VI-21 Average Customers, Sales and GRC Present Rate Revenue 2010 through 2014................. 59Table VII-22 O&M Labor Price Indexes And Escalation Rates............................................................... 61Table VII-23 O&M Nonlabor Price Indexes And Escalation Rates ......................................................... 62Table VII-24 Correspondence Between Employee Categories And UCIS Variables .............................. 64Table VII-25 Percentage of Nonlabor Expense That is Actually Labor Expense..................................... 65Table VII-26 Palo Verde Nonlabor Escalation ......................................................................................... 66Table VII-27 Four Corners Nonlabor Escalation...................................................................................... 66Table VII-28 Capital Escalation Rates...................................................................................................... 68Table VII-29 Percentage of Capital Expenditure That is Actually Labor Expense ................................. 69Table VIII-30 Other Operating Revenue Nominal ($000)........................................................................ 71Table VIII-31 Added Facilities Rate Components.................................................................................... 74Table IX-32 Summary of O&M Expense Exhibits................................................................................... 76Table IX-33 Examples of Cost Elements/Corresponding G/L Accounts ................................................. 79Table IX-34 Southern California Edison Company Test Year 2012 General Rate CaseOperations & Maintenance Expenses Category: Total O&M Expenses ($000)................................. 86Table IX-35 Southern California Edison Company Test year 2012 General Rate CaseOperation & Maintenance Expenses Category: Generation Expenses ($000).................................... 87Table IX-36 Southern California Edison Company Test Year 2012 General Rate CaseOperation & Maintenance Expenses Category: Transmission Expenses ($000)................................ 89Table IX-37 Southern California Edison Company Test Year 2012 General Rate CaseOperation & Maintenance Expenses Category: Distribution ($000) ................................................. 90Table IX-38 Southern California Edison Company Test Year 2012 General Rate CaseOperation & Maintenance Expenses Category: Customer Accounts Expenses ($000)...................... 91Table IX-39 Southern California Edison Company Test Year 2012 General Rate CaseOperation & Maintenance Expenses Category: Customer Service and Information andSales Expenses ($000)......................................................................................................................... 92-xi-

SCE-10 : Results of Operations (R/O)Volume 01 - Requested Revenue Requirements, Ratemaking, SalesForecast, OOR, Cost Escalation, Post- Test Year RatemakingList Of Tables (Continued)TablePageTable IX-40 Southern California Edison Company Test Year 2012 General Rate CaseOperation & Maintenance Expenses Category: Administrative and General Expenses($000) .................................................................................................................................................. 93Table X-41 Benefit Escalation Rates ...................................................................................................... 100Table X-42 Proposed Capital Additions, 2013-2014 ($ millions) .......................................................... 101Table X-43 Overall Economic Impacts From SCE’s Proposed Capital Expenditures, 2010-2014................................................................................................................................................... 104Table X-44 Regional Economic Impacts From SCE’s Proposed Capital Expenditures,2010-2014.......................................................................................................................................... 105-xii-

12345678910111213141516171819202122232425I.INTRODUCTIONThe chapters that comprise this Volume 1 of Southern California Edison Company’s (SCE)Results of Operations (RO) exhibit address several related subjects. First, in Chapter II, Douglas Snowsummarizes the revenue requirement SCE has identified for the 2010-2014 forecast period. In Chapter III,Mr. Snow summarizes SCE’s General Rate Case (GRC)-related revenue change and proposal toconsolidate total system 2012 revenue requirements. In Chapter IV, Mr. Snow presents SCE’s proposalfor recovery of the GRC revenue requirement, including recovery of Edison SmartConnect TM deploymentcosts beginning in 2013 and two revenue requirement scenarios related to SCE’s proposal to end itsownership share of the Four Corners Generating Station. Also included in that chapter, Alan Varvispresents SCE’s Transmission & Distribution (T&D) Jurisdictional Study, which is used to split totalforecast costs between those subject to the jurisdiction of this Commission and those subject to thejurisdiction of the Federal Energy Regulatory Commission (FERC).In Chapter V, John Gillies presents SCE’s 2010-2014 forecasts of the grid kilowatt-hour sales itexpects to deliver to customers within its service territory (i.e., sales to bundled customers plus directaccess customers). In Chapter VI, Russell Garwacki presents SCE’s estimates of the revenues that wouldresult from application of SCE’s currently authorized rates to the sales forecast presented by Mr. Gillies.In Chapter VII, Todd Cameron presents SCE’s 2005-2009 recorded and 2010-2014 forecasts of costescalation rates. The cost escalation rates are used in SCE’s RO model to convert recorded costs toconstant 2009 dollars and to escalate forecasts presented in 2009 dollars to forecast, or Test Year dollars.In Chapter VIII, Mr. Snow presents SCE’s estimates of Other Operating Revenue (OOR), which offsetsthe base revenue requirement to be collected from SCE’s customers. In Chapter IX, Mr. Snowsummarizes the total Operation and Maintenance (O&M) expenses presented throughout this application.Finally, in Chapter X, Dr. Hunt, and Russell Worden presents SCE’s proposals for Post Test YearRatemaking (PTYR).1

1234567891011121314151617181920212223242526272829II.RESULTS OF OPERATIONSThis chapter first presents SCE’s base related 1 total system summary of earnings (i.e., Results ofOperations) for the recorded year 2009 and forecast years 2010 through 2012 at present rates (as definedin Part A below). In addition, this chapter presents SCE’s base-related CPUC-jurisdictional Results ofOperations (RO) for the forecast years 2012 through 2014 at present rates. The RO at present ratesidentifies the expected rate of return on SCE’s operations absent the rate relief requested in thisApplication. This chapter next presents, for each forecast year 2012 through 2014, the CPUCjurisdictionalRO at present rates compared to proposed rates in order to determine SCE’s requestedincremental revenue requirement. The results presented in this chapter summarize the revenues, operatingexpenses, and investment-related costs identified in the other volumes and chapters of this exhibit andaccompanying exhibits of this Application.Figure II-1, below, summarizes SCE’s requested CPUC-jurisdictional revenue requirements andassociated incremental revenue requirement changes for the forecast years 2012 through 2014. Therequested revenue requirement will give SCE a reasonable opportunity to recover anticipated O&Mexpenses (including A&G expenses) and capital costs associated with expected rate base amounts, therebygiving SCE a reasonable opportunity to realize earnings at the current Commission-authorized rate ofreturn. The requested revenue requirement presented in Figure II-1 (and in the subsequent sections of thisChapter) assumes:1) SCE’s Share Sold Case (“Sale”) for Four Corners Generating Station;2) inclusion of the revenue requirement associated with the implementation of the MarketRedesign and Technology Upgrade (MRTU) project;3) inclusion of the revenue requirement associated with SCE’s share of the Solar PV Programauthorized in D.09-06-049;4) inclusion of the revenue requirement associated with the Fuel Cell Program authorized inD.10-04-028;5) a “business-as-usual” revenue requirement in 2012 that excludes the incremental revenuerequirement associated with the deployment of the Edison SmartConnect program authorizedin D.08-09-039;1 Base-related costs include distribution and generation O&M, A&G, and depreciation, return, and taxes (excluding fuel andpurchased power costs recovered through the Energy Resource Recovery Account (ERRA).2

123456) inclusion of the Edison SmartConnect deployment revenue requirement in 2013 and 2014;and,7) continued recovery of SCE’s share of the Mohave Generating Station. 2Chapter III of this volume presents the revenue changes and estimated rate impacts associated withthe revenue requirements presented in this Chapter.Figure II-1Southern California Edison CompanyRequested CPUC-Jurisdictional Revenue Requirements($millions)$8,000$612$7,496$7,000$6,000$5,347$938$6,285$6,537$347$6,884$5,000$4,000$3,000$2,000$1,000$02012 ExcludingGRC RequestRevenueRequirementChange2012 Request 2012 RequestAdj forSmartConnectRevenueRequirementChangeEstimated 2013RevenueRequirementChange** As explained in testimony, SCE is including recovery of the Edison SmartConnect meter revenue requirementauthorized in D.08-09-039 in SCE’s GRC revenue requirement beginning in 2013. Therefore, to isolate therevenue requirement change requested in this proceeding, SCE is including an estimated 2012 EdisonSmartConnect revenue requirement of $251 million that has already been authorized by the Commission inD.08-09-039.Estimated 2014678A. Results Of Operations At Present RatesSCE’s RO at present rates for the recorded year 2009 and estimated years 2010 through 2014 ispresented in Table II-1. 3 The amount shown for recorded years 2009 and forecast years 2010 through2 As discussed in SCE-10, Volume 3, SCE is proposing to recover the remaining net plant by the end of 2016.3 Operating expenses included in the RO tables presented in this chapter for the years 2013 and 2014 were calculated basedon the Post Test Year Ratemaking Mechanism described in Chapters IV and XI of this volume. The final 2013 and 2014revenue requirements will be determined through the operation of the Commission-approved Post Test Year RatemakingMechanism and submitted to the Commission in November 2012 and 2013 prior to implementation in 2013 and 2014,(Continued)3

123456789101112131415161718192021222012 reflects base-related total system revenue requirements that include FERC-jurisdictionaltransmission-related revenues, operating costs, and capital costs. To determine the RO at present ratesshown on Table II-1, SCE has removed all FERC jurisdictional transmission-related revenues and costs. 4As discussed above, SCE is requesting to recover the revenue requirement of several projects theCommission has authorized outside of SCE’s GRC (e.g., SCE’s share of the Solar PV program). In orderto appropriately calculate the RO at present rates consistently throughout the 2009 through 2014 period,both the cost and the associated revenue are included. Therefore, as discussed below, SCE is makingadjustments to its currently Authorized Base Revenue Requirement (ABRR) 5 to include the incrementalrevenue requirement associated with these projects.For the recorded year 2009, Table II-1 shows the base-related total system RO using operatingrevenues including:1) the presently effective ABRR, excluding revenues associated with one SONGS 2&3refueling and maintenance outages in the amount of $47.16 million, 6 and2) recorded FERC-jurisdictional base transmission revenues.For the forecast year 2010, Table II-1 shows the base-related total system RO using operating revenuesincluding:1) the presently effective ABRR; 72) an estimated 2010 revenue requirement associated with the MRTU project; and,3) estimated FERC-jurisdictional base transmission revenues based on present rate levels.For the forecast year 2011, Table II-1 shows the base-related total system RO using operating revenuesincluding:1) the presently effective ABRR;Continued from the previous pagerespectively. As such, the revenue requirements shown for years 2013 and 2014 are estimated and will change uponimplementation pursuant to the authorized Post Test Year Ratemaking Mechanism.4 SCE’s methodology to determine the base-related CPUC-jurisdictional revenue requirement is described in Chapter IV ofthis volume.5 The ABRR is comprised of the Authorized Distribution Base Revenue Requirement (ADBRR), and the AuthorizedGeneration Base Revenue Requirement (AGBRR),6 The 2009 recorded operating expenses shown in Table II-1 include no costs associated with SONGS 2&3 refueling andmaintenance outages.7 The estimated operating expenses shown in Table II-1 for the years 2010 and 2011 include no costs associated withSONGS 2&3 refueling and maintenance outages.4

123456789101112131415161718192021222324252627282) an estimated 2011 revenue requirement associated with the MRTU project; and,3) an estimated 2011 revenue requirement associated with SCE’s share of the SolarPhotovoltaic Program authorized in D.09-06-049.For the forecast year 2012, Table II-1 shows the base-related total system RO using operating revenuesset at:1) the presently effective ABRR;2) the authorized revenue requirement associated with one SONGS 2&3 refueling andmaintenance outage in the amount of $51.3 million; 83) an estimated 2012 revenue requirement associated with the MRTU project;4) an estimated 2012 revenue requirement associated SCE’s share of the SolarPhotovoltaic Program;5) an estimated 2012 revenue requirement associated with the Fuel Cell Programauthorized in D.10-04-028; and,6) estimated FERC-jurisdictional base transmission revenues based on present rate levels.For the forecast year 2013, Table II-1 shows the base-related total system RO using operating revenuesset at:1) the same ABRR estimated for 2012: and,2) an estimated 2013 revenue requirement associated with Edison SmartConnectdeployment project that has been recovered outside of the GRC revenue requirementthrough 2012.The estimated CPUC-jurisdictional RO for the years 2013 and 2014 all utilize the applicable yearendforecast ABRR for base-related operating revenues. Table II-2 in this chapter supports the CPUCjurisdictionalbase-related operating revenues (i.e. ABRR) used in the RO calculations for the years 2009through 2014 as shown on Table II-1. Table II-3 in this chapter shows the ABRR and FERC-jurisdictionalbase transmission revenues that comprise the Operating Revenues included in Table II-1 in this chapter.Chapter VI (Present Rate Revenues) of this volume supports the estimated FERC-jurisdictional basetransmission revenues used in the RO calculation for the years 2009 through 2012 as shown on Table II-1and Table II-3.8 Currently authorized refueling revenue requirement for 2010 in the amount of $49.2 million escalated by the 2010 revenuerequirement escalation percentage authorized in D.09-03-025 of 4.35%, which results in a 2011 refueling revenuerequirement of $51.3 million.5

123456789For purposes of determining the RO calculations at present rates shown on Table II-1, the ABRRunder the Base Revenue Requirement Balancing Account (BRRBA) ratemaking mechanism is used inplace of the forecast base-related revenues at present rate levels as contained in Chapter VI 9 of thisvolume. The reason for this is that the ABRR is the amount of base-related revenue authorized by theCommission to be recovered by SCE during the applicable calendar year. The general purpose of BRRBAis to reflect in rates any differences between the recorded level of base-related revenue and the ABRR.Therefore, the use of the ABRR for forecasted present rate revenue in the RO calculations presents a moreaccurate estimate of the rate of return that would result by using present rate revenues calculated atpresent rate levels as shown in Chapter VI of this volume.Table II-1Southern California Edison CompanyResults Of Operations At Present RatesExcluding Rate Requests Included In This Filing($000)Line Recorded EstimatedFERC CPUC-GRC CPUC-GRC CPUC-GRCNo. Item 2009 2010 2011 2012 2012 2012 2013 20141. TOTAL OPERATING REVENUES 5,205,788 5,536,819 5,814,174 5,918,979 571,442 5,347,537 5,598,840 5,598,8402. OPERATING EXPENSES:3. Production4. Steam 63,194 71,496 59,521 63,329 - 63,329 63,329 63,3295. Nuclear 363,198 359,541 373,717 405,852 - 405,852 405,852 405,8526. Hydro 46,372 50,845 52,294 57,610 - 57,610 57,610 57,6107. Other 112,448 109,625 117,600 143,089 - 143,089 143,089 143,0898. Subtotal Production 585,212 591,507 603,132 669,880 - 669,880 669,880 669,8809. Transmission 162,289 170,167 190,320 191,590 97,441 94,149 94,149 94,14910. Distribution 453,033 487,092 480,789 511,292 6,515 504,777 493,688 493,68811. Customer Accounts 193,442 197,494 202,283 213,822 - 213,822 193,452 193,45212. Uncollectibles 11,258 13,288 13,954 13,554 1,309 12,246 12,821 12,82113. Customer Service & Information 42,165 44,120 46,715 50,069 - 50,069 53,356 53,35614. Administrative & General 791,265 878,959 937,589 1,026,058 47,531 978,526 982,367 993,52115. Franchise Requirements 40,327 50,141 52,653 53,638 5,178 48,459 50,737 50,73716. Revenue Credits (186,028) (192,289) (197,549) (187,091) (33,849) (153,242) (161,604) (164,599)17. Subtotal 2,092,963 2,240,480 2,329,886 2,542,812 124,126 2,418,687 2,388,845 2,397,00518. Escalation - 56,095 117,621 187,379 9,904 177,474 251,311 322,68119. Depreciation 1,061,115 1,182,833 1,317,698 1,577,129 143,236 1,433,893 1,679,873 1,939,81920. Taxes Other Than On Income 241,424 258,018 277,233 298,667 34,636 264,031 280,087 302,43921. Taxes Based On Income 498,076 450,814 415,772 196,356 29,270 167,086 76,311 (62,433)22. Total Taxes 739,500 708,832 693,004 495,023 63,907 431,117 356,398 240,00623. TOTAL OPERATING EXPENSES 3,893,579 4,188,239 4,458,211 4,802,343 341,173 4,461,171 4,676,428 4,899,51124. NET OPERATING REVENUE 1,312,209 1,348,580 1,355,963 1,116,636 230,270 886,366 922,412 699,32925. RATE BASE 13,743,911 15,294,251 16,952,870 19,392,507 2,890,791 16,501,716 18,901,148 20,519,13526. RATE OF RETURN 9.55% 8.82% 8.00% 5.76% 7.97% 5.37% 4.88% 3.41%9 Chapter VI of this volume presents both base-related (i.e., GRC-related) present rate revenues and total system (includingSCE fuel and purchased power and Department of Water Resources procurement) present rate revenues.6

Table II-2Southern California Edison CompanySummary of Approved and Forecast ABRR ChangesExcluding Rate Requests Included In This Filing($000)ABRR ComponentAmountAuthority1. 2009 ABRR:2. 01/1/09 - Authorized Distribution Base Revenue Requirement (ADBRR) 3,341,130 D.09-03-025; Advice Letter 2336-E3. 01/1/09 - Authorized Generation Base Revenue Requirement (AGBRR) 1/ 1,488,612 D.09-03-025; Advice Letter 2336-E4. Less: SONGS 2&3 Refuelings included in 2009 AGBRR 47,160 D.09-03-025; Advice Letter 2336-E5. 2009 ABRR without SONGS 2&3 Refuelings 2/ 4,782,5826. 01/01/10 - Post Test Year Ratemaking (PTYR) Changes:7. ADBRR 141,998 D.09-03-025; Advice Letter 2396-E-A8. AGBRR 61,262 D.09-03-025; Advice Letter 2396-E-A8. Add: 1/1/10 - MRTU 14,400 A.10-04-002 (ERRA Review Proceeding)9. 2010 ABRR with zero SONGS 2&3 Refuelings 3/ 5,000,24210. 01/01/11 - Post Test Year Ratemaking (PTYR) Changes:11. ADBRR 151,107 D.09-03-025 (2010 escalation by 4.35%) AL 2519-E-A12. AGBRR 4/ 65,368 D.09-03-025 (2010 escalation by 4.35%)13. Add: 1/1/11 - Solar PV Program 33,936 D.09-06-04914. Estimated December 31, 2011 ABRR 5,250,65315. Add: One SONGS 2&3 Refueling 51,304 D.09-03-025 (2009 esc. 4.25%, 2010 esc.4.35%)17. 1/1/12 - Solar PV Program (incremental increase) 41,093 D.09-06-04918. 1/1/12 - Fuel Cell Program 4,487 D.10-04-02819. Estimated December 31, 2012 ABRR 5/ 5,347,53720. Add: 1/1/13 - Edison SmartConnect Deployment 251,303 D.08-09-03921. Estimated December 31, 2013 ABRR 5,598,84022. Estimated December 31, 2014 ABRR 5,598,8401/ Includes one SONGS 2&3 refuelings2/ Excludes SONGS 2&3 refuelings3/ 2010 ABRR with one SONGS 2&3 refueling: $5.035 billion (i.e. Currently effective ABRR)4/ Includes zero SONGS 2&3 refueling5/ Includes one SONGS 2&3 refuelingTable II-3Southern California Edison CompanySummary of Total Operating RevenuesExcluding Rate Requests Included In This Filing($000)2009 2010 2011 2012 2013 2014ABBR 4,782,582 5,000,242 5,250,653 5,347,537 5,598,840 5,598,840FERC 423,206 536,577 563,521 571,442 582,569 591,967TOTAL 5,205,788 5,536,819 5,814,174 5,918,979 6,181,409 6,190,8077

123456789B. Results Of Operations At Proposed RatesTable II-4 presents SCE’s requested revenue requirements for the years 2012 through 2014. TheROs at present rates show that SCE will need $6.285 billion, $6.884 billion, and $7.496 billion inCommission-jurisdictional base-related revenue in the years 2012, 2013, and 2014, respectively, to coverthe costs of doing business and to realize earnings at the Commission-authorized rate of return. SCE’scurrently authorized rate of return on rate base is 8.75 percent. 10 The incremental revenue requirement(i.e., ABRR) and associated revenue changes necessary to provide SCE with a reasonable opportunity toearn an 8.75 percent rate of return for the years 2012 through 2014 are discussed in Chapter III of thisvolume.10 SCE’s currently effective rate of return was authorized by the Commission in D.09-10-016 and defers SCE’s next full costof capital application to April 20, 2012, for a Test Year 2013 return on equity.8

Table II-4Southern California Edison CompanyResults of Operations At Proposed RatesCommission Jurisdictional($000)LineGRC - CPUCNo. Item 2012 2013 20141. TOTAL OPERATING REVENUES 6,285,299 6,883,781 7,495,9072. OPERATING EXPENSES:3. Production4. Steam 63,329 63,329 63,3295. Nuclear 405,852 405,852 405,8526. Hydro 57,610 57,610 57,6107. Other 143,089 143,089 143,0898. Subtotal Production 669,880 669,880 669,8809. Transmission 94,149 94,149 94,14910. Distribution 504,777 493,688 493,68811. Customer Accounts 213,822 193,452 193,45212. Uncollectibles 14,393 15,764 17,16613. Customer Service & Information 50,069 53,356 53,35614. Administrative & General 978,526 982,367 993,52115. Franchise Requirements 56,957 62,381 67,92816. Revenue Credits (153,242) (161,604) (164,599)17. Subtotal 2,429,332 2,403,432 2,418,54018. Escalation 177,474 251,311 322,68119. Depreciation 1,433,893 1,679,873 1,939,81920. Taxes Other Than On Income - Property 172,275 187,712 207,09021. Taxes Other Than On Income - Payroll 91,756 92,374 95,34822. Taxes Based On Income 536,668 615,227 717,00323. Total Taxes 800,699 895,314 1,019,44124. TOTAL OPERATING EXPENSES 4,841,398 5,229,930 5,700,48225. NET OPERATING REVENUE 1,443,900 1,653,851 1,795,42526. RATE BASE 16,501,716 18,901,148 20,519,13527. RATE OF RETURN 8.75% 8.75% 8.75%9

123456789101112131415161718192021III.RATE PROPOSALA. Proposed GRC Revenue ChangesIn this Application SCE requests that the Commission adopt a 2012 base-related CPUCjurisdictionalrevenue requirement of Authorized Base Revenue Requirement of $6.285 billion (aspresented in Chapter II of this Volume). Based on SCE’s estimate of ABRR changes that were previouslyapproved by the Commission SCE estimates that its December 31, 2012 ABRR will be $5.347 billion. 11When the estimated impact of these previously approved ABRR changes are considered, an ABRRincrease of $938 million for 2012 is attributable to this Application. After taking into account the forecastCPUC-jurisdictional base-related revenue growth between 2011 and 2012, 12 the revenue changeattributable to this Application is $866 million.Based on the operation of the Post Test Year Ratemaking (PTYR) mechanism proposed by SCE inChapter X of this volume, including the inclusion of the Edison SmartConnect revenue requirement asdiscussed in Exhibit SCE-04, Volume 1, SCE projects a 2013 base-related CPUC-jurisdictional revenuerequirement or ABRR of $6.884 billion and a 2014 ABRR of $7.496 billion (as presented in Chapter II ofthis Volume). The projected 2013 ABRR represents a $347 million increase of SCE’s requested 2012ABRR and the projected 2014 ABRR represents a $612 million increase over SCE’s projected 2013ABRR. After forecast CPUC-jurisdictional base-related revenue growth is taken into account, theestimated incremental revenue changes associated with the PTYR mechanism and attributable to thisApplication are $246 million for 2013 and $527 million for 2014. Table III-5 below, identifies therequested ABRR and CPUC-jurisdictional base-related revenue changes resulting from this proceeding.11 See Table II-2 in this Volume.12 Revenue growth is calculated based on base-related rate levels in effect as of March 1, 2010.10

Table III-5Southern California Edison Company2012, 2013, and 2014 Revenue Changes Resulting From the 2012 TestYear and 2013 and 2014 PTYR GRC RequestCommission Jurisdictional($000)2012 2013 2014 CumulativeSCE-10 Vol. 1 Reference1. Proposed GRC Base Revenue Requirement 6,285,299 6,883,781 7,495,907 Table II-42. Estimated Present Revenue Requirement 5,347,537 6,285,299 6,883,781 For 2012, Table II-23. Add: Edison SmartConnect Deployment PRR 0 251,303 04. Subtotal Estimated Present Revenue Requirement 5,347,537 6,536,602 6,883,7815. GRC ABRR Change 937,762 347,179 612,1266. Less: GRC Revenue Growth GWhs7. 2011 GRC PRR 84,729 5,113,095 Table VI-218. 2012 GRC PRR 85,920 5,184,968 Table VI-219. 2012 GRC PRR 85,920 5,184,968 Table VI-2110. 2013 GRC PRR 87,593 5,285,928 Table VI-2111. 2013 GRC PRR 87,593 5,285,928 Table VI-2112. 2014 GRC PRR 89,006 5,371,197 Table VI-2113. GRC Revenue Growth 71,873 100,960 85,27014. GRC Revenue Change 865,890 246,220 526,85615. Percent Revenue Change 16.19% 3.77% 7.65% 27.61%16. Total System PRR 11,464,632 11,666,018 11,839,008 Table VI-1917. Percent Revenue Change 7.55% 2.11% 4.45% 14.11%1234567891011B. Consolidation Of Rate ChangesSCE proposes that the ABRR requested in this Application for the 2012 Test Year becomeeffective on January 1, 2012. The 2012 ABRR adopted by the Commission in this proceeding should thenbe consolidated for revenue allocation and rate design purposes with the regularly scheduled EnergyResource Recovery Account 2012 Forecast proceeding consolidated rate level changes anticipated tooccur on January 1, 2012. It is appropriate to consolidate the 2012 GRC rate level change with other ratelevel changes anticipated to occur January 1, 2012, since it will reduce the number of rate level changesthereby contributing to rate stability, customer understanding, and ease of administration. 13Since the majority of the 2012 non-base related revenue changes have not been noticed or filed atthe time of this application, SCE has not included an estimate of the 2012 total system consolidatedrevenue requirement in this Exhibit. As this proceeding progresses and as more information becomes13 Pursuant to the Commission’s Rate Case Plan adopted in D.93-07-030, rate design and other pricing issues are to beaddressed in a separate Phase II of this GRC and are not addressed in this Application.11

123available (i.e., additional changes in revenue requirements are noticed) SCE will provide an estimate of itsconsolidated 2012 revenue requirement consistent with the procedures set forth in the Commission’s RateCase Plant (D.93-07-030).12

1234567891011121314151617181920212223242526272829303132IV.RECOVERY OF GRC RELATED REVENUE REQUIREMENTSThis chapter describes SCE’s ratemaking proposal for recovering its Commission-jurisdictionalbase-related revenue requirement beginning in 2012. This chapter first provides a brief ratemakingoverview of the currently approved ratemaking structure. Second, this chapter describes SCE’smethodology for removing FERC-jurisdictional costs from SCE’s forecast total system base-relatedrevenue requirement in order to determine the Commission-jurisdictional base-related revenuerequirement requested in this proceeding. Third, this chapter describes SCE’s methodology tofunctionalize the Commission-jurisdictional base-related revenue requirement requested in thisproceeding between distribution, generation, and new system generation (i.e. peakers) cost components.Fourth, this chapter describes the recovery of SCE’s authorized Commission-jurisdictional base-relatedrevenue requirements through the operation of the Base Revenue Requirement Balancing Account(BRRBA) and the New System Generation Balancing Account (NSGBA). Finally, this chapter discussesvarious ratemaking proposals associated with SCE’s requested Commission-jurisdictional base-relatedrevenue requirements including SCE’s:1. Recovery of the Edison SmartConnect Revenue Requirement2. Recovery of SCE’s share of the Solar Photovoltaic Program Costs3. Recovery of Market Redesign and Technology Upgrade Revenue Requirement4. Recovery of Four Corners-Related Revenue Requirement5. Recovery of Fuel Cell Revenue Program Requirement6. Continuation of the Mohave Balancing Account.7. Continuation of the Post-Retirement Benefit Other than Pensions BalancingAccount.8. Continuation of the Pensions Cost Balancing Account.9. Continuation of the Research, Development And Demonstration AdjustmentClause.10. Continuation of the Employee Stock Option Plan Tax Memorandum Account.11. Continuation of the Reliability Investment Incentive Mechanism.12. Interaction between amounts requested in this Application and those costsrequested to be found reasonable in SCE’s 2007 Wildfire CEMA application(A.10-04-026).13. Interaction with the Fire Prevention Rulemaking proceeding (R.08-11-005)13

12345678910111213141516171814. Interaction with the SONGS 2&3 Steam Generator Replacement cost recovery.15. Request to eliminate the Project Development Division Memorandum Account,Results Sharing Memorandum Account, Medical Programs Balancing Account,Palo Verde O&M Balancing Account, Community Choice Aggregators’Implementation Costs Balancing Account, Four Corners Capital ExpendituresMemorandum Account and Non-Discretionary Cost Memorandum Account.A. Ratemaking OverviewFor SCE’s bundled service customers, SCE’s current rate structure is comprised of the followingrate components: 141. Distribution; 152. Transmission (includes all FERC-jurisdictional cost and revenue components);3. SCE Generation; 164. New System Generation; 175. Nuclear Decommissioning;6. Public Purpose Programs and7. Department of Water Resources (DWR) Power Charge and Bond Charge.Figure IV-2 shows the relative magnitude of each rate component for bundled service customersas of March 1, 2010.14 Direct Access customers are not charged the SCE Generation rate or the DWR Power Charge. Instead, Direct Accesscustomers are charged a Direct Access Cost Responsibility Surcharge (DACRS).15 Revenues from the Distribution rate component recover: (1) authorized base-related Distribution costs approved by theCommission through the GRC proceeding; and, (2) other Distribution costs as approved by the Commission in variousproceedings such as hazardous substance cleanup and litigation costs.16 Revenues from the SCE Generation rate component recover: (1) authorized base-related Generation costs, excludingauthorized Peaker costs, as approved by the Commission through GRC proceedings; and (2) fuel and purchased powercosts as approved by the Commission in ERRA proceedings.17 Revenues from the SCE New System Generation rate component recover: (1) authorized base-related New SystemGeneration costs (e.g., SCE’s Peaker Revenue Requirement) as approved by the Commission through the GRCproceeding; and, (2) net purchased power costs that the Commission has deemed to be considered New Generationconsistent with D.06-07-029, and as approved by the Commission through ERRA proceedings.14

Figure IV-2Southern California Edison CompanyBundled Service Customers Average RatesAs of March 1, 2010(cents/kWh)Nuc Decom,0.1, 1%Public Purpose,0.7, 5%Transmission,0.8, 6%DWR, 1.6, 11%Distribution,4.7, 33%New Sys Gen,0.1, 1%SCEGeneration,6.3, 43%1234567891011121314Authorized CPUC-jurisdictional base-related revenue requirements are currently recovered fromcustomers through the Distribution, SCE Generation, and New System Generation rate components andthe operation of the Base Revenue Requirement Balancing Account (BRRBA), and the New SystemGeneration Balancing Account (NSGBA). SCE proposes to continue both the BRRBA and NSGBAmechanisms in the 2012 test year and 2013 and 2014 post test years, as discussed later in this Chapter.B. Commission Jurisdictional Revenue RequirementAs discussed in Chapter II of this volume, the operating expenses and investment-related costsidentified in this exhibit and accompanying exhibits of this Application include base related FERCjurisdictionaltransmission related operating and capital costs. To determine 2012 through 2014 baserelated Commission-jurisdictional revenue requirements, SCE must split costs that are to be recoveredthrough rates authorized by the Commission from those authorized by the FERC. In D.04-07-022, theCommission adopted SCE’s proposed methodology to determine the Commission’s jurisdictional revenuerequirements. The methodology used in this Application is consistent with the methodology adopted bythe Commission in D.04-07-022. 18 The Commission also adopted this methodology, without comment, in18 The jurisdictional factors adopted by the Commission in D.04-07-022 relied, in part, on a Transmission and Distribution(T&D) Jurisdictional Study that was submitted to the FERC as part of SCE’s 2002 FERC rate case filed on January 31,2002 (Amended February 13, 2002 – Docket No. ER02-925-000). A new T&D Jurisdictional Study was prepared for usein this Application based on an updated set of historical cost values and updated asset statistics.15

123both D.06-05-016 and D.09-03-025 (SCE’s prior general rate cases). Table IV-6 below identifies thejurisdictional split methodology utilized by SCE in this Application for each cost component of its Resultsof Operations (RO).Table IV-6Jurisdictional Split Methodology By RO Cost ComponentLineNo.ItemJurisdictionalAllocation Basis1. Operating Expenses:2. Production3. Transmission4. Distribution5. Customer Accounts6. Uncollectibles7. Customer Service & Information8. Administrative & General9. Franchise Requirements10. Revenue Credits11.12. Escalation13. Depreciation14.15.16. Taxes Other Than On Income:17. Property Taxes18. Payroll Taxes & Misc19. Taxes Based on Income100% CPUC-related (Direct Assigned)T&D Jurisdictional StudyT&D Jurisdictional Study100% CPUC-related (Direct Assigned)Calculated based on resultant CPUC-Jurisdictional amounts100% CPUC-related (Direct Assigned)Labor AllocatorCalculated based on resultant CPUC-Jurisdictional amountsDirect Assigned; Labor Allocator, andT&D Jurisdictional StudyCalculated based on resultant CPUC-Jurisdictional amountsDirect AssignedT&D Jurisdictional Study; andLabor AllocatorCalculated based on resultant CPUC-Jurisdictional rate baseLabor AllocatorCalculated based on resultant CPUC-Jurisdictional rate base20. Rate BaseDirect Assigned21.T&D Jurisdictional Study; and22. Labor Allocator45678910Based on the various methodologies set forth in Table IV-6 above, SCE developed compositejurisdictional percentages by RO cost category for the CPUC and FERC jurisdictions (i.e., jurisdictionalfactors) for each year from 2012 through 2014. The CPUC jurisdictional factors were then applied toSCE’s requested 2012, 2013, and 2014 total system base-related revenue requirements to determine theCPUC jurisdictional base-related revenue requirements for each year. Table IV-7 below sets forth theCommission jurisdictional factors and Commission jurisdictional base-related revenue requirementsrequested in this Application for each year from 2012 through 2014.16

Table IV-7CPUC-Jurisdictional Factors And Revenue Requirements($000)Line2012 GRC - CPUC 2013 GRC - CPUC 2014 GRC - CPUCNo. Item $ % $ % $ %1. TOTAL OPERATING REVENUES 6,285,299 90.50% 6,883,781 88.45% 7,495,907 87.66%2. OPERATING EXPENSES:3. Production4. Steam 63,329 100.00% 63,329 100.00% 63,329 100.00%5. Nuclear 405,852 100.00% 405,852 100.00% 405,852 100.00%6. Hydro 57,610 100.00% 57,610 100.00% 57,610 100.00%7. Other 143,089 100.00% 143,089 100.00% 143,089 100.00%8. Subtotal Production 669,880 100.00% 669,880 100.00% 669,880 100.00%9. Transmission 94,149 49.14% 94,149 49.14% 94,149 49.14%10. Distribution 504,777 98.73% 493,688 98.73% 493,688 98.73%11. Customer Accounts 213,822 100.00% 193,452 100.00% 193,452 100.00%12. Uncollectibles 14,393 90.50% 15,764 88.45% 17,166 87.66%13. Customer Service & Information 50,069 100.00% 53,356 100.00% 53,356 100.00%14. Administrative & General 978,526 95.37% 982,367 95.37% 993,521 95.37%15. Franchise Requirements 56,957 90.50% 62,381 88.45% 67,928 87.66%16. Revenue Credits (153,242) 81.91% (161,604) 81.91% (164,599) 81.91%17. Subtotal 2,429,332 95.10% 2,403,432 95.02% 2,418,540 94.99%18. Escalation 177,474 94.71% 251,311 94.71% 322,681 94.71%19. Depreciation 1,433,893 90.92% 1,679,873 89.44% 1,939,819 89.21%20. Taxes Other Than On Income - Property 172,275 85.09% 187,712 81.54% 207,090 80.23%21. Taxes Other Than On Income - Payroll 91,756 95.37% 92,374 95.37% 95,348 95.37%22. Taxes Based On Income 536,668 85.09% 615,227 81.54% 717,003 80.23%23. Total Taxes 800,699 86.16% 895,314 82.78% 1,019,441 81.44%24. TOTAL OPERATING EXPENSES 4,841,398 92.25% 5,229,930 90.88% 5,700,482 90.30%25. NET OPERATING REVENUE 1,443,900 85.09% 1,653,851 81.54% 1,795,425 80.23%26. RATE BASE 16,501,716 85.09% 18,901,148 81.54% 20,519,135 80.23%27. RATE OF RETURN 8.75% 8.75% 8.75%12345678910Consistent with D.04-07-022, Administrative and General (A&G) expense and General andIntangible plant costs have been allocated to the Commission jurisdictional revenue requirements on thebasis of labor cost ratios. The testimony that follows describes the Transmission and Distribution (T&D)Jurisdictional Study that was performed by SCE to derive various CPUC jurisdictional factors asidentified in Table IV-7 above. The determination of the labor cost ratios and the T&D JurisdictionalStudy are included in the workpapers that support this Chapter.1. Transmission And Distribution Jurisdictional StudyThis testimony presents SCE’s methodology for separating T&D operation andmaintenance (O&M) expenses, other operating revenue (OOR), and capital expenditures between FERCjurisdiction (CAISO), and CPUC jurisdiction (non CAISO).17

12345678910111213141516171819202122232425262728a) IntroductionOn April 29, 1996, at the direction of the CPUC, SCE, PG&E, and SDG&E filed ajoint petition at the FERC seeking a declaratory order identifying facilities as generation, transmission ordistribution related. In evaluating whether SCE’s sub transmission (66kV 115kV) facilities should beCPUC or FERC jurisdictional, SCE relied on the FERC’s Open Access Rule. In this rule, the FERCrejected the accounting definition of transmission (facilities above 50 kV) as the basis for jurisdictionalseparation, and instead chose a “seven indicator test” using the following criteria below to determine thenature of the facilities:1. Local distribution facilities are normally in close proximity to retail customers.2. Local distribution facilities are primarily radial in character.3. Power flows into local distribution systems and rarely, if ever, flows out.4. When power enters a local distribution system, it is not reconsigned or transported onto some other market.5. Power entering a local distribution system is consumed in a comparatively restrictedgeographical area.6. Meters are located at the transmission/local distribution interface to measure flows intothe local distribution system.7. Local distribution systems will be of reduced voltage.SCE facilities meeting the “seven indicator test” were deemed to be distributionrelated and under the jurisdiction of the CPUC. In addition, the generation step up transformers and radiallines that connect four non SCE generating plants to our transmission network were deemed to beperforming a generation function, therefore non Independent System Operator (CAISO) related. 19The facilities booked as transmission for SCE, PG&E, and SDG&E and deemed tobe under the jurisdiction of FERC, were placed under the operational control of the CAISO. Our CAISOcontrolled facilities include all line positions of 500 kV or greater, most 230 kV positions, and certain 115kV and 66 kV lines. Also included are substations that are at 500 kV/230 kV and portions of substationsthat transform from 230 kV/115 kV and 230 kV/66 kV. All other facilities are considered non CAISOrelated.19 The four radial lines: Cool Water-Kramer (two lines), Huntington Beach-Ellis (four lines), Mandalay-Santa Clara (twolines) and Ormond Beach-Moorpark connect the generators located at Cool Water, Huntington Beach, Mandalay, andOrmond Beach to the transmission system.18

12345678910111213141516171819202122232425262728293031b) Cost Separation Methodology(1) CAISO/Non-CAISO O&M Cost Separation MethodologyTo separate costs for this 2012 GRC, SCE looked at the five years (2005 -2009) of recorded costs within each FERC account, by functional sub account, so that similar activitieswere assigned on a consistent basis. In most instances, SCE separated the recorded costs for each subaccount by using SCE’s 2009 recorded statistical information (i.e., circuit miles, relays, transformers, etc.)to better represent expected operations in the forecast period. Based on this analysis, SCE developedCAISO/Non CAISO factors by FERC account for each of the recorded years, and a five-year averagefactor (2005-2009). Incremental additions over the 2009 base year were generally allocated using the fiveyearaverage factor, with the exception of several accounts that had specifically assignable increases. Afive-year average factor was selected to allocate increases because the affected accounts had significantfluctuations during the 2005-2009 recorded period and we expect such fluctuations to continue during the2012 GRC cycle.(2) CAISO/Non-CAISO Other Operating Revenue Separation MethodologyTo separate the OOR, forecasts of revenue by account were derived. Theseforecasts, excluding added/interconnection facilities, were separated between CAISO and non CAISObased on direct assignment, that is, by the nature of each activity. For added/interconnection facilities, adetailed review of each contract was performed assigning the assets between CAISO and non CAISO.(3) CAISO/Non-CAISO Plant Cost Separation MethodologyTo separate capital expenditures, SCE identified forecast expenditures bywork order. In most cases, these work orders identify specific capital replacements as CAISO or nonCAISO based on their identified scope of work and the assets involved. For expenditures (i.e., blankets)that could not be readily separated, costs were allocated between CAISO and non CAISO based on 2005 -2009 recorded costs.Blanket capital expenditures are for jobs that will occur on the system eachyear, but for which details and locations are not known in advance. Blankets include:1) overhead line additions and retirements.2) the repair of storm damage or damage caused by others.3) circuit breaker and transformer additions and replacements.4) replacement of failed substation equipment (less than $500.000 peroccurrence).19

12345678910111213141516171819202122232425262728295) purchases of portable tools, spare parts, store equipment, lab equipment,furniture and office equipment.The assignment of each forecast blanket work order between CAISO andnon CAISO is based on identification and classification of the respective 2005 - 2009 recorded systemand blanket work order costs. The classification is based on the identification of the historical blanketwork order items to specific assets on the transmission system. These assets were classified as CAISO andnon CAISO based on SCE’s single line diagrams detailing the separation of the transmission system.C. Functionalization Of Commission Jurisdictional Revenue RequirementFor SCE to have separate rate components for distribution, generation and “new system”generation requires SCE to separate or functionalize its requested Commission-jurisdictional base-relatedrevenue requirements. In this Application, SCE proposes no material change to the functionalizationmethodology adopted by the Commission in D.04-07-022, as modified in D.06-05-016, and as affirmed inD.09-03-025. However, as a result of D.09-03-031, SCE’s functionalized generation revenue requirement,or AGBRR is allocated between SCE’s non-peaker generation revenue requirement and its peakerrevenue requirement. In D.09-03-031, the Commission allocated the costs and resource adequacy benefitsof the peaker units, owned and operated by SCE, to all benefiting customers. Upon implementation ofD.09-03-031, the peaker-related revenue requirement is included in the New System Generation ratecomponent and not SCE’s generation rate component that is recovered only from SCE’s bundled servicecustomers. 20 Therefore, SCE must allocate the total generation revenue requirement into a non-peakergeneration revenue requirement and a peaker revenue requirement. The following testimony summarizesthe Commission-adopted functionalization approach.The majority of SCE’s CPUC-jurisdictional base-related revenue requirement can befunctionalized between generation and distribution through direct assignment by the use of the FERCUniform System of Accounts and SCE’s physical location identifiers. The remainder of SCE’s CPUCjurisdictionalbase-related revenue requirement comprised of A&G and general plant costs that supportoverall company activities cannot be directly assigned between generation and distribution, so must beallocated.To functionalize SCE’s 2012 CPUC-jurisdictional base-related revenue requirement, SCE firstdirectly assigned O&M costs and rate base amounts between generation and distribution. The O&M costs20 SCE implemented recovery of its peaker generation revenue requirement through the New System Generation ratecomponent in Advice Letter 2346-E, which was approved by the Commission’s Energy Division effective June 1, 2009.20

12345678and rate base amounts that cannot be directly assigned to generation and distribution (e.g., A&G andgeneral plant) are then functionalized based on the use of a labor cost allocator. 21 SCE next functionalizedthe other components of its 2012 revenue requirement, including income taxes and payroll and propertytaxes, by using either a labor or rate base allocator. For example, property taxes are functionalized usingthe ratio of the generation and distribution portions of the rate base to CPUC-jurisdictional rate base;payroll taxes are functionalized by using a labor cost allocator.Table IV-8 shows the functionalization of SCE’s 2012 CPUC-jurisdictional base-related revenuerequirement request.21 SCE developed the labor cost allocator on 2012 labor as forecast in this proceeding.21

Table IV-82012 Results of Operation at Proposed Rates Functionalized($000)Line No. Item CPUC Generation Distribution1. TOTAL OPERATING REVENUES 6,285,299 2,054,505 4,230,7942. OPERATING EXPENSES:3. Production4. Steam 63,329 63,3295. Nuclear 405,852 405,8526. Hydro 57,610 57,6107. Other 143,089 143,0898. Subtotal Production 669,880 669,880 -9. Transmission 94,149 94,14910. Distribution 504,777 504,77711. Customer Accounts 213,822 213,82212. Uncollectibles 14,393 4,705 9,68913. Customer Service & Information 50,069 50,06914. Administrative & General 978,526 377,912 600,61415. Franchise Requirements 56,957 18,618 38,33916. Revenue Credits (153,242) (7,308) (145,934)17. Subtotal 2,429,332 1,063,807 1,365,52518. Escalation 177,474 76,320 101,15419. Depreciation 1,433,893 390,085 1,043,80820. Taxes Other Than On Income21. Property Taxes 172,275 39,119 133,15522. Payroll Taxes & Misc 91,756 35,437 56,31923. Taxes Based On Income 536,668 121,864 414,80424. Total Taxes 800,699 196,420 604,27925. TOTAL OPERATING EXPENSES 4,841,398 1,726,632 3,114,76626. NET OPERATING REVENUE 1,443,900 327,873 1,116,02727. RATE BASE 16,501,716 3,747,132 12,754,58428. RATE OF RETURN 8.75% 8.75% 8.75%123Using the same functionalization methodology as described above, Table IV-9 and Table IV-10provide the functionalization for SCE’s requested 2013 and 2014 CPUC-jurisdictional base-relatedrevenue requirements.22

Table IV-92013 Results of Operation at Proposed Rates Functionalized($000)Line No. Item CPUC Generation Distribution1. TOTAL OPERATING REVENUES 6,883,781 2,214,831 4,668,9502. OPERATING EXPENSES:3. Production4. Steam 63,329 63,3295. Nuclear 405,852 405,8526. Hydro 57,610 57,6107. Other 143,089 143,0898. Subtotal Production 669,880 669,880 -9. Transmission 94,149 94,14910. Distribution 493,688 493,68811. Customer Accounts 193,452 193,45212. Uncollectibles 15,764 5,072 10,69213. Customer Service & Information 53,356 53,35614. Administrative & General 982,367 379,395 602,97115. Franchise Requirements 62,381 20,071 42,31016. Revenue Credits (161,604) (6,312) (155,292)17. Subtotal 2,403,432 1,068,106 1,335,32618. Escalation 251,311 110,162 141,14919. Depreciation 1,679,873 457,353 1,222,52120. Taxes Other Than On Income21. Property Taxes 187,712 41,529 146,18322. Payroll Taxes & Misc 92,374 35,675 56,69923. Taxes Based On Income 615,227 136,112 479,11524. Total Taxes 895,314 213,316 681,99725. TOTAL OPERATING EXPENSES 5,229,930 1,848,937 3,380,99326. NET OPERATING REVENUE 1,653,851 365,894 1,287,95627. RATE BASE 18,901,148 4,181,655 14,719,49228. RATE OF RETURN 8.75% 8.75% 8.75%23

Table IV-102014 Results of Operation at Proposed Rates Functionalized($000)Line No. Item CPUC Generation Distribution1. TOTAL OPERATING REVENUES 7,495,907 2,484,198 5,011,7092. OPERATING EXPENSES:3. Production4. Steam 63,329 63,3295. Nuclear 405,852 405,8526. Hydro 57,610 57,6107. Other 143,089 143,0898. Subtotal Production 669,880 669,880 -9. Transmission 94,149 94,14910. Distribution 493,688 493,68811. Customer Accounts 193,452 193,45212. Uncollectibles 17,166 5,689 11,47713. Customer Service & Information 53,356 53,35614. Administrative & General 993,521 383,703 609,81815. Franchise Requirements 67,928 22,512 45,41616. Revenue Credits (164,599) (6,429) (158,170)17. Subtotal 2,418,540 1,075,354 1,343,18618. Escalation 322,681 141,507 181,17419. Depreciation 1,939,819 609,667 1,330,15220. Taxes Other Than On Income21. Property Taxes 207,090 47,277 159,81322. Payroll Taxes & Misc 95,348 36,824 58,52423. Taxes Based On Income 717,003 163,687 553,31624. Total Taxes 1,019,441 247,788 771,65325. TOTAL OPERATING EXPENSES 5,700,482 2,074,316 3,626,16626. NET OPERATING REVENUE 1,795,425 409,882 1,385,54327. RATE BASE 20,519,135 4,684,372 15,834,76328. RATE OF RETURN 8.75% 8.75% 8.75%12345D. Recovery Of GRC Revenue RequirementIn D.04-07-022, the Commission established the Base Revenue Requirement Balancing Account(BRRBA) to ensure that SCE recovers no more and no less than its authorized CPUC-jurisdictional baserelatedrevenue requirement, or ABRR. As discussed above, the portion of the ABRR functionalized asgeneration that is associated with SCE’s peakers is recovered from all benefiting customers through the24

1234567891011121314151617181920212223New System Generation rate component. As the result of D.07-09-044, SCE established the New SystemGeneration Balancing Account (NSGBA) so that SCE recovers no more and no less than its CPUCjurisdictionalNew System Generation costs. A component of the New System Generation costs is theCPUC-jurisdictional peaker revenue requirement. Through the NSGBA, SCE will recover no more and noless than its authorized CPUC-jurisdictional peaker revenue requirement.A fundamental purpose of both the BRRBA and NSGBA is to compare portions of the monthlyABRR to applicable retail revenues from distribution, generation, and new system generation rates. Inaddition, through the BRRBA, SCE will recover SONGS 2&3 refueling and maintenance outage revenuerequirements each year. The BRRBA also includes the SONGS 2&3 Refueling and Maintenance OutageTracking Account (RMOTA), which allows SCE to track differences between the number of flexibleSONGS 2&3 refueling and maintenance outages (i.e., revenue requirements) included in the annualAuthorized Generation Base Revenue Requirement (AGBRR) with the actual number (zero, one or two)of refueling and maintenance outages that occur during each year of the GRC cycle since flexiblerefuelings can occur in any year (test year or post test year). 22 SCE requests continuation of the currentratemaking procedures for the SONGS 2&3 flexible refueling and maintenance outages for Test Year2012, and as discussed in more detail in Chapter X of this Exhibit, for the post test years 2013 and 2014.The BRRBA includes distribution and generation sub-accounts to track under-collections andover-collections by function. Similarly, the NSGBA tracks under-collections and over-collections to berecovered or refunded through the New System Generation rate. Pursuant to D.04-04-066 the balances inSCE’s balancing account, such as the BRRBA and NSGBA, are consolidated into rate levels on an annualbasis in the ERRA forecast proceeding submitted to the Commission on August 1 st of each year. 23 Inaddition, SCE sets forth the entries recorded in the BRRBA and NSGBA for Commission review for eachcalendar year in the ERRA review proceeding submitted to the Commission on April 1 st of each year.22 SCE is estimating one SONGS 2&3 refueling and maintenance outage in 2012, 2013, and 2014. If for any reason therefueling does not take place in a given year, through the operation of the RMOTA/BRRBA, SCE will refund any overcollectionto customers in the subsequent year. Likewise if the ABRR includes one refueling and two occur, then throughthe operation of the RMOTA, SCE will recover any under-collection from customers in the subsequent year.23 Distribution over or under-collections are consolidated into distribution rate levels. Generation over or under-collectionsare consolidated into generation rate levels. And, new system generation over or under-collections are consolidated intonew system generation rate levels.25

12345678910111213141516171819202122232425262728293031E. Miscellaneous Ratemaking Issues1. Recovery Of Edison SmartConnect Revenue Requirementa) BackgroundThe Edison SmartConnect program was authorized by the Commission inD.08-09-039. That decision adopted a Settlement Agreement between SCE and DRA and includedvarious stipulations on behalf of TURN. The Settlement Agreement provided for a total recovery limit of$1.63 billion over a five-year deployment period. In SCE’s 2009 GRC, the Commission adopted SCE’sproposal to include a forecast of primarily the CSBU-related costs in the GRC revenue requirementassuming “business-as-usual” (i.e., without any impact of the SmartConnect program costs or benefits onthe 2009 through 2011 GRC revenue requirement). The Settlement Agreement also provided for theestablishment of the Edison SmartConnect Balancing Account (ESCBA) to record the SmartConnectcapital revenue requirement (i.e. depreciation, return on rate base, and taxes) and O&M costs during thedeployment period, and provided a fixed O&M benefit credit to SCE’s customers of $1.4246 per installedmeter per month through the end of deployment. The $1.4246 per installed meter per month was adoptedby the Commission in order to provide customers with the O&M benefits that would be achieved throughthe SmartConnect program. These benefits were not reflected in the 2009 through 2011 GRC revenuerequirements. The revenue requirements associated with capital-related benefits are recorded as a credit inSCE’s BRRBA annually. The “deployment period” was planned to last during the five year period 2008through 2012.SCE anticipates that full deployment will be achieved by December 31, 2012. It isimportant that the terms of the Settlement Agreement are preserved such that both the deployment-relatedcapital revenue requirement and O&M are recovered through the ESCBA, and capital benefits arecredited to customers. Therefore, as discussed in more detail below, SCE is proposing to maintain thiscost recovery “separation” through the end of deployment, or December 31, 2012. Beginning in 2013,SCE proposes to put the revenue requirement pieces together, including the operational related benefits, inthe 2013 and 2014 GRC revenue requirements. Since SCE is also required to credit customers the capitalrelatedbenefits during the deployment period, for administrative ease, SCE has included the 2012 capitalrelatedbenefits in the 2012 GRC revenue requirement. As such, SCE will not record the 2012 benefit inthe BRRBA. In addition, as discussed below, SCE requests modification of the ESCBA for use afterdeployment is completed to allow for the recording of certain deployment-related carry-over costs andany adjustment to costs recorded prior to the end of deployment period.26

12345678910111213141516171819202122232425b) 2012 Test PeriodBy adopting the Settlement Agreement, the Commission approved cost recovery ofthe SmartConnect program (i.e., deployment costs) through the end of 2012. SCE proposes no changein cost recovery for the 2012 Test Year in this GRC proceeding. Therefore, in the 2012 Test Year GRCrevenue requirement, SCE has included a “business-as-usual” case for the CSBU-related 24 O&M andcapital, and has excluded the 2012 revenue requirement associated with Edison SmartConnectdeployment-related costs since those costs will still be recovered through the ESCBA through December31, 2012. 25 In this way, SCE will continue crediting the $1.4246 per installed meter per month in theESCBA through the end of deployment, or December 31, 2012. As discussed above, for administrativeease, SCE has included the capital-related benefits as a credit in the 2012 GRC revenue requirement andwill not continue to record the credit revenue requirement in the BRRBA. Providing both the O&M andcapital benefits to customers is important because the terms of the Settlement Agreement are preserved.As discussed in SCE-04, Volume 4, SCE is estimating a reduction in Other Operating Revenue sincefewer charges will be assessed to customers as a result of new Edison SmartConnect functionality. 26c) Forecast Included in 2013 GRC Revenue RequirementIn this GRC, CSBU has presented a 2013 O&M and capital forecast that includesthe full impact of Edison SmartConnect O&M costs and benefits in 2013 (and 2014) and avoids overlapof the 2012 Test Year with the Edison SmartConnect meter deployment. 27 In other words, the 2013 GRCrevenue requirement includes: (1) a “bottoms-up” O&M forecast for CSBU; (2) the revenue requirementassociated with new CSBU capital expenditures supported in Exhibit SCE-04, Volume 4; and (3) the ongoingrevenue requirement associated with the Edison SmartConnect deployment-related capital (i.e.meters). As such, beginning in 2013 SCE will discontinue crediting the $1.4246 per installed meter permonth in the ESCBA since all benefits are at that point reflected in CSBU’s 2013 O&M forecast. Like theGRC revenue requirement for 2012, all capital benefits that result from Edison SmartConnect areincluded in the 2013 GRC revenue requirement and will no longer be credited to the BRRBA annually.24 Includes all CSBU departments with the exception of Local Public Affairs (LPA). LPA operation are unaffected by theEdison SmartConnect program25 The term “business-as-usual” simply means that all of the deployment costs and associated O&M benefits are excludedfrom the GRC revenue requirement because they are recovered through the ESCBA.26 Franchise Fees and Uncollectible expenses are calculated in the RO model.27 Included in the impact of Edison SmartConnect are enabled dynamic pricing/demand response programs, Home AreaNetwork, remote service switch, and automated meter reading.27

1234567891011121314151617181920212223242526272829303132CSBU’s 2013 forecast is presented in Exhibit SCE-04, Volumes 1 through 4.d) Modification to the ESCBAThe Edison SmartConnect Phase III application approved in D.08-09-039 assumedmeter purchases and installations would be complete in 2012. Furthermore, approval of the ESCBAprovided that the balancing account would remain in operation through the end of deployment, orDecember 31, 2012. Although the Edison SmartConnect meter deployments are currently scheduled to becompleted by the end of 2012, certain Edison SmartConnect project costs that were authorized in D.08-09-039 are expected to carryover into 2013 and perhaps 2014. Specifically, as discussed in Exhibit SCE-04, Volume 1, due to factors outside of SCE’s control, costs for the functionalities related to theprogrammable communicating thermostats (PCTs) and in-home displays (IHDs) are expected to beincurred in 2013 and perhaps 2014. These costs are included in the $1.63 billion cost cap for the EdisonSmartConnect program adopted in D.08-09-039 and these specific costs have not been included inCSBU’s 2013 O&M requested in this GRC.Specifically, SCE requests to continue use of the ESCBA and modify the ESCBAPreliminary Statement for purposes of: (1) recording authorized costs which are expected to be incurred in2013 and 2014 (i.e. PCTs and IHDs); (2) recording costs incurred in 2012 that may not be recorded until2013; and (3) recording adjustments to costs that were recorded during the deployment period. SCE alsoproposes to modify the ECSBA to eliminate the operational benefit of $1.4246 per meter per monthbeginning in 2013, as these benefits are already reflected in CSBU’s and other departments 2013 forecast,and eliminate the recording of the capital-related revenue requirement (i.e. depreciation, return on ratebase, and taxes) associated with the Edison SmartConnect deployment capital.e) Delay in Deployment PeriodAlthough not anticipated, if a delay should occur and deployment continues into2013, SCE proposes to continue to recover the CSBU “business-as-usual” portion of the authorized 2012revenue requirement in 2013 and through the end of deployment. If a delay occurs, SCE proposes toescalate the CSBU’s authorized 2012 revenue requirement just like all other components of the GRCrevenue requirement in 2013 subject to the Post Test Year ratemaking proposal discussed later in thisExhibit. Likewise, once a delay in the end of deployment is known but prior to the end of 2012, SCEproposes to file an advice letter to: (1) implement a modified 2013 GRC revenue requirement to removethe CSBU-related “bottoms-up” revenue requirement and add back in the 2012 “business-as-usual”revenue requirement; and (2) extend the use of the existing ESCBA with all of its features (i.e. the$1.4246 per meter per month credit). Once the date of the end of deployment is known, SCE proposes to28

1234567891011121314151617181920212223file another advice letter to: (1) remove the 2012 “business-as-usual” revenue requirement for CSBU andadd in the adopted 2013 CSBU revenue requirement; and (2) discontinue the existing ESCBA andimplement the modified ESCBA as discussed above.f) Demonstration of No Double RecoveryThe Commission in D.08-09-039 required SCE in its next GRC to “make anaffirmative showing that it has avoided double recovery of any requested AMI costs, and that anyrequested costs in its 2012 GRC are consistent with the limits of recovery adopted in this decision.” 28 InExhibit SCE-04, Volume 1, SCE has provided testimony showing that with the ratemaking currently inplace and requested in this proceeding beginning in 2012, that no double recovery of EdisonSmartConnect costs has or will occur.2. Recovery Of SCE’s Share Of The Solar Photovoltaic ProgramIn A.08-03-015, SCE requested Commission authority to own, install, operate andmaintain 250 MW of distributed solar PV projects primarily in the one-to-two MW range to be located inSCE’s service territory. Prior to a final decision in that application, the Commission granted SCE’srequest in Advice Letter 2226-E to establish the Solar PV Program Memorandum Account (SPVPMA) tobegin recording the capital revenue requirement and incremental O&M expenses associated with the first$25 million of the program.In D.09-06-049, the Commission authorized SCE to install and operate, and maintain up to250 MW of utility-owned solar photovoltaic (PV) generating facilities. The Commission found itreasonable for SCE to recover incremental O&M and up to $962.5 million in direct capital expenditures,which equates to an average of $3.85/W over the five year program period. 29 In addition, the Commissionadopted SCE’s request to include an estimated revenue requirement in generation rate levels each yearand establish the Solar PV Program Balancing Account to record the incremental O&M and the capital28 D.08-09-039, (mimeo), Ordering Paragraph 6, p. 61.29 In D.09-06-049 the Commission doubled the size of the Solar PV program by adding an additional 250 MW IndependentPower Producer component, whereby SCE must hold an annual solicitation to procure up to 250 MW distributedgeneration bids from IPPs under power purchase agreements.29

12345678910111213141516171819202122232425revenue requirement on a going forward basis. 30 D.09-06-049 also allows SCE to transfer the balancerecorded in the SPVPMA to the SPVPBA after the balance is reviewed in an ERRA review proceeding. 31SCE proposed in A.08-03-015 to continue to record the Solar PV program revenuerequirement in the SPVPBA until both the O&M and capital-related revenue requirements are included inSCE’s GRC revenue requirement. This proposal was unopposed. In compliance with D.09-06-049, SCEfiled Advice Letters 2363-E and 2363-E-A establishing the SPVPBA Preliminary Statement.In D.09-06-049 the Commission stated that the reasonableness review of the Solar PVprogram capital expenditures and O&M costs should be addressed in SCE’s GRC just like other UtilityOwned Generation (UOG) expenses. 32 Therefore, SCE is including in this GRC its estimate of both theO&M and capital expenditures for the Solar PV program (See Exhibit SCE-02, Volume 10). Pursuant toD.09-06-049, only direct capital costs in excess of the annual $/W threshold contained in SCE’s Solar PVtestimony will be subject to reasonableness review. As discussed in Exhibit SCE-02, Volume 10, thedirect capital expenditures included in the calculation of the 2012 GRC revenue requirement are less thanthe adopted threshold.Because D.09-06-049 requires review of the Solar PV program costs in the GRC like otherUOG costs, consistent with SCE’s proposal in A.08-03-015, SCE has included the Solar PV programrevenue requirement in the 2012, 2013, and 2014 CPUC jurisdictional revenue requirement (i.e., ABRR).Reasonableness review of future capital expenditures and O&M costs will be performed in subsequentGRCs as required by D.09-06-049. If SCE’s Solar PV program revenue requirement proposal is adoptedin this proceeding, upon the effective date of the 2012 GRC Phase 1 revenue requirement the SPVPBAwill no longer be necessary and the account will be eliminated.3. Recovery Of Market Redesign And Technology Upgrade (MRTU) RevenueRequirementThe Commission issued Resolution E-4087 on May 24, 2007, authorizing SCE to establishthe MRTU Memorandum Account (MRTUMA) to record the incremental O&M expenses and the30 On a monthly basis the balance recorded in the SPVPBA is transferred to the generation subaccount of the Base RevenueRequirement Balancing Account. In the BRRBA, the difference between the revenue resulting from the estimated revenuerequirement included in generation rates and the actual Solar PV program revenue requirement is recorded. The year-endbalance recorded in the BRRBA is included in rates annually.31 D.09-06-049, Ordering Paragraph No. 3. SCE has included the balance recorded in the SPVPMA for review in A.10-04-002, SCE’s 2009 ERRA review proceeding.32 D.09-06-049, (mimeo), p. 48 and p. 57, Conclusion of Law 9.30

1234567891011121314151617181920212223242526272829303132revenue requirement on incremental capital additions associated with the California Independent SystemOperator’s MRTU initiative. Resolution E-4087 requires that the costs of the MRTU implementation befound reasonable in SCE’s ERRA review proceeding.In its 2009 GRC, SCE requested authority to include recovery of the MRTU revenuerequirement in its 2009 GRC revenue requirement based on an estimate of the capital expenditures andO&M expenses for MRTU Release 1, 1A, and 2. The Commission rejected this proposal because theestimated costs of Releases 1, 1A, and 2 were unknown at that time and the scope of the MRTU phaseswere evolving. This is no longer the case. The actual capital expenditures that were incurred throughDecember 31, 2009 are now known, and are currently being reviewed in SCE’s 2009 ERRA reviewproceeding. To the extent any recorded MRTU capital costs are found unreasonable in the ERRA reviewproceeding, SCE will make the appropriate adjustment to reduce the 2012, 2013, and 2014 GRC revenuerequirement included in this Application. As supported in Exhibit SCE-08, the O&M costs for operatingthe MRTU system are now part of the overall costs forecast for the Power Procurement Business Unit.Once the Commission issues a final decision in this 2012 GRC and in the ERRA reviewproceeding, no additional amounts will be recorded in the MRTUMA and the recorded balance in theMRTUMA will be transferred to the BRRBA for recovery in rates.4. Recovery Of Four Corners Revenue RequirementAs discussed in Exhibit SCE-02, Volume 6, substantial uncertainty currently surroundsSCE’s future ownership share of the Four Corners Generating Station (FCGS). Currently SCE owns 48percent of FCGS and has informed the co-owners of the plant of its plan to not extend participation inFCGS beyond the expiration of its current agreement which is 2016. As explained in Exhibit SCE-02,Volume 5, SCE’s decision to not participate in the FCGS beyond 2016 is due to California’s GreenhouseGas (GHG) Emissions Performance Standard (EPS) promulgated by the Commission on January 29, 2007(D.07-01-039). FCGS GHG emissions exceed the amount allowed under the EPS. SCE has providedseveral options (i.e., scenarios) on how best to maximize its customers’ value of SCE’s ownership interestin FCGS while remaining compliant with the EPS.SCE has modeled two possible scenarios:• SCE Share Sold Case (“Sale”)• Plant Decommissioned 2014-2016 Case (“Decommission”)At this time, SCE believes that the most likely scenario is the “SCE Share Sold Case,” andtherefore has assumed this in the 2012, 2013, and 2014 CPUC-jurisdictional base-related revenuerequirement requested in this proceeding. This scenario assumes that the plant will continue to be31

12345678910111213141516operated and maintained consistent with historic practice until the sale is completed, as the Buyer ofSCE’s Share would presumably plan to continue to operate the plant for many more years. This caseassumes SCE will continue to fund its share of plant costs, and continue to receive its share of the plantelectrical output, until the sale is completed. As discussed in SCE-2, Volume 6, SCE will endeavor toupdate the Commission on any material developments relating to SCE’s exit plan in its rebuttal andupdate testimony or other Commission filings. As supported in SCE-2, Volume 6, the O&M forecast forthe 2012 Test Year under the first scenario (i.e. Sale case) is $44.3 million and the capital expenditureestimate for the 2012-2014 period is $104.1 million.SCE’s forecast for the other scenario, which assumes the plant is decommissioned,indicates that maintenance and capital spending can be reduced as the plant shut down date approaches,particularly work currently planned for the 2014 major overhaul of Unit 5. The O&M forecast for the2012 Test Year for the Plant Decommissioning case is $41.5 million, and the capital expenditure forecastfor the 2012-2014 period is $71.4 million.Table IV-11 below shows a comparison of the Results of Operation for the 2012 Test Yearof the base case, or “Sale Case”, and the second scenario that assumes the plant is decommissioned asdiscussed above.32

Table IV-112012 Results of Operation – Four Corner’s Scenario Comparison($000)2012 CPUCLine No.ItemFour CornersSale (Base)Four CornersDecommissioningDifference1. TOTAL OPERATING REVENUES 6,285,299 6,281,036 (4,263)2. OPERATING EXPENSES:3. Production4. Steam 63,329 60,491 (2,838)5. Nuclear 405,852 405,852 -6. Hydro 57,610 57,610 -7. Other 143,089 143,089 -8. Subtotal Production 669,880 667,042 (2,838)9. Transmission 94,149 94,149 -10. Distribution 504,777 504,777 -11. Customer Accounts 213,822 213,822 -12. Uncollectibles 14,393 14,384 (10)13. Customer Service & Information 50,069 50,069 -14. Administrative & General 978,526 977,726 (800)15. Franchise Requirements 56,957 56,919 (39)16. Revenue Credits (153,242) (153,242) -17. Subtotal 2,429,332 2,425,646 (3,686)18. Escalation 177,474 177,252 (222)19. Depreciation 1,433,893 1,433,769 (124)20. Taxes Other Than On Income - Property 172,275 172,271 (4)21. Taxes Other Than On Income - Payroll 91,756 91,650 (106)22. Taxes Based On Income 536,668 536,578 (90)23. Total Taxes 800,699 800,499 (200)24. TOTAL OPERATING EXPENSES 4,841,398 4,837,166 (4,232)25. NET OPERATING REVENUE 1,443,900 1,443,870 (31)26. RATE BASE 16,501,716 16,501,364 (352)27. RATE OF RETURN 8.75% 8.75% 8.75%123As shown in Table IV-11 above, based on the assumptions discussed above and in SCE-02, Volume 6, thedecommissioning scenario results in a $4.3 million lower revenue requirement in the 2012 Test Year.Table IV-12 below, shows a comparison of the Results of Operation for the two post-test years.33

Table IV-122013 and 2014 Results of Operation – Four Corner’s Scenario Comparison($000)Line NoItemFourCornersSale (Base)2013 CPUC 2014 CPUCFour CornersDecommissioningDifferenceFour CornersSale (Base)Four CornersDecommissioningDifference1. TOTAL OPERATING REVENUES 6,883,781 6,880,172 (3,609) 7,495,907 7,452,242 (43,665)2. OPERATING EXPENSES:3. Production4. Steam 63,329 60,491 (2,838) 63,329 60,491 (2,838)5. Nuclear 405,852 405,852 - 405,852 405,852 -6. Hydro 57,610 57,610 - 57,610 57,610 -7. Other 143,089 143,089 - 143,089 143,089 -8. Subtotal Production 669,880 667,042 (2,838) 669,880 667,042 (2,838)9. Transmission 94,149 94,149 - 94,149 94,149 -10. Distribution 493,688 493,688 - 493,688 493,688 -11. Customer Accounts 193,452 193,452 - 193,452 193,452 -12. Uncollectibles 15,764 15,756 (8) 17,166 17,066 (100)13. Customer Service & Information 53,356 53,356 - 53,356 53,356 -14. Administrative & General 982,367 981,567 (800) 993,521 992,721 (800)15. Franchise Requirements 62,381 62,348 (33) 67,928 67,532 (396)16. Revenue Credits (161,604) (161,604) - (164,599) (164,599) -17. Subtotal 2,403,432 2,399,753 (3,679) 2,418,540 2,414,407 (4,134)18. Escalation 251,311 251,012 (299) 322,681 322,300 (381)19. Depreciation 1,679,873 1,680,226 353 1,939,819 1,910,134 (29,685)20. Taxes Other Than On Income - Property 187,712 187,893 181 207,090 207,232 14221. Taxes Other Than On Income - Payroll 92,374 92,265 (110) 95,348 95,236 (113)22. Taxes Based On Income 615,227 615,204 (23) 717,003 709,066 (7,937)23. Total Taxes 895,314 895,362 48 1,019,441 1,011,534 (7,907)24. TOTAL OPERATING EXPENSES 5,229,930 5,226,354 (3,577) 5,700,482 5,658,375 (42,107)25. NET OPERATING REVENUE 1,653,851 1,653,819 (32) 1,795,425 1,793,867 (1,558)26. RATE BASE 18,901,148 18,900,780 (368) 20,519,135 20,501,329 (17,806)27. RATE OF RETURN 8.75% 8.75% 8.75% 8.75% 8.75% 8.75%12345678910A comparison between the two scenarios shows that the decommissioning scenario is $3.6million and$43.7million lower than the base case revenue requirement in 2013 and 2014, respectively.5. Recovery Of Fuel Cell Program Revenue RequirementIn D.10-04-028 the Commission authorized SCE to install utility-owned fuel cells on threeUniversity of California and California State University campuses. That decision also authorized SCE toestablish the Fuel Cell Program Memorandum Account (FCPMA) to record the actual capital revenuerequirement and O&M expenses and recover those costs through a transfer of the monthly balance to thegeneration sub-account of the BRRBA, as long as the amounts are no higher than the estimates approvedin D.10-04-028. The Commission authorized $19.1 million of direct capital costs, and total operation andmaintenance costs of $8.9 million over the ten year life of the fuel cells. 3333 Allowance For Funds Used During Construction (AFUDC) is added to the direct capital costs prior to the capitalexpenditures being in service and closed to rate base.34

1234567891011121314151617181920212223242526272829303132As supported in Exhibit SCE-02, Volume 10, SCE estimates it will incur $19.1 million ofdirect capital costs associated with the Fuel Cell Program. In addition, as discussed in Exhibit SCE-02,Volume 10, SCE forecasts $0.890 million of O&M expense in 2012, 2013, and 2014. SCE has includedboth the annual capital revenue requirement associated with the capital investment of $19.1 million andthe forecast annual O&M expenses of $0.890 million in its 2012, 2013, and 2014 ABRR. If this proposalis adopted in this proceeding, beginning on January 1, 2012, SCE will no longer record the revenuerequirement in the FCPMA, and the FCPMA will be eliminated.Ordering Paragraph No. 4 of D.10-04-028 authorizes SCE to recover the revenuerequirement of the Fuel Cell Program as long as the amounts do not exceed $19.1 million of direct capitalexpenditures and $8.9 million of O&M over the ten year life of the program, the costs are consideredreasonable. As supported in SCE-02, Volume 10, SCE has forecasted O&M and capital to be included inthe 2012 GRC revenue requirement consistent with the requirements of D.10-04-028.6. Continuation Of The Mohave Balancing Account (MBA)In D.06-05-016 the Commission authorized SCE to establish the two-way MBA to recordthe difference between: (1) recorded capital-related revenue requirement, operating expenses and workerprotection expenses associated with Mohave Generating Station; and (2) the authorized Mohave revenuerequirement adopted in D.06-05-016. In D.09-03-025 the Commission affirmed the authorization tocontinue to use the MBA during the 2009 through 2011 period. Pursuant to the terms of PreliminaryStatement, Part NN, MBA, any over- or under-collection in the account is transferred on an annual basisto the BRRBA to be recovered from or returned to SCE’s customers. SCE must support entries recordedin the MBA in an annual April ERRA review proceedings.As discussed in Exhibit SCE-02, Volume 1, SCE is requesting no change in the currentratemaking for Mohave and requests the continuation of the MBA during the 2012 through 2014 period.If this proposal is adopted, in the advice letter filed in compliance with a final Commission decision inthis proceeding, SCE will modify Preliminary Statement, Part NN, MBA, as necessary (e.g., include the2012 authorized revenue requirement).7. Continuation Of The Post-Retirement Benefits Other Than Pensions BalancingAccount (PBOPBA)SCE proposes to continue the PBOPBA during the 2012 GRC cycle as these costs can varysignificantly from the forecast. If this proposal is approved in this proceeding, in the advice letter to befiled in compliance with a final Commission decision in this proceeding, SCE will modify PreliminaryStatement, Part PP as required (e.g. include the 2012 authorized revenue requirement).35

1234567891011121314151617181920212223242526272829The purpose of the PBOPBA is to record the difference between: (1) PBOP expensesauthorized by the Commission; and (2) recorded PBOP expenses, after capitalization. The balance in thePBOPBA will be carried forward each month through the end of each year. The balance recorded in thePBOPBA at the end of each year is transferred to the BRRBA and consolidated into rate levels on anannual basis. Entries recorded in the PBOPBA in each calendar year are reviewed in SCE’s ERRA reviewproceedings filed on April 1 st of each subsequent year.8. Continuation Of The Pensions Cost Balancing Account (PCBA)SCE proposes to continue the use of the PCBA during the 2012 GRC cycle as these costscan vary significantly from the forecast. If this proposal is approved in this proceeding, in the advice letterfiled in compliance with a final Commission decision in this proceeding, SCE will modify PreliminaryStatement, Part OO as required (e.g. include the 2012 authorized revenue requirement).The purpose of the PCBA is to record the difference between: (1) pension expensesauthorized by the Commission; and (2) recorded pension expenses, after capitalization. The balance in thePCBA will be carried forward each month through the end of each year. The balance recorded in thePCBA at the end of each year is transferred to the BRRBA and consolidated into rate levels on an annualbasis. Entries recorded in the PCBA in each calendar year are reviewed in SCE’s ERRA reviewproceedings filed on April 1 st of each subsequent year.9. Continuation Of Research, Development And Demonstration Adjustment Clause(RDDAC)SCE proposes to continue the use of the one-way RDDAC balancing account to ensure thatRD&D funds authorized in the GRC are spent on RD&D programs. 34 The purpose of the RDDAC is torecord the difference between: (1) the authorized RD&D funding level reflected in the ABRR; and (2) therecorded RD&D program expenses. Any unspent funds as of December 31 st of each year are carriedforward in the RDDAC to the subsequent year until the next GRC. As discussed in SCE-03, Volume 2,SCE is requesting RD&D funding at the currently authorized levels.10. Continuation of the Employee Stock Option Plan Tax Memorandum Account(ESOPTMA)In D.09-03-025, the Commission adopted SCE’s proposal to establish the ESOPTMA torecord the revenue requirement impact of including the Schedule M dividends paid to ESOP participants.34 The RDDAC was first established in D.87-12-066. The Commission in D.06-05-016 and D.09-03-025 allowed SCE tocontinue to use the RDDAC during the 2006 and 2009 GRC cycles.36

123456789101112131415161718192021222324252627282930In the 2009 GRC, SCE stated that there were pending Internal Revenue Service regulations that wouldallow the ESOP deduction to be claimed only by SCE’s parent company, Edison International, the payerof the dividends, and not the company that maintains the 401(k) plan. However, in the 2009 GRC revenuerequirement, SCE continued to provide customers with the projected tax benefit associated with thedividends to be paid on the Edison International stock held in the SCE ESOP. If these regulations becomefinal, there will be no deduction available, and SCE’s GRC revenue requirement will be understated. Withthe establishment of the ESOPMA, if these regulations become final, SCE will have the opportunity torecover the revenue requirement shortfall should the IRS not allow SCE to take the deduction.As of the date of this Application, the regulation still is not final. As discussed in ExhibitSCE-10, Volume 2, SCE proposes to continue providing customers the projected tax benefit of the ESOPdividend deduction. Therefore, SCE also proposes to continue the ESOPTMA to track the revenuerequirement associated with this ESOP tax deduction to preserve the opportunity to recover that revenuerequirement if the proposed regulation is finalized.11. Continuation Of Reliability Investment Incentive Mechanism (RIIM)From 1997 through 2008, SCE operated with a form of reliability incentive mechanism inwhich it could earn rewards or suffer penalties based on its performance relative to benchmarks forfrequency and duration of electric service interruptions. The first such mechanism was adopted for SCE inD.96-09-092. More recently, the Commission authorized a modified version of a distribution reliabilitymechanism in SCE’s 2003 GRC, D.04-07-022.In SCE’s 2006 GRC, SCE, the Coalition of California Utility Employees (CUE), and TheUtility Reform Network (TURN) entered into a stipulation asking for Commission approval to establishthe RIIM. The RIIM replaced the benchmark-based reliability mechanism with a system focused onreliability-related capital expenditures and workforce increases. If SCE did not spend as much asauthorized, or increase certain workforce categories consistent with RIIM targets, funds would bereturned to customers at the end of the rate case cycle. The RIIM was based on SCE’s priority system forcapital expenditures, allowing funds to flow to higher priority requirements as circumstances dictated.The Commission approved that stipulation in D.06-05-016.In SCE’s 2009 GRC, SCE and CUE served testimony recommending the Commissioncontinue the RIIM, however each party proposed different modifications to the RIIM framework. In D.09-03-025, the Commission adopted a settlement between SCE and CUE. Resolution E-4313 implemented37

12345678910111213141516171819202122232425262728the RIIM to be in effect during the 2009 GRC (i.e. through the implementation date of the Phase 1decision in the 2012 GRC). 35As discussed by Mr. Kelly in Exhibit SCE-03, Volume 1, SCE is proposing to continue theRIIM during the 2012 GRC cycle which will end on December 31, 2014. If this proposal to continue theRIIM is adopted, SCE will modify Preliminary Statement, Part LL, RIIM, to include the new AuthorizedRIIM Expenditures and capital additions for 2012 through 2014.12. Interaction With Other Proceedingsa) 2007 Wind and Firestorm Catastrophic Events Memorandum Account CostRecovery ProceedingThe Commission authorized SCE to activate its Wind and Firestorm (W&F)CEMA effective October 21, 2007. The purpose of the W&FCEMA is to record the incremental O&Mexpenditures and the revenue requirement on the incremental capital additions associated with restoringservice to customers repairing damage to facilities caused by the fires that raged through Los Angeles,Orange, Riverside, San Bernardino, Santa Barbara and Ventura Counties, and wind damage that wasincurred in Riverside County. On April 22, 2010, SCE filed A.10-04-026 to seek recovery ofapproximately $10.5 million of incremental O&M and capital-related revenue requirement associatedwith the W&FCEMA. The incremental O&M costs of $6.837 million have been removed from the 2007and 2008 recorded GRC-related costs. Therefore, the W&F CEMA O&M costs are not included in SCE’srequested 2012, 2013, and 2014 ABRR.The reasonableness of SCE’s incremental W&F capital additions will bedetermined in the W&FCEMA proceeding. Although SCE has included the revenue requirementassociated with the W&F capital additions in its 2012, 2013, and 2014 ABRR, SCE is not seeking thereasonableness of those capital additions in this GRC application. If the Commission issues a finaldecision in A.10-04-026 that disallows any W&F capital costs, SCE will remove the associated revenuerequirement from its requested 2012, 2013, and 2014 ABRR. Once the Commission issues a final 2012GRC Phase 1 decision and a final decision in the W&F CEMA Application, no additional amounts will berecorded in SCE’s W&FCEMA and the recorded balance in the W&FCEMA will be transferred to theBRRBA for recovery in rates.35 Resolution E-4313 authorizes SCE to escalate the 2009 capital expenditures and additions by 4.25% to derive its 2010capital expenditures and additions, and escalate the 2010 results by 4.35% for 2011.38

1234567891011121314151617181920212223242526272829b) Fire Hazard Prevention Memorandum Account (FHPMA)In D.09-08-029 (Decision in Phase 1 of R.08-11-005), the Commission found itreasonable for SCE to recover costs prudently incurred to comply with the vegetation managementmaintenance changes adopted in the decision. In order to allow SCE to recover these costs, D.09-08-029authorized SCE to establish the FHPMA. The Commission stated in that decision that the proper forumfor recovery of costs recorded in the FHPMA will be Phase 2 of the OIR. The Commission didcontemplate including these fire prevention costs in each utility’s general rate case in D.09-08-029.However, at the time SCE is filing the Notice of Intent of the 2012 GRC, the requirements of Phase 2 ofthe OIR are not known. Therefore, as supported in SCE-03, Volume 4, SCE has included in its 2012,2013, and 2014 CPUC jurisdictional revenue requirement (i.e., ABRR) a forecast of the fire hazardprevention costs required in D.09-08-029 (i.e. Phase 1 of R.08-11-005). If recovery of the Phase 1 costs inthis GRC Application is adopted, SCE will discontinue recording the Phase 1 fire hazard prevention costsin the FHPMA upon the effective date of the 2012 GRC revenue requirement. SCE will continue to usethe FHPMA to record the costs mandated in Phase 2 of R.08-11-005 until those costs can be included in afuture GRC revenue requirement..c) SONGS 2&3 Steam Generator Replacement Cost RecoveryThe Commission in D.05-12-040 adopted SCE’s request to replace the originalSONGS 2&3 steam generators and to establish cost recovery mechanisms for capital-related revenuerequirements associated with both the removal and disposal of the original steam generators, and the newreplacement generators. 36 On June 30, 2009, SCE filed Advice Letter 2355-E in compliance with D.05-12-040 to establish two balancing accounts, the SONGS 2&3 Steam Generator Replacement BalancingAccount and the SONGS 2&3 Steam Generator Removal and Disposal Balancing Account. In early 2010,the two generators in SONGS Unit 2 were replaced and in the fall of 2010, SCE will begin to replace thetwo generators in Unit 3. SCE will record and recover the capital–related revenue requirements for thesteam generator replacement project through these two balancing accounts through the 2012 GRC cycle(i.e. through the end of 2014). Therefore, SCE has not included the capital costs associated with the steamgenerator replacement project in the 2012, 2013, and 2014 ABRR. SCE will propose to include theassociated steam generator replacement revenue requirement in the GRC revenue requirement in its 2015GRC.36 All of the O&M expenses for SONGS are recovered through GRC revenue requirement and are not subject to balancingaccount treatment.39

1234567891011121314151617181920212223242526d) Four Corners Capital Expenditure Memorandum Account (FCCEMA)D.09-03-025 established the Four Corners Capital Expenditures MemorandumAccount to record the revenue requirement associated with the 2009 capital expenditure forecast includedin the 2009 GRC. 37 The Commission in D.09-03-025 excluded the associated revenue requirement fromthe 2009, 2010, and 2011 GRC revenue requirements because recovery of those capital costs was subjectto the outcome of a final Commission decision in R.06-04-099. 38 If, as a result of the Commission’sdecision in R.06-04-099, recovery of the revenue requirement associated with all of the Four Cornerscapital expenditures can appropriately be included in SCE’s 2012, 2013, and 2014 GRC revenuerequirements adopted in this proceeding, the FCCEMA can be eliminated. If there are capital expendituresthat the Commission excludes from being included in the calculation of the 2012, 2013, and 2014 GRCrevenue requirements and still provides SCE the opportunity to recover the costs in the future, SCE willretain the FCCEMA.13. Elimination Of Six Ratemaking Accountsa) Project Division Development Memorandum Account (PDDMA)D.06-05-016 established the PDDMA to track the support costs incurred by theProject Development Division (PDD). Since the PDD support costs were excluded from the 2006, 2007,and 2008 CPUC-jurisdictional GRC revenue requirement SCE has had the opportunity to recover thePDD support costs recorded in the PDDMA after review in its annual ERRA review proceedings. Therecorded costs in the PDDMA include, for example, support function costs related to identifying locationsfor new generation and evaluating generation technologies. Costs related to proposed project developmentare excluded from the PDDMA. The Commission again required SCE to exclude the forecast of the PDDfrom the 2009, 2010, and 2011 CPUC-jurisdictional GRC revenue requirement in D.09-03-025 andallowed SCE to recover the PDD costs once again through the PDDMA.As discussed in Exhibit SCE-02, Volume10, SCE has included PDD support costsin its 2012, 2013, and 2014 CPUC jurisdictional revenue requirement (i.e., ABRR). Since 2006, the PDDsupport costs have been relatively stable and predicable. Therefore, the PDDMA is no longer required.37 The Commission excluded the 2009 through 2011 capital expenditures from the GRC revenue requirement calculation.However, the Commission did not authorize any capital expenditures and additions beyond 2009, and allowed SCE toincrease its 2009 total GRC revenue requirement by 4.25% and 4.35% to determine its 2010 and 2011 GRC revenuerequirements, respectively.38 At the time SCE tendered its Notice of Intent in this proceeding there is an Administrative Law Judges Proposed Decisionpending Commission action.40

1234567891011121314151617181920212223242526272829303132SCE requests that once the Commission has issued a final 2012 GRC Phase 1 decision, no additionalPDD support costs will be recorded in the PDDMA. Any remaining balance recorded in the PDDMA willbe reviewed in the next ERRA review proceeding consistent with Preliminary Statement, Part N.44,PDDMA.b) Results Sharing Memorandum Account (RSMA)D.06-05-016 established the RSMA for the purpose of comparing the authorizedand actual Results Sharing expenses paid out. If authorized amounts exceed actual payout amounts (i.e.,over-collections), that over-collection is returned to customers through the Base Revenue RequirementBalancing Account. If the actual payout amounts exceed authorized amounts (i.e., under-collections), thatunder-collection is not recoverable. Although the Commission found SCE’s request for Results Sharingreasonable in D.09-03-025, it required SCE to continue to use the RSMA during 2009 through 2011period. As discussed in Exhibit SCE-06, Volume 2, SCE is requesting the elimination of the RSMA sincethe Results Sharing program was redesigned to provide rewards based on corporate and business unitgoals, with one budget-related goal, which should alleviate the concerns the Commission had of theprogram requested in SCE’s 2006 and 2009 GRCs.c) Medical Program Balancing Account (MPBA)D.09-03-025 required SCE to establish the MPBA. The purpose of the MPBA is torecord the difference between: (1) medical, dental and vision expenses authorized in D.09-03-025; and(2) medical, dental and vision expenses, after capitalization. In the 2009 GRC proceeding, SCE did notrequest to establish a balancing account for its medical programs, nor did any other party. As discussed inExhibit SCE-06, Volume 2, SCE is including a forecast of its medical program expenses in its 2012,2013, and 2014 ABRR and is requesting elimination of the MPBA effective the date of the Phase 1decision in this proceeding.d) Palo Verde O&M Balancing Account (PVO&MBA)D.09-03-025 required SCE to establish the PVO&MBA. The purpose of thePVO&MBA is to record the difference between 1) SCE’s share of Palo Verde-related O&M, overheadloadings for Administrative & General (A&G) expense, Pension & Benefits (P&B), and Payroll Taxexpenses: and SCE’s oversight expenses authorized in the Commission in D.09-03-025; and (2) actualPalo Verde-related O&M expense billed by Arizona Public Service Company (APS) under the Palo VerdeOperating Agreement for SCE’s share of expenses, including refueling outage O&M expense andcontractual overheads for A&G, P&B, and Payroll taxes; and, actual SCE oversight expenses. Assupported in Exhibit SCE-02, Volume 3, SCE has included in its 2012, 2013, and 2014 CPUC41

1234567891011121314151617181920212223242526272829jurisdictional revenue requirement (i.e., ABRR) a forecast of the Palo Verde O&M expenses. Therefore,the PVO&MBA will no longer be necessary upon a final Commission decision in this Application and theaccount can be eliminated.e) Community Choice Aggregators’ Implementation Cost Balancing Account(CCAICBA)D.04-12-046 established the CCAICBA for the purpose of recording costs incurredto implement Community Choice Aggregation programs. Prior to D.09-03-025, Preliminary Statement,Part MM, required SCE to record implementation expenses related to CCA programs in accordance withD.04-12-046. In compliance with D.09-03-025, Preliminary Statement, Part MM, was modified to alsorecord on-going support and maintenance expenses and billed Other Operating Revenue as a result of theCCA activities approved in the 2009 GRC. As discussed in Exhibit SCE-04, Volume 2, SCE has includeda forecast of CCA program costs in its 2012, 2013, and 2014 CPUC jurisdictional revenue requirement(i.e., ABRR). SCE is requesting elimination of the CCAICBA as SCE believes it can adequately estimatethe amount of CCA-related expenses in the GRC revenue requirement and these costs should no longer besubject to a balancing account.f) Non-Discretionary Services Cost Memorandum Account (NDSCMA)D.08-05-003 authorized SCE to establish the NDSCMA to record SCE’sincremental costs incurred for providing non-discretionary services. Specifically, SCE was required totrack the costs of processing Direct Access Service Requests, voluntary and involuntary ESP Terminationof Services, ESP Service Establishment services, Customer Information Service Request (CISR) services,ESP Non-Energy Billing Receivables services, Meter Establishment services, and Monthly AccountMaintenance services. As supported in Exhibit SCE-04, Volume 4, SCE has included a forecast of thesenon-discretionary service costs in its 2012, 2013, and 2014 CPUC jurisdictional revenue requirement(i.e., ABRR). Therefore, the NDSCMA is no longer required. SCE requests that once the Commission hasissued a final 2012 GRC Phase 1 decision, no additional non-discretionary service costs will be recordedin the NDSCMA. Any remaining balance recorded in the NDSCMA will be reviewed in the next ERRAreview proceeding consistent with Preliminary Statement, Part N.44, NDSCMA, which requires reviewand disposition of amounts recorded in the NDSCMA to be determined in an appropriate Commissionproceeding.42

12345678910111213141516171819202122232425262728293031V.SALES AND CUSTOMER FORECASTThis section presents the forecast of retail electricity sales in the SCE service area for the TestYear period. It consists of a summary of the forecast and a brief description of the methodology used toproduce the forecast. We also briefly describe the major factors and assumptions that influence theforecast.A. Sales Forecast SummaryTotal electricity sales in the SCE service area were 85,849 GWh in 2009. We are predicting salesof 83,334 GWh in 2010, 84,729 GWh in 2011 and 85,920 GWh in 2012. The predicted decline between2009 and 2010 is due mainly to the transition from above normal summer season weather in 2009 tonormal weather in 2010. A very moderate economic recovery is projected to begin in 2011, which isreflected in our forecast of a 1.7 percent increase in electricity sales between 2010 and 2011 and 1.4percent between 2011 and 2012.B. MethodologySCE uses econometric models to forecast monthly retail electricity sales (recorded sales as billed,and measured at the customer meter) by customer class. Retail sales include final sales to both bundledand direct access customers within the SCE service territory. It excludes sales to public power customers,contractual sales, or inter-changes with other utilities.The retail sales forecast represents the sum of sales in seven customer classes: residential,commercial, industrial, other public authority, agriculture, street lighting and inter-department transfers(IDT). Each customer class forecast (with the exception of IDT) is itself the product of two separateforecasts: a forecast of electricity consumption per customer or per building square feet and a forecast ofthe number of customers or total building square feet. The IDT sales forecast, which represents a verysmall percentage of total retail sales, is based upon the average of recorded monthly sales over the mostrecent 12 month historical period.Econometric models employ statistical techniques to quantify the relationship between electricityconsumption and the various economic, demographic and other factors that are thought to influenceelectricity consumption. Examples of such variables are weather, electricity rates, number of billing days,SCE energy efficiency program savings, employment, personal income and building floor stock.Historical data are used to determine these relationships. The typical estimation procedure used toconstruct these models is ordinary least squares (OLS).43

1234567891011121314151617181920212223242526272829303132Once a satisfactory statistical relationship is established, SCE uses historical average values ofweather (specifically, cooling and heating degree days) and billing days to represent typical or normalconditions in future periods. Forecasts of economic drivers such as employment, income and buildingfloor stock, along with the typical weather and billing day variables, are then “plugged into” the models inorder to derive forecast values of electricity consumption per customer. Global Insight, Moody’sEconomy.Com, and McGraw-Hill are the principal sources of employment, income and floor stock data,both historical and forecast.Model-generated forecasts may be modified based on current trends, judgment, and events that arenot specifically modeled in the econometric equations.As indicated, a different set of models are used to estimate and forecast the number of customersby customer class. The forecast of residential customer additions is generated using a non-econometricapproach. In this case, we use a stock adjustment model that calculates changes in the stock of occupiedresidential housing in the SCE service area according to the number of residential building permits issued.The relationship between changes in permits and housing is subject to a time-lag in order to account forconstruction activity. Combined with assumptions concerning residential demolition rates and residentialvacancy rates, the model uses the forecast of residential building permits to estimate additions to thecurrent period occupied housing stock, which are in turn converted to additions to SCE’s residentialcustomer base.Forecasts of non-residential customers are based on econometric models that relate changes in thenumber of non-residential customers to a change in economic activity. For example, changes in thenumber of commercial customers are assumed to be influenced by changes in the number of residentialcustomers. In the case of agricultural customers, the economic variable is agricultural employment andchanges in the number of industrial customers are dependent upon changes in manufacturing employment.C. Historical TrendsOn a recorded basis, SCE total electricity sales increased at an average annual rate of 1.9 percentper year between 2001 and 2008. The major factor responsible for this relatively high annual rate ofgrowth was high levels of new residential and commercial customers, which in turn was a consequence ofrapid employment growth as the California economy emerged from the 2001-2002 recession.The year over year percent change in total non-farm employment growth in the SCE service areaduring the years 2001 to 2009 is shown in Figure V-3 below. After the low point of the previouseconomic recession in early 2002, employment growth turned positive in 2003, and then acceleratedsharply in 2004 and continued strong until mid 2006. Employment growth slowed in 2007 and finally44

123456789turned negative in 2008. At the peak of this economic cycle, SCE customer additions reached 72,500 in2005 and new meter connections reached nearly 88,000 in 2006, the highest meter connection level since1990.To a large extent, employment growth during the 2002 to 2006 economic expansion was fuelledby the dramatic growth in the Southern California new housing construction. As shown in Figure V-3below, new housing construction activity began a steady upward climb beginning in 2002. Permitsreached a peak in 2004 then fell slightly in 2005. The end of the housing construction boom was signaledwhen permits declined 15 percent between 2005 and 2006. Further steep declines in the number ofpermits followed in 2007 through 2009.Figure V-3Total Non-Farm Employment Growth in the SCE Service Area4.0%3.0%2.0%Year Over Year % Chg1.0%0.0%-1.0%-2.0%-3.0%-4.0%-5.0%-6.0%Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-101011121314Although the current economic recession started in late 2007, warmer than normal summertemperatures caused 2008 sales to increase over 2007. However, in 2009, the effect of the recession wassignificant, as sales were 4.4 percent below the 2008 level.The loss of jobs, the sharp reduction in customer and meter additions, and an absolute decline inretail sales in 2009, are all indicators of the current recession’s impact on Southern California economic45

12activity and on SCE electricity sales. It is against this historical background that SCE is forecasting lowersales in 2010 compared to 2009 and modest growth in 2011 and 2012.Figure V-4Residential Building Permits in the SCE Service Area80,00070,00060,00050,00040,00030,00020,00010,0000Actual to 2009ForecastSource: Census Bureau, Global Insight34567891011D. Economic Outlook20142013201220112010200920082007200620052004200320022001With the economic background described above, Global Insight is forecasting a very slowrecovery in employment and residential building permits in 2010 and 2011. For example, as shown inFigure V-5 below, employment growth is expected to remain negative in 2010 and increase only 2.5percent in 2011. Residential building permits in the SCE service area in 2010 are expected to reach just14,261, about 21 percent of the 2002 to 2006 average. We expect about 25,400 permits in 2011, arespectable improvement compared to 2010, but still well below the number experienced during the 2002-2006 housing boom as shown in Figure V-4 above. The recession is projected to officially end in 2010,but economic growth is expected to be very modest for the next few years.46

Figure V-5Total Non-Farm Employment Growth in SCE Service Area, Actual andForecastAnnual Percent Change4.0%3.0%2.0%1.0%0.0%-1.0%-2.0%-3.0%-4.0%Actual to 200920142013201220112010200920082007200620052004200320022001Forecast-5.0%Source:Global Insight123456789E. Weather AssumptionsSCE uses 30 year average temperature conditions as its definition of normal weather. Normalweather conditions are assumed throughout the forecast period. For purposes of model estimation andforecasting, actual and normal temperature data are transformed into cooling degree days (a measure ofsummer season cooling load) and heating degree days (a measure of winter heating load). As shown inFigure V-6 below, the SCE service area experienced 4 consecutive years, 2006 to 2009, with higher thannormal cooling degree days. The forecast for 2010 and beyond assumes normal weather. Thus, a slowingtrend is automatically built into the forecast for 2010 as electricity sales transition from 2009, a year ofwarmer than normal summer weather, to normal summer weather in 2010.47

Figure V-6Recorded and Normal Cooling Degree Days5,0004,5004,0003,5003,0002,5002,0001,5001,0005000Actual to 2009Forecast (Normal)1234567891011121314151620142013201220112010200920082007200620052004200320022001F. Other Factors Influencing the ForecastOther factors influencing the growth trend in total retail sales during the test period are electricityrates, energy savings from energy conservation programs and self-generation.The average electricity price in 2010 is expected to remain approximately equal to the 2009 level,but increase in 2011 due to higher fuel prices and expenditures associated with the 2012 GRC application.Historical and forecast system average prices are shown in Figure V-7 below. All other things equal, theimpact of higher electric rates is a reduction in average electricity use per customer.Energy efficiency savings represent electricity consumption that would have taken place in theabsence of specific utility-funded programs. Therefore, the forecast of total retail sales in 2010 through2014 would have been higher in the absence of these programs.Methodologically, historical energy efficiency savings are added back to recorded retail sales togenerate a value of “energy consumption” — what would have taken place in the absence of theprograms. The forecast equations utilize this energy consumption data. The forecast equations produceforecasts of energy consumption, from which the forecast of energy efficiency savings are deducted toyield the forecast of retail sales. Self-generation from thermal and solar (photo-voltaic) sources is treatedin a similar way as energy efficiency.48

12345Energy efficiency savings in 2010 and 2011 are based upon the approved Program Year fundingand energy efficiency goals and for 2012 to 2014 are based on the ‘Total Market Gross” goals adopted inD. 08-07-047 and modified in D. 09-09-047. Also included are estimates of the effects of increasinglystringent Federal efficiency standards for air-conditioners and heaters and State building code standardsaffecting lighting intensities.Figure V-7Average System Electricity Price, Actual and Forecastcents per kWh20.018.016.014.012.010.08.06.04.02.00.0Actual to 2009Forecast67891020142013201220112010200920082007200620052004200320022001G. Total Retail Sales Forecast by Customer ClassTable V-13 below presents the Test Year period forecast of total electricity sales by customerclass. The table shows actual recorded sales in 2009 and the forecast for the years 2010 to 2014. Theprojected average annual growth in total retail sales is about 1.5 percent per year from 2010 to 2012,compared to the 1.9 percent average annual growth experienced between 2001 and 2008.49

Table V-13Annual Retail Sales by Customer Class (GWh)2009 2010 2011 2012 2013 2014Residential 30,063 28,870 28,608 28,666 29,120 29,543Agricultural 1,432 1,310 1,355 1,368 1,410 1,441Commercial 40,076 39,277 40,787 41,934 42,962 43,789Industrial 8,524 8,279 8,223 8,224 8,355 8,462Public Authorities* 5,754 5,599 5,755 5,729 5,746 5,770Total Retail Sales 85,849 83,334 84,729 85,920 87,593 89,006*Includes public authorities - other, street lighting, special contracts, railways and interdepartmental1234567891011121314H. Customer and New Meter Connection ForecastsTable V-14 and Table V-15 below present the forecasts for the Test Year period of total electricitycustomers and new meter connections by customer class. Both customers and meter connections areclosely tied to activity in the residential construction sector, usually with a lag of 6 to 18 months. In otherwords, a change in the number of new meter connections or new customers is typically a result of achange in the number of building permits that occurred 6 to 18 months earlier. However, with the largebacklog of vacant foreclosed homes, customer growth can temporarily rebound faster than would bepredicted from historical relationships. In appearance, it will look like the lag between housingconstruction and residential customer growth has been shortened, but what is actually happening is thatvacant homes are being sold and occupied, counting as an increase in new customers. This can continueuntil the backlog of vacant homes is sold off. Our forecast of customers and new meters follows closelythe housing market cycle described above, but also accounts for a decreasing vacancy rate. Over the testyear period, total customer growth averages about 1 percent per year, which is somewhat lower than the1.2 percent average annual growth recorded between 2001 and 2008.Table V-14Year-End Customers by Customer Class2009 2010 2011 2012 2013 2014Residential 4,262,966 4,284,484 4,308,993 4,338,689 4,374,484 4,413,422Agricultural 22,315 22,306 22,298 22,295 22,297 22,304Commercial 539,270 543,304 548,079 554,556 562,841 572,356Industrial 12,244 11,810 11,512 11,400 11,330 10,978Public Authorities* 46,992 46,788 46,525 46,265 46,063 45,925Total Retail Sales 4,883,787 4,908,692 4,937,407 4,973,206 5,017,015 5,064,986*Includes public authorities - other, street lighting, special contracts, railways and interdepartmental1516New meter connections reached a 17 year high of about 88,700 in 2006 and then plummeted to32,145 in 2009 as the housing market collapsed. Given the housing construction outlook, we expect the50

12number of new meter connections to decline further to 29,799 in 2010, and then increase to 35,527 in2011 and 46,393 in 2012.Table V-15New Gross Meter Connections2009 2010 2011 2012 2013 2014Residential 23,643 22,324 28,215 38,591 46,853 49,732Agricultural 424 360 360 360 360 360Non-Residential 8,078 7,115 6,953 7,443 8,627 9,869Total New Meters 32,145 29,799 35,527 46,393 55,839 59,9613456789101112I. September 2009 Forecast of Customers and New Meter ConnectionsSCE's forecast of customers, sales, and new meters presented above was finalized in March 2010and represents SCE’s most current forecast at the time this testimony was written. SCE used this forecastfor calculating the revenue increases presented in this Results of Operations volume of testimony. Theforecast was not available in time for use by some other SCE departments for use in calculating customeror load growth-related expense and capital forecasts found in other volumes of SCE’s testimony. Thesedepartments relied upon the earlier September 2009 forecast of customers, meter sets, and load growth.Table V-16 and Table V-17 below show these earlier forecasts. The forecast methodology used in makingthe September 2009 forecast is very similar to that of the March 2010 forecast described in the abovesections, but necessarily used inputs from an earlier forecast of the economy.Table V-16September 2009 Forecast of Year-End Customers by Customer Class2009* 2010* 2011* 2012* 2013* 2014*Residential 4,261,611 4,276,612 4,296,650 4,326,685 4,364,698 4,412,709Agricultural 22,390 22,364 22,347 22,335 22,325 22,320Commercial 538,978 541,729 545,202 550,791 558,775 569,453Industrial 11,700 10,325 9,834 9,755 9,660 9,397Public Authorities** 47,289 47,043 46,746 46,524 46,400 46,3814,881,968 4,898,075 4,920,780 4,956,090 5,001,858 5,060,260* Forecasts** Includes Public Authoirties-Other, Streetlights, Special Contracts, Railroads, andInterdepartmental51

Table V-17September 2009 Forecast of New Gross Meter Connections2009* 2010* 2011* 2012* 2013* 2014*Residential 22,034 22,013 32,147 42,917 51,949 58,139Agricultural 450 300 300 300 300 300Non-Residential 11,564 10,943 10,848 10,987 11,217 11,435Total New Meters 34,047 33,256 43,295 54,205 63,466 69,874* Forecasts12Note that the values for 2009 in Table V-16 and Table V-17 above are forecasts, as only partialdata was available at the time the September 2009 forecast was completed.52

1234567891011121314151617181920212223242526272829303132VI.PRESENT RATE REVENUEThis Chapter supports the development of both the Total System Present Rate Revenue (TSPRR)and the GRC-Related Present Rate Revenue (GRCPRR), and discusses the differences between the twoamounts. As explained below, the GRCPRR is a subset of the TSPRR and is used to determine theestimated revenue change requested in this proceeding for 2012, 2013, and 2014.A. Total System Present Rate RevenueTSPRR is based on the kilowatt-hour (kWh) sales forecast included in Chapter V of this volumeand rate levels based on SCE’s rates effective pursuant to Decision No. 10-02-19, ERRA Advice Letter2446-E on March 1 2010. This section provides the forecast TSPRR for test year 2012, and post-test years2013 and 2014. Recorded sales and revenues for base year 2009, and forecast sales and revenues for theyears 2010 and 2011 are also provided.1. Methodology For The Development Of Total System Present Rate Revenue Estimatesa) Forecast Of SalesChapter V of this volume forecasts SCE’s net kWh sales by revenue class through2014. The five defined revenue classes are: Residential, Commercial, Industrial, Agricultural, and OtherPublic Authorities (OPA). These forecasts include customers by revenue class as well. The determinationof the TSPRR requires converting these revenue class forecasts to forecasts of billing determinants by rategroup. The TSPRR is then the product of present rates and the forecast billing determinants. The basicrate groups that we use to develop the TSPRR are defined in subsection (b) below.b) Revenue Class And Rate Group Statistical DataIndividual customer usage statistics generally are aggregated and summarized bytwo broad categories: revenue class and rate schedule. Revenue class data aggregate usage statistics bysimilar end-use criteria. Rate schedule data aggregate usage statistics by groupings with relativelyhomogeneous load characteristics and methods of service.In nearly all Company-sponsored publications, statistical data is compiled andreported by revenue class, consistent with our procedures for reporting to the Federal Energy RegulatoryCommission (FERC). Retail revenue classes are designated as follows:• Residential.• Agricultural.• Commercial.• Industrial.53

12345678910111213141516171819202122232425262728293031• Other Public Authorities.These classifications are generally accepted by the electric utility industry forstatistical reporting. In addition, many government and industry statistical series are gathered and reportedon this basis. These classifications are widely used, and are broadly understood. Data aggregated by theseclassifications provide information that tends to be predictable with some degree of confidence.Statistical data is also gathered by rate schedule and is grouped and compiledaccording to rate group for ratemaking purposes. Rate groups are designated as follows:• Domestic.• GS-1: Lighting – Small and Medium Power, Non-Demand-Metered.• GS-2: Lighting – Small and Medium Power, Demand-Metered.• TOU-GS: Lighting – Small and Medium Power, Time-Of-Use.• TC-1: Traffic Control.• Large Power – Secondary Voltage.• Large Power – Primary Voltage.• Large Power – Subtransmission Voltage.• PA-1: Agricultural and Pumping, Connected Load.• PA-2: Agricultural and Pumping, Demand-Metered.• AG-TOU and TOU-PA-5: Agricultural and Pumping, Time-Of-Use.• Street and Area Lighting.These groupings enable costs to be allocated to groups of customers with relativelyhomogeneous load characteristics and methods of service, and provide a link between incurrence of costs,development of rates, and recovery of revenues. For example, non-domestic customers who, as a group,use relatively small amounts of energy and have relatively small demands are grouped together as theLighting-Small and Medium Power, Non-Demand-Metered Rate Group. The rate groups listed above,with some modification, have been retained over time to generally provide for consistency of data fromone GRC to the next.The interrelationship between revenue class and rate group can be demonstrated bydescribing how these classifications relate to individual rate schedules through an example.Assume there are only two revenue classes of customers, Commercial andIndustrial, and only two rate groups: (1) Lighting - Small and Medium Power, Non-Demand-Metered,and, (2) Large Power - Secondary Voltage. In addition, assume only two rate schedules: GS-1 and54

12345TOU-8-S. Commercial and Industrial customers would be allowed to take service in either of these rateschedules, but customers on Schedule GS-1 would be included in the Lighting – Small and MediumPower, Non-Demand-Metered Rate Group, while customers on Schedule TOU-8-S would be included inthe Large Power Group – Secondary Voltage Rate Group. This situation is illustrated in Table VI-18,below.Table VI-18Revenue Classes By Rate GroupLineNo. Revenue Class Rate Group1.2.Commercial Industrial Lighting – Small & MediumPower – Non-Demand- Metered3. GS-1 GS-1 GS-1Large Power –Secondary Voltage4. TOU-8-S TOU-8-S TOU-8-S678910111213141516171819202122c) Forecast Of Billing Determinants By Rate Schedule(1) Description Of Forecasting MethodologySCE uses statistical methods to analyze time-series data to forecast kWhsales by revenue class by rate schedule based in part upon five years of recorded data. Other relatedbilling determinants by rate schedule, such as usage by time-period, are derived from the forecast kWhsales and historical usage patterns.The statistical models forecast kWh and average customers for each rateschedule within each revenue class. These independent forecasts of kWh by rate schedule by revenueclass are then normalized to the total revenue class kWh forecasts described in Chapter V of this exhibit.(2) Forecast Of Billing DeterminantsUsing the above-described method, rate schedule bill month forecasts arealso normalized to match the revenue class forecasts. Kilowatt-month forecasts are tied to the kWh andbill-month forecasts based on both a direct forecast of billing demand by rate schedule and by historicalload factors. The final output of the model is a forecast of billing determinants in total for each rateschedule. These billing determinants are then spread to the appropriate rate block and/or time periodbased on historical relationships to develop the billing determinants by rate schedule necessary to estimatethe TSPRR.55

123456789101112131415162. Total System Present Rate Revenue ForecastThe billing determinants (customer usage data, such as: kWh sales, billingkilowatt-months, billing horsepower, bill months, number and type of lamps, voltage and power factoradjustment data, and other miscellaneous customer-usage data) developed for each rate schedule are thenmultiplied by the various billing factors for each rate schedule. In addition, SCE forecasts both Bundledand Direct Access (DA) customer billing determinants separately since these customers pay differentgeneration-related charges. 39This product of billing factors and billing determinants, for both Bundled and DAcustomers is, in fact, developed separately for generation, including Utility Retained Generation (URG)and Department of Water Resources (DWR) generation, as well as DA-related charges, distribution,transmission, nuclear decommissioning, public purpose programs, trust transfer amount, and othermiscellaneous revenue components. The sum of these component revenues is the TSPRR.TSPRR is the revenue that is estimated to be billed for service rendered during a particularforecast period. The TSPRR has been estimated for the forecast years 2010 through 2014.Table VI-19 below shows the average number of customers, GWh sales, TSPRR, for baseyear 2009 and for forecast years 2010 through 2014. 4039 The partial reopening of DA presents a challenge for calculating the Present Rate Revenues with regards to generationrevenue. If the number DA KWH and related customers are allowed to rise in accordance with Commission Decision 10-03-022 SCE will under collect its generation revenue in the years beyond 2010. To avoid this problem in the years beyond2010 the DA customer forecast is held constant at the 2010 level, with adjustments for KWH growth consistent with thetotal KWH growth, for the years beyond 2010.40 For purposes of calculating revenues past 2011 under the present rates it is assumed that DWR’s portion of power willremain at 30.36%, DWR’s current share since the revenue currently collected under DWR would be collected bycomparable amounts in other revenue components.56

Table VI-19Average Customers, Sales And Total System Present Rate Revenue2009 through 2014LineNo. Year CustomersSales(GWh)TSPRR*($000)1. 2009 4,874,868 85,848.8 11,315,6372. 2010 4,898,748 83,334.3 11,196,2573. 2011 4,923,608 84,728.7 11,328,9354. 2012 4,955,992 85,919.6 11,464,6325. 2013 4,996,313 87,592.6 11,666,0186. 2014 5,042,591 89,006.0 11,839,008*Years 2009 through 2014 include revenue associated with the kWhsprovided to SCE’s retail customers by DWR.12345678910111213141516B. GRC Present Rate RevenueAs discussed above, the TSPRR reflects the total amount of revenue associated with currentlyadopted rate levels. However in this proceeding, SCE is not requesting a revenue requirement associatedwith the total cost of providing service to retail customers, so comparing the TSPRR to the GRCrequested revenue requirement is not appropriate. Therefore, as discussed in this section, in order todetermine the appropriate amount of revenue change requested in this proceeding, the GRC-relatedPresent Rate Revenue (GRCPRR) must be determined. This section provides the forecast of the GRCPRRfor test year 2012, and post test years 2013 and 2014. Recorded sales and GRC-related revenues for baseyear 2009, and forecast years 2010 and 2011 are also provided.1. Determination Of The GRC Present Rate RevenueConsistent with past GRC applications, SCE’s requested revenue requirement in thisproceeding is only a subset of the total costs to serve its customers. For example, SCE is not seekingrevenue required with the recovery of fuel and purchased power costs. Therefore, the GRCPRR excludesrevenue associated with recovery of fuel and purchased power costs. Table VI-20 below, shows acomparison between Total System cost categories include in each unbundled rate component, and costcategories included in the GRCPRR.57

Table VI-20TSPRR and GRCPRRCost ComponentsCost ComponentsUnbundled Rate TSPRR Included in GRC RevenueComponentsRequirement and GRCPRRGeneration 1) Base Generation 1) Base Generation2) Solar PV Rooftop Prgm 2) Solar PV Rooftop Prgm3) Fuel Cell Prgm 3) Fuel Cell Prgm4) MRTU 4) MRTU5) Fuel6) ProcurementDistribution 1) Base Distribution 1) Base Distribution2) Edison SmartConnect 2) Edison SmartConnect (2012)3) Other DistributionNew System 1) Base Generation (Peakers) 1) Base Generation (Peakers)Generation 2) ProcurementTransmissionNuclearDecommissioning1) Base Transmission2) TRBA3) RSBA4) TACBA1) Trust2) Spent Nuclear FuelNANAPublic Purpose 1) Legislatively mandated PublicPrograms Goods Charge2) Commission authorized PublicPurpose ProgramsNADWR1) Power Charge2) Bond ChargeNA1234562. GRC Present Rate Revenue ForecastTo determine the GRCPRR for each forecast year, SCE first determined the GRC-relatedrate in present rate levels, which is based on the GRC-related revenue requirements and adopted kWhsales used to set rate levels as of March 1, 2010. 41 The GRCPRR shown in Table VI-21 below isdetermined by applying the calculated present GRC-related rates to the kWh forecast set forth in ChapterV of this volume. Table VI-21 also sets forth the average number of customers, and kWh sales for the41 Present rates are those rates implemented in Advice Letter 2446-E submitted in compliance with D.10-02-01958

12345forecast years 2010 through 2014. As discussed in Chapter III of this volume, when determining the totalGRC-related revenue change requested in this proceeding, SCE includes annual GRCPRR sales growthamounts which equal to the change in the GRCPRR from one year to the next. For example, the GRCRevenue Growth amount shown on Table III-5 for 2012 in the amount of $71.9 million is equal to thedifference between the 2012 GRCPRR and the 2011 GRCPRR.Table VI-21Average Customers, Sales and GRC Present Rate Revenue2010 through 201459

1234567891011121314151617VII.COST ESCALATIONA. O&M Cost Escalation1. PurposeThe purpose of this chapter is to explain and justify the escalation rates we used to deflatehistorical O&M and A&G expenses for the years 2005 through 2009; and, forecast O&M and A&Gexpenses for the years 2010 through 2014.Section B summarizes the escalation rates that we developed for use in this case. Section Cprovides the details of the methodology and sources we used to develop the escalation rates. It alsoprovides some special nonlabor escalation rates that we developed for Palo Verde nonlabor O&Mescalation and Four Corners nonlabor O&M escalation.2. Escalation RatesWe estimated labor and nonlabor escalation rates for the following functional categories: steam,hydro, other power production, transmission, distribution, customer service and information (CS&I) andadministrative and general (A&G). These escalation rates are summarized into the following two sections.a) LaborLabor price indexes and escalation rates are shown in Table VII-22, below.60

Table VII-22O&M Labor Price Indexes And Escalation RatesLine No. Index Type 2005 2006 2007 2008 2009 2010 2011 2012 2013 20141 Steam Index 0.704 0.752 0.860 0.963 1.000 1.033 1.061 1.086 1.117 1.1492 % change 4.05% 6.69% 14.41% 12.01% 3.83% 3.30% 2.76% 2.27% 2.86% 2.90%3 Nuclear Index 0.848 0.881 0.927 0.954 1.000 1.033 1.061 1.086 1.117 1.1494 % change 2.20% 3.93% 5.19% 2.93% 4.80% 3.30% 2.76% 2.27% 2.86% 2.90%5 Hydro Index 0.884 0.925 0.924 0.963 1.000 1.033 1.061 1.086 1.117 1.1496 % change 4.01% 4.62% -0.11% 4.25% 3.83% 3.30% 2.76% 2.27% 2.86% 2.90%7 Other Power Production. Index 0.722 0.850 0.897 0.963 1.000 1.033 1.061 1.086 1.117 1.1498 % change 3.47% 17.77% 5.50% 7.40% 3.83% 3.30% 2.76% 2.27% 2.86% 2.90%9 Trasmission Index 0.869 0.894 0.923 0.973 1.000 1.033 1.061 1.086 1.117 1.14910 % change 2.57% 2.84% 3.30% 5.40% 2.78% 3.30% 2.76% 2.27% 2.86% 2.90%11 Distribution Index 0.867 0.899 0.927 0.973 1.000 1.033 1.061 1.086 1.117 1.14912 % change 3.24% 3.65% 3.16% 4.94% 2.78% 3.30% 2.76% 2.27% 2.86% 2.90%13 Customer Acct Index 0.893 0.899 0.926 0.944 1.000 1.033 1.061 1.086 1.117 1.14914 % change 3.07% 0.66% 3.08% 1.86% 5.98% 3.30% 2.76% 2.27% 2.86% 2.90%15 CS&I Index 0.890 0.912 0.917 0.944 1.000 1.033 1.061 1.086 1.117 1.14916 % change 4.04% 2.40% 0.59% 2.90% 5.98% 3.30% 2.76% 2.27% 2.86% 2.90%17 A&G Index 0.899 0.918 0.945 0.984 1.000 1.033 1.061 1.086 1.117 1.14918 % change 3.59% 2.14% 2.90% 4.16% 1.64% 3.30% 2.76% 2.27% 2.86% 2.90%61

12b) NonlaborNonlabor price indexes and escalation rates are shown in Table VII-23, below.Table VII-23O&M Nonlabor Price Indexes And Escalation RatesLine No. Index 2005 2006 2007 2008 2009 2010 2011 2012 2013 20141 Steam Index 0.830 0.878 0.916 0.997 1.000 1.013 1.036 1.065 1.092 1.1222 % change 6.31% 5.80% 4.32% 8.79% 0.31% 1.32% 2.24% 2.77% 2.62% 2.72%3 Nuclear Index 0.881 0.921 0.969 1.017 1.000 1.013 1.038 1.069 1.098 1.1264 % change 4.74% 4.50% 5.22% 4.94% -1.63% 1.32% 2.40% 3.04% 2.72% 2.57%5 Hydro Index 0.842 0.897 0.924 1.000 1.000 1.015 1.043 1.073 1.100 1.1286 % change 6.89% 6.47% 3.03% 8.28% -0.05% 1.51% 2.72% 2.93% 2.53% 2.48%7 Other Power Production. Index 0.854 0.893 0.925 0.990 1.000 1.015 1.040 1.071 1.100 1.1338 % change 6.30% 4.59% 3.57% 7.05% 0.98% 1.47% 2.51% 2.99% 2.69% 3.00%9 Trasmission Index 0.867 0.904 0.935 0.997 1.000 1.012 1.037 1.064 1.088 1.11510 % change 5.27% 4.24% 3.53% 6.53% 0.35% 1.22% 2.43% 2.57% 2.29% 2.50%11 Distribution Index 0.848 0.899 0.935 1.002 1.000 1.013 1.036 1.061 1.085 1.10812 % change 5.41% 6.03% 4.08% 7.11% -0.18% 1.32% 2.29% 2.37% 2.23% 2.13%13 Customer Acct Index 0.904 0.927 0.954 0.989 1.000 1.021 1.043 1.066 1.089 1.11014 % change 3.04% 2.52% 3.00% 3.58% 1.15% 2.06% 2.19% 2.19% 2.13% 2.01%15 CS&I Index 0.888 0.914 0.943 0.989 1.000 1.013 1.035 1.060 1.081 1.10216 % change 4.24% 2.93% 3.17% 4.88% 1.10% 1.28% 2.16% 2.43% 2.02% 1.90%17 A&G@H Index 0.881 0.916 0.951 0.987 1.000 1.022 1.049 1.079 1.111 1.14618 % change 4.23% 3.96% 3.85% 3.77% 1.31% 2.22% 2.60% 2.85% 2.99% 3.11%62

12345678910111213141516171819202122232425262728293031323. Methodology and EstimatesWe developed the price indexes and escalation rates in Table VII-1 and Table VII-2 usingthree sources of information:a) Recorded SCE payroll data, including hours worked and wages paid.b) SCE Straight time wage increases as specified in its principal union contracts and its targetwage increases for nonrepresented employees.c) Global insight historical data and forecasts of wages and process for the U.S. economy.The following sections explain how this information was used to develop labor andnonlabor escalation rates for the historical period (2005through 2009) and the forecast period (2010through2014).a) Labor Escalation(1) Historical period -2005 Through 2009We have recorded payroll data for labor expenses that are directly assignedto FERC accounts. These data include wages paid for straight time labor, overtime labor, and double timelabor and corresponding hours by these categories. To estimate the average hourly earnings by functionalcategory (nuclear, transmission, distribution and so forth), effective hours are calculated as the sum of: (i)straight time hours, (ii) overtime hours multiplies by one and one-half, and, double time hours multipliesby two. Wages are summarized across three categories and are then divided by effective hours worked tocalculate average hourly earnings. This method removes the effect of year to year variations in overtimeand double time hours worked.(2) Forecast Period 2010 - 2014For 2010, our represented employees received a wage increase of fourpercent as part of a collective bargaining agreement with our unions. For 2010, or nonrepresentedemployees received an average wage increase of three percent; however such wage increases can vary byjob classification and individual employee. Our forecast labor escalation for 2007 is a weighted average ofthese wage increases. The weighting was based upon the shares of represented and nonrepresentedemployees in wages and salaries paid (for 2003 – 2006). These shares are 29.599 percent and 70.401percent respectively, resulting in an overall labor escalation rate of 3.3 percent for 2010.For 2011, our represented employees are scheduled to receive a wageincrease of four percent, as part of a collective bargaining agreement, however, wage increases fornonrepresented employees has not been determined yet. For 2012 and later, wage increases have not beendetermined for any employees, represented or nonrepresented. To estimate labor escalation for these63

12345678years, we constructed a weighted average of forecast labor escalation rates provided by Global Insight’sUtility Cost Information Service (UCIS). UCIS provides projections of wage increases for electric powergeneration workers (nuclear, hydro, other, and steam), transmission and distribution workers, managersand administrators, and professional and technical workers. The UCIS projections are national projectionsand are not specific to the Western US or Southern California. Table VII-24 below shows the categoriesof our workers and the shares of total wages and salaries that they earn. These are used as the weights toconstruct the weighted average of escalation rates for 2012 through 2014. The resulting labor escalationrates are: 2012 - 2.27 percent, 2013 - 2.86 percent and 2014 - 2.90 percent.Table VII-24Correspondence Between Employee Categories And UCIS VariablesLine No. Employee Category Share of Total Wages andSalaries Paid for 2003through 2006Global Insight UCISLabor Escalation IndexGlobal Insight UCIS LaborEscalation Variable Name1 Clerical/Physical 46.52% Electric power generation,transmission, anddistribution workers2 Executive/Manager/Supervisor25.62% Managers andadministrators3 Professional/Technical 27.87% Professional and technicalworkersCEU4422110008ECIWSPWMGRNSECIWSPWP&TNS910111213141516171819202122b) Nonlabor Escalation(1) Global Insight IndexesFor historical and forecast nonlabor escalation, SCE is using indexesprovided by Global Insight’s Utility Cost Information Service (UCIS). UCIS provides indexes of O&Mcombined materials and services costs by functional categories of steam, nuclear, hydro, other powerproduction, transmission, distribution, customer accounts, customer service information, andadministrative and general. Rebased to equal one in 2009, these are the basis for the nonlabor escalationrates shown in Table VII-23 above.(2) Adjustment of Nonlabor Escalation Rates To Reflect Labor Costs Bookedin Nonlabor ExpenseSCE’s accounting system books certain labor costs in nonlabor expense asreported in the FERC Form 1 and in the historical nonlabor O&M data used to develop the estimates oftest year nonlabor expense contained in this application. In order to accurately calculate the actualnonlabor escalation rate, we escalate the nonlabor portion and separately escalation the labor portion64

12345embedded in nonlabor. To accomplish this, we first identify the amount of labor included in the nonlaborexpense by functional category. In 2008, SCE implemented a new accounting system that tracks expensesdifferently than the previous accounting system. Therefore, we calculated labor embedded in nonlabor for2005 through 2008 and then for 2009 separately (applicable to 2009 through 2014). These percentagesare illustrated in Table VII-25 below.Table VII-25Percentage of Nonlabor ExpenseThat is Actually Labor ExpensePercentage of Non Labor ExpenseLine No. O&M Category That is Actually Labor Expense2003-2008 2009-20141 Steam Generation 4.55% 0.00%2 Nuclear Generation 9.72% 0.00%3 Hydro Generation 16.51% 0.00%4 Other Power Production 2.64% 5.61%5 Transmission 11.06% 2.45%6 Distribution 18.36% 0.00%7 Customer Accounts 16.64% 0.00%8 CS&I 1.77% 0.00%9 A&G 0.00% 0.00%678910111213141516The nonlabor escalation rates reported in Table VII-2 represent a weightedaverage of the Global Insight published nonlabor escalation rates and the SCE labor escalation ratereported in Table VII-1. The labor escalation weights are illustrated in Table VII-4, and the non laborweights are equal to one minus the labor escalation weights.(3) Nonlabor Escalation For Palo VerdeSCE does not operate Palo Verde Nuclear Generation Station (PVNGS).Arizona Public Service (APS) operates PVNGS and bills SCE for its share of operating costs, whichinclude both labor and nonlabor. SCE’s payments to APS are booked as a nonlabor expense. To properlyescalate these costs, SCE performs a similar calculation to our nonlabor escalation by weighting andescalating the labor and nonlabor costs to arrive at a Palo Verde nonlabor escalation rate. The PVNGSescalation rate is illustrated in Table VII-26 below.65

Table VII-26Palo Verde Nonlabor EscalationLine No Year Index % Change1 2005 0.86 3.47%2 2006 0.90 4.22%3 2007 0.95 5.20%4 2008 0.99 3.95%5 2009 1.00 1.50%6 2010 1.02 1.97%7 2011 1.05 2.60%8 2012 1.07 2.61%9 2013 1.10 2.80%10 2014 1.13 2.75%1234567(4) Nonlabor Escalation For Four CornersSCE does not operate the Four Corners Nuclear Generation Station. ArizonaPublic Service (APS) operates the Four Corners Nuclear Generation Station and bills SCE for its share ofoperating costs, which include both labor and nonlabor. SCE’s payments to APS are booked as a nonlaborexpense. To properly escalate these costs, SCE performs a similar calculation to our nonlabor escalationby weighting and escalating the labor and nonlabor costs to arrive at a Four Corners nonlabor escalationrate. The Four Corners Nuclear Generation Station escalation rate is illustrated in Table VII-27 below.Table VII-27Four Corners Nonlabor EscalationLine No Year Index % Change1 2005 0.78 5.45%2 2006 0.83 6.13%3 2007 0.89 8.12%4 2008 0.98 10.07%5 2009 1.00 1.74%6 2010 1.02 1.84%7 2011 1.04 2.47%8 2012 1.07 2.54%9 2013 1.10 2.73%10 2014 1.13 2.80%891011(5) Health Care EscalationIn Exhibit SCE-06 Volume 02 Chapter VII, SCE presents estimates of testyear health care costs that do not incorporate the nonlabor escalation rates discussed here. Due to the factthat SCE treats health care cost trends separately, the effect of health care changes is removed from the66

1234567891011121314151617A&G nonlabor escalation rates shown in this chapter. This was done by requesting adjusted A&Gnonlabor escalation rates from Global Insight UCIS that specifically exclude the effect of health care costescalation. Therefore, there is no double counting of escalation between the health care escalation ratesshown in Exhibit SCE-06 Volume 02 Chapter VII and the escalation rates illustrated within this chapter.B. Capital Cost Escalation1. PurposeThe purpose of this section is to provide the forecast capital escalation rates embeddedwithin the departments’ capital expenditure forecasts. Capital escalation rates were developed on adepartment by department basis by weighting and escalating the labor and nonlabor costs. Laborescalation is utilized by departments where labor is historically embedded within capital expenditures.Each department forecasts their capital escalation to reflect the embedded labor. Subsection 2 summarizesthe escalation rates and embedded labor in capital escalation rates that were developed for use in this case.2. Escalation RatesWe estimated capital escalation rates for the following functional categories: transmission,distribution, nuclear – SONGS, nuclear - Palo Verde, CSBU – meters, CSBU distribution, generation –hydro, generation - coal - Four Corners , generation - gas – peakers, generation - gas – Mountainview, anddecommissioning projects. These escalation rates are illustrated in Table VII-28 below.67

1a) CapitalTable VII-28Capital Escalation Rates2009 2010 2011 2012 2013 2014Transmission 100 101.79 103.64 106.28 109.54 113.331.79% 1.83% 2.55% 3.07% 3.45%Distribution 100 101.84 103.67 106.15 109.22 112.601.84% 1.79% 2.40% 2.90% 3.09%Nuclear - SONGS 100 102.24 104.64 107.03 110.03 113.522.24% 2.35% 2.29% 2.80% 3.17%Nuclear - Palo Verde 100 102.11 104.49 106.88 109.90 113.512.11% 2.33% 2.28% 2.82% 3.28%CSBU - Meters 100 101.30 103.61 105.17 106.47 107.921.30% 2.28% 1.51% 1.24% 1.36%CSBU Distribution 100 100.16 101.71 103.86 106.60 109.500.16% 1.55% 2.12% 2.64% 2.72%Generation - Hydro 100 101.50 103.02 104.57 106.14 107.731.50% 1.50% 1.50% 1.50% 1.50%Generation - Coal - Four Corners 100 103.00 106.09 109.27 112.55 115.933.00% 3.00% 3.00% 3.00% 3.00%Generation - Gas - Peakers 100 103.00 106.09 109.27 112.55 115.933.00% 3.00% 3.00% 3.00% 3.00%Generation - Gas - Mountainview 100 102.00 104.04 106.12 108.24 110.412.00% 2.00% 2.00% 2.00% 2.00%Decommissioning Projects: (MohaveSolar 2, San Bernardino (ieMountianview) Units 1&2 100 101.50 103.02 104.57 106.14 107.731.50% 1.50% 1.50% 1.50% 1.50%234567(1) Adjustment of Escalation Rates to Reflect Labor Included in CapitalExpendituresSCE’s capital expenditures include embedded labor costs. In order toaccurately calculate the actual capital escalation rate, each department separately estimates the laborpercentage of capital costs. We then apply SCE’s labor escalation rate to that portion of capital costsThese percentages are illustrated in Table VII-29.68

Table VII-29Percentage of Capital ExpenditureThat is Actually Labor ExpensePercentage of Labor Embedded in Capital ExpendituresTransmission 55.58%Distribution 62.90%Nuclear - SONGS 44.00%Nuclear - Palo Verde 44.00%CSBU - Meters 0.00%CSBU Distribution 0.00%Generation - Hydro 5.00%Generation - Coal - Four Corners 0.00%Generation - Gas - Peakers 0.00%Generation - Gas - Mountainview 0.00%Decommissioning Projects: (Mohave Solar2, San Bernardino (ie Mountianview) Units1&2 5.00%69

1234567891011121314VIII.OTHER OPERATING REVENUEThis chapter presents SCE’s total system Other Operating Revenue (OOR) for recorded year 2009and forecast years 2010 through 2014. OOR are revenues received by SCE from transactions not directlyassociated with the sale of electric energy and are recorded in FERC Accounts 450 through 456 aspresented below. OOR is subtracted from total operating costs to determine the test year revenuerequirement because it reduces the revenue that needs to be collected through customer rate levels. Part Bof this section discusses SCE’s Added Facilities rates used for the 2012 Test Year. As discussed inExhibit SCE-4, Volume 4, Chapter IV, the 2012 OOR forecast assumes Edison SmartConnect has beenfully deployed and there is a reduction in the amount of OOR associated with certain fees as a result of thefunctionality of the new meters.A. Account-By-Account Summary Of OOROOR recorded amounts for 2009 and forecast amounts for 2010 through 2014 are summarized inTable VIII-30 below. 4242 OOR summarized by specific FERC subaccount is presented in detail within the workpapers that support this section.70

Table VIII-30Other Operating RevenueNominal ($000)Line FERC Recorded ForecastExhibitNo. Account Description 2009 2010 2011 2012 2013 2014 Reference1. 450.000 - Forfeited Discounts2. Customer Service Operations OOR 16,627 17,318 19,320 21,620 21,620 21,620 SCE-4, Vol. 4, Chapter IV3. 451.000 -Miscellaneouse Service Revenues4. Customer Service Operations OOR 34,792 33,287 33,480 15,167 15,167 15,167 SCE-4, Vol. 4, Chapter IV5. Transmission & Distribution Business Unit OOR 808 1,101 1,128 1,184 1,184 1,184 SCE-3, Vol. 5, Chapter IIITotal 451.00035,600 34,388 34,608 16,351 16,351 16,3516. 453.000 - Sales of Water & Water Power7. Financial and Other Miscellaneous Revenues 853 389 389 389 389 389 SCE-10, Vol. 1, Chapter VIII8. 454.000 - Rent from Electric Property9. Customer Service Operations OOR 3,931 3,758 4,036 4,392 4,392 4,392 SCE-4, Vol. 4, Chapter IV10. Transmission & Distribution Business Unit OOR 36,057 36,954 37,360 38,823 38,823 38,823 SCE-3, Vol. 5, Chapter III11. Financial and Other Miscellaneous Revenues 15,114 14,903 14,845 14,727 14,727 14,727 SCE-10, Vol. 1, Chapter VIIITotal 454.00055,102 55,615 56,241 57,942 57,942 57,94212. 456.000 - Other Electric Revenue13. Customer Service Operations OOR 398 257 257 130 130 130 SCE-4, Vol. 4, Chapter IV14. CS&I Tariffed Products and Services OOR 1,568 1,431 1,220 868 868 868 SCE-4, Vol. 4, Chapter IV15. Transmission & Distribution Business Unit OOR 35,989 45,287 46,989 51,317 51,317 51,317 SCE-3, Vol. 5, Chapter III16. Financial and Other Miscellaneous Revenues 21,513 20,219 21,140 21,089 21,778 22,569SCE-10, Vol. 1, Chapter VIII,SCE-10, Vol. 2, Chapter IIITotal 456.00059,468 67,194 69,606 73,404 74,093 74,88417. Gains/Losses on Sale of Property 1,706 713 713 713 713 713 SCE-10, Vol. 2, Chapter I18. Gross Revenue Sharing Mechanism Authorized Threshold 16,672 16,672 16,672 16,672 16,672 16,672 SCE-10, Vol. 1, Chapter VIII19. Escalation 9,521 12,38620. TOTAL OOR 186,028 192,289 197,549 187,091 197,301 200,95712345678910111. Revenue Account 450 – Forfeited DiscountsThis account includes fees imposed on customers because of failure to pay bills. Such feesinclude forfeited discounts and late payment charges. Forecasts of revenues and descriptions for eachsubaccount within this FERC account, along with support for the estimating method used, are containedin Exhibit SCE-04, Volume 4, Chapter IV. The 2012 test year estimate for FERC Account 450 is $21.6million.2. Revenue Account 451 – Miscellaneous Service RevenuesThis account includes revenues for all miscellaneous services and charges billed tocustomers that are not specifically provided for in other accounts. Such fees include returned checkcharges and service establishment charges. Forecasts of revenues and descriptions for each subaccountwithin the FERC account, along with support for the estimating method used, are contained in Exhibit71

1234567891011121314151617181920212223242526SCE-03 Volume 5, Chapter III, and Exhibit SCE-04, Volume 4, Chapter IV. The 2012 test year estimatefor FERC Account 451 is $16.4 million.3. Revenue Account 453 – Sales of Water and PowerThis account includes revenues expected to be received from Big Creek Project headwaterbenefits. The estimated revenue is based on settlement agreements made between SCE and Pacific Gas &Electric Company (PG&E), Based on the agreements, PG&E pays SCE for the headwater benefitsreceived mainly by a generating station owned by PG&E’s in the San Joaquin basin. The payment to SCErepresents PG&E’s share of the costs incurred by SCE to operate and maintain dams and diversionsupstream. The 2012 test year estimate for FERC Account 453 is $0.389 million.4. Revenue Account 454 – Rent From Electric PropertyThis account includes rents received for the use by others of land, buildings and otherproperty devoted to electric operations. The majority of the revenues recorded in FERC Account 454 aregenerated from company financed added and interconnection facilities (subaccounts 454.300 and454.350). Chapter III of Exhibit SCE-03, Volume 5, supports the forecast of the Company-financed addedfacilities revenues. Part B of this Chapter supports the development of added facilities rates for the 2012Test Year. The total test year estimate for FERC Account 454 is $57.9 million.5. Revenue Account 456 – Other Electric RevenuesThis account includes various items not included in other accounts such as the tax gross-upon Contributions in Aid of Construction, Added Facilities fees, and transmission service revenues. Thetotal 2012 Test Year estimate for FERC Account 456, including various miscellaneous subaccounts assupported in workpapers, is $73.4 million.6. Other OORa) Non-Tariffed Products And ServicesIn D.99-09-070, the Commission adopted a Gross Revenue Sharing Mechanism(GRSM) for OOR that is generated from Non-Tariffed Products and Services (NTP&S). 43 Revenuesharing between SCE’s shareholders and customers occurs when the recorded OOR from the non-tariffed43 The revenue sharing mechanism applies to all of SCE’s OOR, except revenue that is: 1) derived from tariffs, fees, orcharges established by the Commission or FERC; 2) subject to other established ratemaking procedures or mechanisms.72

1234567891011121314151617181920212223242526products and services reaches a certain threshold. The currently authorized OOR threshold is $16.671million. 44 Therefore, the $16.671 million threshold is included in the OOR 2012 test year estimate.The Commission in D.09-03-025 decided that any change to the NTP&S and therelated revenue sharing provisions would be subject to a separate rulemaking proceeding. As of the dateof this filing, a rulemaking proceeding has not been established and SCE is not proposing any changes tothe NTP&S and related revenue sharing provisions herein.b) Revenues With Specific TreatmentIn various decisions and resolution, the Commission has established specificratemaking treatment for revenues generated from a variety of programs. Since these revenues arereturned to customers directly through the operation of memorandum or balancing accounts established totrack the programs, they are not included in the GRC. Specific ratemaking treatment includes, but is notlimited to, programs such as Research, Development and Demonstration Royalties (RDDR), and revenuesrelated to the labor markup billed to non-utility affiliates and returned to customers through a creditrecorded in the BRRBA.c) Gain Or Loss On Sale Of PropertyIn past GRCs, the Commission ordered SCE to include in OOR the gain or loss onsale of property originating in utility plant FERC Accounts 101 and 103, and transferred to FERCAccount 121 (Non-Utility Property) prior to sale. This revenue is to be shared between shareholders andcustomers based upon the amount of time the property was included in rate base. The 2012 estimate ofrevenues attributable to the gain or loss on sale of property is $0.713 million and is supported anddeveloped in Volume 2 of this exhibit. 45B. Added Facilities RatesOur revenue requirement recovers the costs of owning, operating, and maintaining standardfacilities. Customers may request facilities which are in addition to, or in substitution for, the standardfacilities that we would normally install. We may not choose to accommodate these requests by buildingsuch additional facilities, which are called Added Facilities. We charge customers for the cost of these44 The current threshold, as adopted in D.99-09-070, is based upon the level of OOR from non-tariffed products and servicesreflected as a revenue credit in SCE’s 1995 Test year GRC (D.96-01-011).45 The gains and losses on minor sales of property are allocated between customers and shareholders pursuant to D.06-05-041 as modified by D.06-12-043.73

12additional facilities through Added Facilities rates. Table VIII-31 below summarizes our proposed AddedFacilities rates.Table VIII-31Added Facilities Rate Components34567891011121314Added Facilities are provided pursuant to a number of tariff provisions, depending on the nature ofthe facilities. Under Rule 2, Section H, we provide additional transmission and distribution facilities. Wemay either finance Added Facilities (Company-financed option) or require the customer to finance theAdded Facilities (Customer-financed option). We provide Added Facilities with and without replacementoptions. The cost of these facilities is recovered through a monthly charge equal to the installed cost of thefacilities times the monthly Added Facilities rate applicable to the type of financing. When collectingmonthly charges is impractical, we convert the monthly charge to a one-time payment. Under Rule 21, wemay either finance generation interconnection facilities (Company-financed option) or require thecustomer to advance the cost of interconnection facilities (Customer-financed option). Under Rule 2,Section J, we may finance the monthly capital-related charge of Interval Metering and/or MeteringFacilities that are not part of other transmission and distribution facilities installed as Added Facilitiesunder Rule 2, Section H.74

1234567891011121314151617181920212223242526272829The Added Facilities rates reflect our costs of owning, operating, and maintaining the AddedFacilities. For calculation purposes, costs have been divided into two cost components: (1) capital related(or costs of ownership); and, (2) O&M related. The capital-related cost component is derived from thecarrying charge rates associated with each FERC account. The development of carrying charge rates isbased on current assumptions of rate of return (8.75 percent), 2009 authorized depreciation rates,Administrative and General (A&G) expenses (1.80 percent), Ad Valorem tax (1.22 percent of AssessedValue), Insurance (0.39 percent), Federal income tax (35 percent) and State income tax (8.60 percent).The rate of return is equal to the current authorized return on rate base for 2010. The rate component forO&M has been calculated as the ratio of the most recent ten years’ historical O&M expense and plantin-service relevant to the added facilities.Table VIII-31 above shows the rates for various Company- and Customer-financed options. Ourcurrent rates have the following options: (1) Company-financed without replacement, (2)Company-financed with limited replacement for a 20-year term, (3) Company-financed with perpetualreplacement, (4) Customer-financed without replacement, (5) Customer-financed with limitedreplacement for a 20-year term, and (6) Customer-financed with perpetual replacement. Thesereplacement options address utility and customer obligations to pay for new facilities when the originallyinstalled facilities require replacement.If a customer chooses the rate without replacement option, the customer must pay for replacementfacilities when they are needed. If a customer chooses the limited replacement option, we providereplacement with no additional cost to the customer for a period up to 20 years. Finally, if a customerchooses the perpetual replacement option, we provide replacement facilities at no additional cost to thecustomer as long as the customer continues to pay for added facilities. As provided in Rule 2H, when wedetermine the collection of monthly charges to be impractical, the Added Facilities customer is required tomake an equivalent one-time payment in lieu of the monthly charges. The one-time payment equals thenet present value of the future payments the customer would otherwise be obligated to pay multiplied bythe installed cost of the Added Facilities to calculate a one-time equivalent payment.The rate for the monthly capital-related charge of Interval Metering and/or Metering Facilitiesunder Rule 2, Section J, is 1.82 percent per month. The rate is multiplied by the investment amount of theInterval Metering and/or Metering Facilities.75

12345IX.SUMMARY OF OPERATION AND MAINTENANCE EXPENSES BY FERC ACCOUNTThis chapter summarizes O&M expenses that SCE requests for test year 2012 in this application.The development and justification of all O&M expense estimates are contained in exhibits organizedalong our business unit lines as shown in Table IX-32 below:Table IX-32Summary of O&M Expense ExhibitsCategory of ExpenseFERCExhibitWitnessAccountsReferenceGeneration 500 through 557 SCE-02, Volumes 2-10 P. Phelan/T. Ware/ D. Bauder/J. Lefman/ K. Murray/L. Wright/M. Nelson/ A. Kurpakus/A. Laven/I. Cuthbertson/R. Hite/E. Antillon/G. Butts/ R. HardingInformation Technology 517 SCE-05, Volume 2 J. Foulk/M. PinterPower Procurement 557 SCE-08, Volumes 1-4 G. Stern/K. Pickrahn/K. Cini/ M.UlrichTransmission 560 through 573 SCE-03, Volumes 2-5 D. Kim/E. Martinez/K. Varnell/T. Reeves/R. Woods/K. Trainor/W. Spansel/E. Antillon/G. FerreeDistribution 580 through 598 SCE-03, Volumes 2-5 D. Kim/E. Martinez/K. Varnell/T. Reeves/R. Woods/K. Trainor/E. Antillon/G. Ferree/J. Arencibia/P. Grigaux/M. StarkCustomer Service Operations 901 through 905 SCE-04, Volume 2 G. HuckabyCustomer Service & Information 907 through 916 SCE-04, Volume 3 G. HuckabyAdministrative & General:Information Technology 920 through 935 SCE-05, Volume 2 M. Pinter/S. Tessema/S. Huson/J. FoulkHuman Resources Departmentaland Total Compensation920 through 935 SCE-06, Volumes 1-2 G. Clapp/P. Miller/M. Bennett/D.ErtelFinancial Organization, Capitalized 920 through 935 SCE-07, Volume 1 L. Letizia/R. Loughlin/W. PetmeckyA&G, Capitalized P&B,Participants Credits, Risk ControlLaw, Claims, Worker’s920 through 935 SCE-07, Volume 2 E. Jennerson/S. Mines/R. RamosCompensation, Ethics &ComplianceRegulatory Policy and Affairs, 920 through 935 SCE-07, Volume 3 S. Kempsey/V. Gutierrez/A. JazayeriCorporate Membership and Dues,Property Liability Insurance, andCorporate CommunicationsOperations Support 920 through 935 SCE-09, Volume 2 J. Monroe/J. Alderete/R Greenwood/T. Hampton/A. Riddle/D. WilsonPublic Affairs and FranchiseRequirements920 through 935 SCE-04, Volume 3 L. Starck76

123456A. Operation And Maintenance Expense Forecast Development And Summary By FERCAccountIn preparing our Operation and Maintenance (O&M) expense estimates for this GRC filing, weused the following step-by-step process to develop and support our test year O&M expenses. The purposeof this methodology, as shown in Figure IX-8 below, was to achieve a consistent analytical approach bythe organizations that prepared our O&M expense estimates.Figure IX-8Expense Forecast DevelopmentExpense Forecast DevelopmentGeneral Ledger –(CARS/SAP)FERC Form 12005 - 2009Adjust for nonrecurringexpenses &convert to 2009 $Analyze forecastingoptions & businessneeds•Last RecordedYear•Average•Trend•Budget-Based2012Forecast2009 GRC78910111213Our O&M expense forecast development process complies with the Commission’s Rate Case Plandecision, D.89-01-040, in that it: (1) includes five years of recorded data for each FERC account, by laborand non-labor, and other, used in the development of the test year revenue requirement, including thelatest recorded year available at the time of tendering the NOI, (2) provides base year (2009) historicaland estimated data for subsequent years with evaluation of changes up to and including the test year, (3)states all expenses in recorded base year (2009) and nominal dollars, and (4) ensures that all forecastamounts have a clear tieback to base data. 4646 See D.89-01-040, Standard Requirement List of Documentation Supporting An NOI, specifically item numbers 6 and 7.77

123456789101112131415161718192021222324252627In summary, our O&M expense forecast development process consisted of the following steps:• Five years of recorded O&M data (2005-2009) was extracted from SCE’s accounting systemsthat were used during the five year period (i.e. the legacy Corporate Accounting and ReportingSystem (CARS) for the period January 1, 2005 through June 30, 2008, and SAP for the periodJuly 1, 2008 through December 31, 2009).• The five years of recorded O&M data is then organized into activity groups along businessunit lines by FERC account for analysis and forecasting. This effort not only supported thelevel of expenses for 2012, but required each business unit to review its recorded expenses andactivities. The FERC Form 1 O&M amounts are the basis, or starting point, for the recordedGRC O&M data.• Recorded expenses were adjusted for unique, abnormal, or one-time non-recurring expenses,as well as, to remove expenses recovered through other ratemaking mechanisms. Afteradjustments were made, the recorded-adjusted expenses were converted to constant 2009dollars.• The development of the 2010 through 2012 forecast O&M expenses included a review ofvarious methodologies, including (1) use of last recorded year; (2) averaging of recorded data;(3) trending of recorded data; and (4) development of a “budget-based” approach.• A test year 2012 forecast for each O&M activity was selected. Each business unit supports andjustifies the method chosen and discusses the reasons other methodologies were not used todetermine the 2012 forecast for each O&M activity.A detailed discussion of each step in the O&M expense forecast development follows.B. General Ledger/CARS/SAPThe starting point for developing our 2012 Test Year O&M expense estimates was to collect andanalyze recorded data for the five-year historical period 2005-2009. 47 The originating source for therecorded O&M expense data from January 1, 2005 through June 30, 2008 is SCE’s legacy general ledgersystem – the Corporate Accounting and Reporting System (CARS). The originating source for therecorded O&M expense data from July 1, 2008 through December 31, 2009 is SAP. 4847 Since SCE is filing its 2012 GRC application in 2010, 2005 through 2009 recorded data will be the five year recordedperiod used, with 2009 designated as the “base year”, and 2005 through 2008 referred to as the “historical period”.48 SCE implemented SAP accounting system on July 1, 2008. The SAP system was installed with the goal of replacingseparate systems with a single solution that integrates the basic enterprise business processes, e.g. accounting, payroll,procurement, material management, and work management in a single, integrated application that uses a centralized(Continued)78

123456789101112Prior to July 1, 2008, all of SCE’s financial transactions were recorded in CARS, and SCE usedthis general ledger accounting system to develop its financial reports. The GRC workpapers include asubset of the CARS Trial Balance Accounts (i.e. FERC Accounts), namely, O&M, A&G, and OOR. Atthe highest level, recorded O&M costs in CARS were summarized by Trial Balance Accounts (TBAs,a.k.a. FERC Accounts).Upon implementation of the new system on July 1, 2008, all of SCE’s financial transactions arerecorded in SAP. The basic chart of accounts in SAP is a “Natural” Chart of Accounts with classificationbased on “nature of activity” as opposed to function of activity. For example, “Salary” is used instead ofgeneration-related labor being classified as “Generation”. Balance sheet and revenue items are recordedusing natural general ledger accounts. Expenses are all recorded in cost objects and the nature of each costis designed by a data element called a “cost element” which corresponds to a natural G/L account asshown in Table IX-33 below.Table IX-33Examples of Cost Elements/Corresponding G/L Accounts131415161718The SAP FERC module is employed to translate the activities recorded during the month in SAPNatural Chart of Accounts to FERC Accounts. The FERC requires all electric utilities to file acomprehensive financial and operating report, known as the FERC Form 1, on an annual basis. Thereporting of recorded costs in the FERC Form 1 follows FERC’s established Uniform System of Accounts(USOA). Recorded O&M expenses are reported by FERC account and derived from SCE’s GeneralLedger (i.e., CARS through June 30, 2008 and then SAP beginning on July 1, 2008). The total recordedContinued from the previous pagedatabase. SAP is the world’s third-largest software company with over 91,000 installations worldwide, representing morethan 40 percent of market share. SAP also leads utility-industry ERP installations and has served the utility industry forover 20 years with 950 utility customers, including PG&E and SEMPRA.79

12amounts in each O&M FERC account for the years 2005 through 2009 as shown in this GRC filing areidentical to the amounts included in SCE’s FERC Form 1 filings for those years.Figure IX-9O&M: Natural vs. FERCNatural Chartof Accounts601 Labor611 Materials615 Supplies616 ContractorsTotal O&M ExpenseFERC UniformSystem of Accounts500 Power Production560 Transmission580 Distribution920 A & GTotal O&M Expense345678910111213141516The FERC Module uses maps maintained by SCE’s Controller’s Department to perform thistranslation. For balance sheet accounts and revenue accounts, the FERC Module uses a simple, directmapping method to assign amounts from the natural G/L accounts to FERC accounts. For expenses, theFERC Module employs a separate map to assign costs to FERC accounts. The cost object used at SCE tocapture O&M costs is a Final Cost Center (FCC). 49 Each FCC has an assigned FERC indicator. Costs thatrecord in a FCC are recorded to the appropriate FERC account based on the nature of the cost (i.e. costelement) and the assigned FERC indicator on the FCC.Recorded O&M costs generally fall into one of two categories: labor or non-labor. In addition, forGRC purposes, portions of our non-labor costs, such as rents, are reclassified as “other” expenses,because they are not subject to traditional non-labor escalation or require special trending rates such ashealth care expenses.In order to present all O&M expense data for the five-year period in a consistent manner, alltransactions recorded in CARS are stated in SAP terms. This was accomplished using conversion maps.The conversion map used to populate SAP with the actual January 1, 2005 through June 30, 2008 CARS49 Descriptions of FCCs are included in SCE’s standardized O&M workpapers.80

1234567891011121314151617181920212223242526272829activity was used as a starting point, then the business units were given templates with the proposedconversion map to review and provide any revisions to the mapping. In all cases, transactions wereconverted to the same FERC account in SAP as had been originally recorded in CARS and, as so, theconverted amounts tie to the FERC Form 1.C. GRC O&M Data ManagementOur Regulatory Policy and Affairs (RP&A) Department manages the GRC O&M forecastingprocess on a total Company basis through the use of an O&M workpaper data base. RP&A provides eachO&M witness a standardized package of workpapers (which can be supplemented with departmentalworkpapers) in order to: (1) ensure all base O&M costs are being forecast in the GRC, (2) prevent doublerecovery of costs, and (3) provide a consistent and simplified GRC showing. Recorded 2005 through 2009O&M expenses were extracted from CARS (i.e., January 1, 2005 through June 30, 2008) and SAP (July1, 2008 through December 31, 2009) and loaded into the RP&A O&M workpaper application to begin theGRC forecasting process. The data that was extracted from CARS was “mapped” to SAP accounting sothat all of the data for the five year period is consistent (i.e., by Final Cost Center designation).The Commission reviews and authorizes O&M expenses in GRCs by FERC account; therefore, atthe highest level, SCE requests test year O&M funding by FERC account. FERC has establishedfundamental descriptions of appropriate costs to be recorded to each FERC account.. The FERC USOA isvery specific in some instances, such as Account 585, “Street Lighting and Signal System Expense,” andvery broad in some instances, such as Account 593, “Maintenance of Overhead Lines.” Therefore, it isoften necessary to go below the FERC account level in order to develop meaningful O&M forecasts.To help facilitate the O&M estimation process, most FERC Accounts have been disaggregatedinto activity groupings that track closely with specific business unit operations. Separation into FERCactivities allows us to isolate the cause of certain variations in historical data and helps to establish a basisfor the estimating method to be applied. At SCE, departmental O&M budgets are assigned to functional,departmental managers who are responsible for those expenses and evaluated throughout the year, both onfunctional performance and cost control. 50 In SAP, cost centers are used to capture costs for similar typesof work, grouped to facilitate their effective tracking and management. In addition, in conjunction withcost elements, cost centers in SAP are used by the SAP FERC Module to identify and record the costs tothe appropriate FERC Accounts.50 SCE has a rigorous process of approving and managing its O&M (cost center) budget, as discussed in more detail inAppendix E to this exhibit.81

1234567891011121314151617181920212223242526Since we review and control O&M costs internally on a monthly basis at the cost element grouplevel and by FCC, the RP&A O&M workpaper application provides recorded 2005 through 2009expenses, by cost element group (i.e. labor, non-labor, and other) for each FCC. The cost center numbersare grouped in activities within FERC accounts to recognize and more accurately reflect our managementstructure and assignment of responsibilities.D. Adjustments Included In Business Unit Activities1. Company-Wide Adjustments Included In Business Unit ActivitiesCertain types of adjustments were made to recorded labor and non-labor expenses for thebase year 2009 and prior years (2005 through 2008) in the historical period on a Company-wide basis. 51These adjustments were made to generally remove: (1) costs that are recovered through other ratemaking(non-GRC) mechanisms, such as Public Purpose Program costs, (2) costs that are not being requested inthis GRC, such as fuel and purchased power costs, and (3) costs that are the responsibility ofshareholders. In addition, as explained below, expenses incurred for services provided by SCE in supportof Edison International (EIX) and associated non-utility affiliates, were added back to the base year andhistorical period.a) Ratemaking Treatment For Non-Utility-Related ExpensesWith regard to expenses incurred in support of EIX and associated non-utilityaffiliates and its relationship to the ratemaking process, this filing follows current Commission precedentset forth in the Holding Company Decision (D.88-01-063), Affiliate Transaction Rulemaking Decision(D.97-12-088) and all subsequent GRCs. These decisions established guidelines and methodologies wemust follow when incurring expenses in support of non-utility affiliates.In accordance with the decisions, such expenses are incurred by the utility andcharged to EIX and non-utility affiliates. The payments from EIX and non-utility affiliates for theseservices are recorded as a credit to SCE’s O&M expenses. Current Commission-approved ratemakingprovides that we reverse these credits from forecast test year expenses. That is, forecast test year expensesare reflected at the level the utility will incur excluding the credit.52 Then, recorded utility expenses in51 All of the forecast O&M and capital-related costs included in this GRC filing are on a total Company-wide, or systembasis; which includes both base-related CPUC-jurisdictional costs and base-related FERC-jurisdictional transmissionrelatedoperating and capital costs. Based on a methodology as described in Section IV of this exhibit, the total systemO&M and capital-related forecasts are then separated into CPUC and FERC-jurisdictional amounts.52 Throughout this testimony we use the term “gross basis” to indicate the level of costs excluding the credit and the term“net basis” for the level of costs including the credit.82

12345678910111213141516171819202122232425262728293031support of EIX and non-utility affiliates are credited to customers through the Base Revenue RequirementBalancing Account (BRRBA). This procedure ensures that utility customers do not subsidize servicesprovided by SCE to EIX and non-utility affiliates.With the exception of the two specific cases that are discussed below, SCE hasreflected its forecast test year expenses on a “gross” basis. It is necessary to forecast on a gross basisbecause otherwise SCE’s customers would receive the benefit of charges to EIX and non-utility affiliatestwice: once through a reduction in test year expenses, and a second time through credits recorded in theBRRBA.Consistent with the principles of the Holding Company Decision, costs incurred bySCE on behalf of EIX and non-utility affiliates not included in our forecast test year expense estimateswill not be credited to the BRRBA. SCE removed from its forecast test year expenses those non-utilityaffiliate costs that have been identified as incremental expenses and that are associated with personnel oractivities that are 100 percent dedicated to non-utility functions. These costs include: (1) CorporateCommunications outside services costs associated exclusively with EIX and non-utility affiliates; and, (2)EIX and non-utility affiliate’s pensions and benefits costs. These costs are not included in our forecast testyear expense estimates (i.e., they have been reflected on a net basis), and therefore they will not becredited to the BRRBA.2. Business Unit AdjustmentsIn addition to the Company-wide adjustments described above, each business unit adjustedthe appropriate functions for unique, abnormal, or one-time non-recurring expenses. For example, indeveloping the 2012 O&M forecast, the Risk Control department include an adjustment to reduce itshistorical expenses to remove costs related to initial or one-time implementation expenses. By removingthese types of unique, abnormal, or one-time non-recurring expenses, these recorded costs are notincorporated into the various forecasting methodologies, as described below, and therefore, not embeddedin their 2012 Test Year O&M forecast.Justification for all adjustments made to the base year and historical period, both on aCompany-wide and business unit basis can be found in the supporting testimony for that particular O&Mexpense in the corresponding exhibit in this application.After all adjustments are made to the recorded 2005 through 2009 expenses, labor and nonlaborescalation rates for the recorded period are applied to the recorded-adjusted amounts to remove theeffect of inflationary changes in the costs of labor and goods to facilitate year-to-year comparisons. The83

12345678910111213141516171819202122232425262728293031322005 through 2008 recorded amounts are deflated and restated in base year, or 2009$, using escalationrates as developed and supported in Chapter VII of this exhibit.E. Analyze Forecasting Options And Business NeedsAfter we adjust the historical 2005 through 2009 data to reflect a consistent record of on-goingoperations for each functional area, and convert each historical year’s data into constant 2009$, that datais used to make initial estimates of our 2010, 2011 and Test Year 2012 O&M forecasts. RP&A’s O&Mworkpaper application calculates the following forecasting methodologies for recorded-adjusted O&Mcosts at the activity level, as applicable, by labor, non-labor and other:• Last Recorded Year: the 2012 Test Year estimate could be based on the last recorded year(e.g., 2009 base year) of recorded-adjusted O&M expenses.• Averaging: the 2012 test year estimate could be based on two, three, four, or five years (2005-2009) of recorded-adjusted O&M expenses which are arithmetically averaged.• Linear trending: the 2012 test year estimate could be based on three, four, or five years(2005-2009) of recorded-adjusted O&M expenses which are trended using standard regressionanalysis.• Budget Based: the 2012 test year estimate could be based on a detailed analysis of costelements expected to be incurred in the test year. This approach may use 2009 recordedadjusted,an average of recorded years, or a historical trend as a base plus a detailed estimateof additional future costs and/or savings. In addition, a forecast may be built from zero dollarsto estimate test year (i.e., a “bottoms-up” forecast).This standardized approach used to estimate future O&M funding levels for a given activity is astructured and systematic process. Ultimately, the method used is a matter of judgment. Often, year-toyearchanges in recorded data are a complex mix of events that cannot always be fully-explained, or theyare explained as natural or cyclical events, which may recur one or more times over the five-year recordedhistory. This could be due to weather conditions, or may be due to a business or economic cycle that islonger than one year in duration. This kind of variation in recorded data should not be adjusted, butshould be taken into consideration when deciding the estimating method to be used for that particularactivity. In such an instance, a historical average may be more appropriate than a trend. As year-to-year,variations are understood, it is determined whether a historical average or trend is appropriate, or whetherthe 2009 recorded level should be used as the basis from which future estimates are made.Not all activities lend themselves to a mathematical estimating method based on historical data.Wide variations in recorded expense levels would tend to reduce the use of trending or averaging methods84

123456789101112131415as accurate predictors of test year expenses. These types of activities may be better estimated using aspecial study approach, a “bottoms-up” calculation of resources required, or an addition or subtraction ofsome incremental costs to a base level of expense given some expected future change in workload orscope of activity.F. 2012 O&M ForecastEach O&M witness considered the results obtained from each of the forecasting methods anddiscusses in their respective testimony and accompanying workpapers the validity of these methods indetermining their 2012 test year forecast. 53 Based on their analyses of recorded costs, and theirunderstanding of the nature and scope of the activities they anticipate for the test year, SCE’s O&Mwitnesses forecast their estimates of test year 2012 O&M expenses. The selected forecast for each O&Mactivity is then summarized up to the FERC account level and included in the test year revenuerequirement request.G. Summary Of ResultsThe following tables summarize our O&M expense amounts for the recorded year 2009 andestimated years 2010 through 2014, both in constant 2009 dollars and nominal dollars.53 Or CSBU’s 2013 forecast.85

LineNo.DescriptionTable IX-34Southern California Edison CompanyTest Year 2012 General Rate CaseOperations & Maintenance ExpensesCategory: Total O&M Expenses($000)Recorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20141. Production2. Steam 63,194 71,496 59,521 63,329 63,329 63,3293. Nuclear 363,198 359,541 373,717 405,852 405,852 405,8524. Hydro 46,372 50,845 52,294 57,610 57,610 57,6105. Other 112,448 109,625 117,600 143,089 143,089 143,0896. Subtotal - Production 585,212 591,507 603,132 669,880 669,880 669,8807. Transmission 162,289 170,167 190,320 191,590 191,590 191,5908. Distribution 453,033 487,092 480,789 511,292 500,060 500,0609. Customer Accounts 193,442 197,494 202,283 213,822 193,452 193,45210. Uncollectibles (Account 904) 11,258 13,235 14,493 15,904 17,823 19,58111. Customer Service and Informational and Sales 42,165 44,120 46,715 50,069 53,356 53,35612. Administrative and General 791,265 878,959 937,589 1,026,058 1,030,085 1,041,78113. Franchise Reqiurements (Account 927) 40,327 49,940 54,686 62,937 70,528 77,48814. TOTAL O&M EXPENSE 2,278,991 2,432,515 2,530,008 2,741,553 2,726,774 2,747,18815. Escalation 0 56,095 117,621 187,379 265,336 340,68916. TOTAL INCLUDING ESCALATION 2,278,991 2,488,609 2,647,629 2,928,931 2,992,110 3,087,87717. Less: Franchise Fees and Uncollectibles (FF&U) (51,585) (63,176) (69,179) (78,841) (88,351) (97,069)18. TOTAL O&M EXPENSE EXLUDING FF&U 2,227,406 2,425,434 2,578,450 2,850,090 2,903,759 2,990,80819. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL20. Total Constant 2009$21. Labor 1,097,968 1,167,996 1,219,573 1,292,943 1,260,667 1,260,66722. Non-Labor 905,177 988,520 998,113 1,094,343 1,098,304 1,098,30423. Other 275,847 275,998 312,321 354,267 367,803 388,21824. Subtotal 2,278,991 2,432,515 2,530,008 2,741,553 2,726,774 2,747,18825. Escalation:26. Labor 0 38,497 74,965 110,568 146,909 187,72827. Non-Labor 0 17,597 42,656 76,810 106,769 137,64028. Other 0 0 0 0 11,659 15,32029. Subtotal 0 56,095 117,621 187,379 265,336 340,68930. TOTAL INCLUDING ESCALATION 2,278,991 2,488,609 2,647,629 2,928,931 2,992,110 3,087,87731. Less : Franchise Fees and Uncollectibles (FF&U) (51,585) (63,176) (69,179) (78,841) (88,351) (97,069)32. TOTAL O&M EXPENSE EXCLUDING FF&U 2,227,406 2,425,434 2,578,450 2,850,090 2,903,759 2,990,80886

Table IX-35Southern California Edison CompanyTest year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Generation Expenses($000)Line No. Account No.1. Steam:DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20142. 500 Operation Supervision and Engineering 22,403 19,163 20,089 20,592 20,592 20,5923. 501 Fuel 3,805 3,805 3,805 3,805 3,805 3,8054. 502 Steam Expenses 8,731 8,731 8,731 8,731 8,731 8,7315. 505 Electric Expenses 735 805 805 805 805 8056. 506 Miscellaneous Steam Power Expenses 6,728 5,141 5,141 4,581 4,581 4,5817. 507 Rents 223 223 223 223 223 2238. 509 Allowances - - - - - -9. 510 Maintenance Supervision and Engineering 845 931 931 931 931 93110. 511 Maintenance of Structures 827 691 691 691 691 69111. 512 Maintenance of Boiler Plant 12,058 19,473 12,378 14,719 14,719 14,71912. 513 Maintenance of Electric Plant 1,707 7,601 2,182 3,970 3,970 3,97013. 514 Maintenance of Miscellaneous Steam Plant 5,132 4,932 4,545 4,281 4,281 4,281Four Corners Maintenance Outage Adjustment - - - - - -14. TOTAL STEAM 63,194 71,496 59,521 63,329 63,329 63,32915. Nuclear:16. 517 Operation Supervision and Engineering 80,967 84,372 84,372 87,290 87,290 87,29017. 518 Nuclear Fuel Expense - - - - - -18. 519 Coolants and Water 4,464 6,044 6,118 5,875 5,875 5,87519. 520 Steam Expenses 35,009 34,467 34,467 33,684 33,684 33,68420. 523 Electric Expenses 5,504 5,504 5,504 5,504 5,504 5,50421. 524 Miscellaneous Nuclear Power Expenses 105,131 103,817 115,060 114,618 114,618 114,61822. 525 Rents 1,599 1,599 1,599 1,599 1,599 1,59923. 528 Maintenance Supervision and Engineering 39,839 33,722 33,722 33,722 33,722 33,72224. 529 Maintenance of Structures 7,342 9,715 9,715 9,715 9,715 9,71525. 530 Maintenance of Reactor Plant Equipment 8,353 10,419 10,419 10,419 10,419 10,41926. 531 Maintenance of Electric Plant 8,799 8,799 8,799 8,799 8,799 8,79927. 532 Maintenance of Miscellaneous Nuclear Plant 66,191 61,083 63,942 58,642 58,642 58,64228. SONGS 2&3 Refueling Outage Adjustment - - - 35,984 35,984 35,98429. TOTAL NUCLEAR 363,198 359,541 373,717 405,852 405,852 405,85230. Hydro:31. 535 Operation Supervision and Engineering. 6,065 6,065 6,065 6,065 6,065 6,06532. 536 Water for Power 3,637 3,856 3,856 3,856 3,856 3,85633. 537 Hydraulic Expenses 2,683 2,683 2,917 3,045 3,045 3,04534. 538 Electric Expenses 2,785 2,938 3,067 3,584 3,584 3,58435. 539 Miscellaneous Hydraulic Power Generation Expenses 14,299 15,885 16,748 18,723 18,723 18,72336. 540 Rents 2,213 2,814 2,814 2,814 2,814 2,81437. 541 Maintenance Supervision and Engineering 2,148 2,245 2,245 2,245 2,245 2,24538. 542 Maintenance of Structures 1,322 1,558 1,558 2,184 2,184 2,18439. 543 Maintenance of Reservoirs, Dams and Waterways 3,107 3,919 3,924 5,574 5,574 5,57440. 544 Maintenance of Electric Plant 4,623 5,964 6,182 6,602 6,602 6,60241. 545 Maintenance of Miscellaneous Hydraulic Plant 3,490 2,918 2,918 2,918 2,918 2,91842. TOTAL HYDRO 46,372 50,845 52,294 57,610 57,610 57,61087

Table IX-35 (Cont’d)Southern California Edison CompanyTest year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Generation Expenses($000)Line No. Account No.43. Other:DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 201444. 546 Operation Supervision and Engineering 3,693 4,605 4,630 4,655 4,655 4,65545. 547 Fuel - - - - - -46. 548 Generation Expenses 5,883 6,948 7,393 7,838 7,838 7,83847. 549 Miscellaneous Other Power Generation Expenses 13,803 16,985 17,710 20,220 20,220 20,22048. 550 Rents 318 1,737 2,300 5,487 5,487 5,48749. 551 Maintenance Supervision and Engineering 2,106 1,823 1,941 2,057 2,057 2,05750. 552 Maintenance of Structures 1,323 1,223 1,223 1,223 1,223 1,22351. 553 Maintenance of Generating and Electric Plant 39,372 23,700 25,153 37,478 37,478 37,47852. 554 Maintenance of Miscellaneous Other Power Generation Plant 2,491 3,426 3,504 3,581 3,581 3,58153. 555 Purchased Power - - - - - -54. 556 System Control and Load Dispatching 1,210 1,210 1,210 1,210 1,210 1,21055. 557 Other Expenses 42,249 47,968 52,536 59,340 59,340 59,34056. TOTAL OTHER 112,448 109,625 117,600 143,089 143,089 143,08957. TOTAL PRODUCTION 585,212 591,507 603,132 669,880 669,880 669,88058. Escalation - 15,356 31,937 51,721 72,446 92,71259. TOTAL INCLUDING ESCALATION 585,212 606,863 635,069 721,601 742,326 762,59160. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:61. Total Company Constant 2009$62. Labor 315,561 313,466 330,249 338,167 338,167 338,16763. Non-Labor 245,437 266,998 260,593 312,879 312,879 312,87964. Other 24,214 11,043 12,290 18,834 18,834 18,83465. Subtotal Total Company 585,212 591,507 603,132 669,880 669,880 669,88066. Escalation:67. Labor - 10,332 20,300 28,919 39,407 50,35768. Non-Labor - 5,024 11,637 22,802 31,154 39,85269. Other - - - - 1,884 2,50370. Subtotal Total Company - 15,356 31,937 51,721 72,446 92,71271. TOTAL INCLUDING ESCALATION 585,212 606,863 635,069 721,601 742,326 762,59188

Table IX-36Southern California Edison CompanyTest Year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Transmission Expenses($000)LineNo.AccountNo.DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20141. Operation:2. 560 Operation Supervision and Engineering 19,304 17,043 19,007 19,012 19,012 19,0123. 561 Load Dispatching 8,867 10,742 11,362 11,362 11,362 11,3624. 562 Station Expenses 12,256 12,547 12,609 12,659 12,659 12,6595. 563 Overhead Line Expenses 2,670 3,290 3,327 3,851 3,851 3,8516. 564 Underground Line Expenses 720 977 983 991 991 9917. 565 Transmission of Electricity by Others - - - - - -8. 566 Miscellaneous Transmission Expenses 36,215 42,299 46,275 48,965 48,965 48,9659. 567 Rents 5,538 8,224 8,224 8,224 8,224 8,22410. TOTAL OPERATION 85,570 95,122 101,787 105,064 105,064 105,06411. Maintenance:12. 568 Maintenance Supervision and Engineering 13,830 14,821 15,477 16,337 16,337 16,33713. 569 Maintenance of Structures 3,214 3,228 3,228 3,228 3,228 3,22814. 570 Maintenance of Station Equipment 23,892 22,820 25,793 26,645 26,645 26,64515. 571 Maintenance of Overhead Lines 34,242 30,119 39,882 36,068 36,068 36,06816. 572 Maintenance of Underground Lines - - - - - -17. 573 Maintenance of Miscellaneous Transmission Plant 1,541 4,057 4,153 4,248 4,248 4,24818. TOTAL MAINTENANCE 76,719 75,045 88,533 86,526 86,526 86,52619. TOTAL TRANSMISSION EXPENSE 162,289 170,167 190,320 191,590 191,590 191,59020. Escalation - 3,594 8,901 13,858 19,106 24,72621. TOTAL INCLUDING ESCALATION 162,289 173,761 199,221 205,448 210,696 216,31622. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:23. Total Constant 2009$24. Labor 63,327 73,569 77,880 79,151 79,151 79,15125. Non-Labor 98,146 95,782 111,624 111,623 111,623 111,62326. Other 816 816 816 816 816 81627. Subtotal 162,289 170,167 190,320 191,590 191,590 191,59028. Escalation:29. Labor - 2,425 4,787 6,769 9,224 11,78730. Non-Labor - 1,170 4,114 7,089 9,811 12,84531. Other - - - - 72 9432. Subtotal - 3,594 8,901 13,858 19,106 24,72633. TOTAL INCLUDING ESCALATION 162,289 173,761 199,221 205,448 210,696 216,31689

Table IX-37Southern California Edison CompanyTest Year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Distribution($000)LineNo.AccountNo.1. Operation:DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20142. 580 Operation Supervision and Engineering 32,026 30,857 30,876 34,741 35,717 35,7173. 582 Station Expenses 17,685 17,880 17,948 18,000 18,000 18,0004. 583 Overhead Line Expenses 23,630 20,077 20,542 20,734 20,734 20,7345. 584 Underground Line Expenses (2,691) (1,301) 218 (346) (346) (346)6. 585 Street Lighting and Signal System Expenses 503 579 580 585 585 5857. 586 Meter Expenses 25,054 26,823 27,509 29,231 19,133 19,1338. 587 Customer Installations Expenses 17,578 17,603 17,632 17,967 17,154 17,1549. 588 Miscellaneous Distribution Expenses 136,740 148,522 139,720 143,040 141,521 141,52110. 589 Rents 604 604 604 604 604 60411. TOTAL OPERATION 251,129 261,644 255,629 264,556 253,102 253,10212. Maintenance:13. 590 Maintenance Supervision and Engineering 43,669 44,999 46,080 47,500 47,500 47,50014. 591 Maintenance of Structures 62 492 492 492 492 49215. 592 Maintenance of Station Equipment 10,038 11,523 11,605 11,761 11,761 11,76116. 593 Maintenance of Overhead Lines 105,408 121,007 120,167 132,249 132,249 132,24917. 594 Maintenance of Underground Lines 14,231 16,449 15,891 22,653 22,653 22,65318. 595 Maintenance of Line Transformers 834 1,081 1,081 1,081 1,081 1,08119. 596 Maintenance of Street Lighting and Signal Systems 5,565 5,283 5,300 5,341 5,341 5,34120. 597 Maintenance of Meters 1,659 1,667 1,677 1,689 1,911 1,91121. 598 Maintenance of Miscellaneous Distribution Plant 20,438 22,947 22,867 23,970 23,970 23,97022. TOTAL MAINTENANCE 201,904 225,448 225,160 246,736 246,958 246,95823. TOTAL DISTRIBUTION EXPENSE 453,033 487,092 480,789 511,292 500,060 500,06024. Escalation - 11,143 23,524 37,504 50,207 64,03325. TOTAL INCLUDING ESCALATION 453,033 498,235 504,313 548,796 550,267 564,09326. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:27. Total Constant 2009$28. Labor 218,627 238,039 239,786 256,955 246,392 246,39229. Non-Labor 234,406 249,053 241,003 254,337 253,668 253,66830. Other - - - - - -31. Subtotal 453,033 487,092 480,789 511,292 500,060 500,06032. Escalation:33. Labor - 7,846 14,739 21,974 28,713 36,69134. Non-Labor - 3,297 8,784 15,530 21,495 27,34235. Other - - - - - -36. Subtotal - 11,143 23,524 37,504 50,207 64,03337. TOTAL INCLUDING ESCALATION 453,033 498,235 504,313 548,796 550,267 564,09390

Table IX-38Southern California Edison CompanyTest Year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Customer Accounts Expenses($000)LineNo.AccountNo.DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20141. 901 Supervision 12,062 13,054 13,801 14,630 14,772 14,7722. 902 Meter Reading Expenses 44,301 44,777 45,541 46,202 25,455 25,4553. 903 Customer Records and Collection Expenses 106,017 106,448 108,568 115,102 115,964 115,9644. 904 Uncollectible Accounts 11,258 13,235 14,493 15,904 17,823 19,5815. 905 Miscellaneous Customer Accounts Expenses 31,062 33,215 34,373 37,888 37,261 37,2616. TOTAL CUSTOMER ACCOUNTS 204,700 210,729 216,776 229,727 211,275 213,0347. Escalation - 5,715 11,216 16,895 20,486 25,9838. TOTAL INCLUDING ESCALATION 204,700 216,444 227,992 246,622 231,761 239,0179. Less: Account 904 (Uncollectible Accounts) (11,258) (13,235) (14,493) (15,904) (17,823) (19,581)10. TOTAL LESS ACCOUNT 904 193,442 203,209 213,499 230,717 213,939 219,43511. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:12. Total Constant 2009$13. Labor 130,348 133,904 137,531 145,411 122,116 122,11614. Non-Labor 40,770 63,064 64,226 67,685 70,610 70,61015. Other 33,582 13,761 15,019 16,630 18,549 20,30716. Subtotal 204,700 210,729 216,776 229,727 211,275 213,03417. Escalation:18. Labor - 4,413 8,454 12,435 14,231 18,18519. Non-Labor - 1,302 2,762 4,460 6,256 7,79820. Other - - - - - -21. Subtotal - 5,715 11,216 16,895 20,486 25,98322. TOTAL INCLUDING ESCALATION 204,700 216,444 227,992 246,622 231,761 239,01723. Less: Account 904 (Uncollectible Accounts) (11,258) (13,235) (14,493) (15,904) (17,823) (19,581)24. TOTAL LESS ACCOUNT 904 193,442 203,209 213,499 230,717 213,939 219,43591

Table IX-39Southern California Edison CompanyTest Year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Customer Service and Information and Sales Expenses($000)LineNo.AccountNo.DescriptionRecorded/Adj.Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20141. 907 Supervision 9,532 10,463 10,439 10,729 11,123 11,1232. 908 Customer Assistance Expenses 31,175 32,199 34,818 37,882 40,775 40,7753. 909 Informational and Instructional Advertising Expenses - - - - - -4. 910 Miscellaneous Customer Service and Informational Expenses - - - - - -5. 912 Demonstrating and Selling Expenses - - - - - -6. 913 Advertising Expenses - - - - - -7. TOTAL CUSTOMER SERVICE & information 40,707 42,662 45,257 48,611 51,898 51,8988. 916 Miscellaneous Sales Expenses 1,458 1,458 1,458 1,458 1,458 1,4589. TOTAL SALES EXPENSE 1,458 1,458 1,458 1,458 1,458 1,45810. TOTAL CSI AND SALES EXPENSE 42,165 44,120 46,715 50,069 53,356 53,35611. Escalation - 1,089 2,329 3,707 5,431 6,89012. TOTAL INCLUDING ESCALATION 42,165 45,209 49,044 53,776 58,787 60,24613. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:14. Total Constant 2009$15. Labor 25,470 26,009 26,455 27,693 29,275 29,27516. Non-Labor 16,695 18,111 20,260 22,376 24,081 24,08117. Other - - - - - -18. Subtotal 42,165 44,120 46,715 50,069 53,356 53,35619. Escalation:20. Labor - 857 1,626 2,368 3,411 4,35921. Non-Labor - 232 703 1,339 1,955 2,45022. Other - - - - 64 8023. Subtotal - 1,089 2,329 3,707 5,431 6,89024. TOTAL INCLUDING ESCALATION 42,165 45,209 49,044 53,776 58,787 60,24692

Table IX-40Southern California Edison CompanyTest Year 2012 General Rate CaseOperation & Maintenance ExpensesCategory: Administrative and General Expenses($000)LineNo. Account No. DescriptionRecorded/Adj. Estimated (in Constant 2009$)2009 2010 2011 2012 2013 20141. Operation:2. 920 Administrative and General Salaries/Office Supplies and Expenses 333,114 371,388 395,565 432,923 432,923 432,9233. 921 Administrative and General Salaries/Office Supplies and Expenses 153,794 165,597 172,989 196,548 196,548 196,5484. 922 Administrative Expenses Transferred - Credit (104,834) (124,583) (133,597) (151,289) (154,899) (159,481)5. 923 Outside Services Employed 48,281 46,466 46,116 52,043 52,043 52,0436. 924 Property Insurance 10,536 16,436 14,086 15,544 15,544 15,5447. 925 Injuries and Damages 75,516 105,125 123,142 125,726 125,726 125,7268. 926 Employee Pensions and Benefits 251,187 266,436 286,912 326,914 334,551 350,8299. 927 Franchise Requirements 40,327 49,940 54,686 62,937 70,528 77,48810. 928 Regulatory Commission Expenses 1,094 2,010 2,010 2,010 2,010 2,01011. 930 General Advertising Expenses-Miscellaneous General Expenses 1,192 7,172 5,025 8,642 8,642 8,64212. 931 Rents 14,447 15,974 18,403 19,058 19,058 19,05813. Reduction for Productivity Savings/A&G Credit for Catalina utilities (900) (900) (900) (9,900) (9,900) (9,900)14. TOTAL OPERATION 823,754 921,062 984,438 1,081,157 1,092,775 1,111,43115. Maintenance:16. 935 Maintenance of General Plant 7,838 7,838 7,838 7,838 7,838 7,83817. TOTAL MAINTENANCE 7,838 7,838 7,838 7,838 7,838 7,83818. TOTAL A&G 831,592 928,900 992,276 1,088,995 1,100,613 1,119,26919. Escalation - 19,197 39,715 63,694 97,659 126,34620. TOTAL INCLUDING ESCALATION 831,592 948,096 1,031,991 1,152,689 1,198,272 1,245,61421. Less: Account 927 (Franchise Requirements) (40,327) (49,940) (54,686) (62,937) (70,528) (77,488)22. TOTAL LESS ACCOUNT 927 791,265 898,156 977,304 1,089,752 1,127,744 1,168,12723. LABOR, NON-LABOR AND OTHER EXPENSE DETAIL:24. Total Constant 2009$25. Labor 344,635 383,009 407,672 445,565 445,565 445,56526. Non-Labor 269,723 295,512 300,407 325,443 325,443 325,44327. Other 217,235 250,378 284,196 317,986 329,604 348,26028. Subtotal 831,592 928,900 992,276 1,088,995 1,100,613 1,119,26929. Escalation:30. Labor - 12,624 25,059 38,103 51,923 66,35031. Non-Labor - 6,573 14,656 25,591 36,098 47,35232. Other - - - - 9,638 12,64433. Subtotal - 19,197 39,715 63,694 97,659 126,34634. TOTAL INCLUDING ESCALATION 831,592 948,096 1,031,991 1,152,689 1,198,272 1,245,61435. Less: Account 927 (Franchise Requirements) (40,327) (49,940) (54,686) (62,937) (70,528) (77,488)36. TOTAL LESS ACCOUNT 927 791,265 898,156 977,304 1,089,752 1,127,744 1,168,12793

1234567891011121314151617181920212223X.POST-TEST YEAR RATEMAKINGThis chapter presents SCE’s proposal to extend our current Post-Test Year Ratemaking (PTYR)mechanism. This mechanism is intended to provide additional revenues, as necessary, to cover our costsof doing business in calendar years 2013 and 2014, including our program to step-up capital investment tomeet growing demand and to replace aging utility infrastructure. Our current PTYR mechanism wasadopted in SCE’s 2003 General Rate Case and extended, with modifications, in SCE’s 2006 and 2009General Rate Cases. 54SCE currently operates under ratemaking that incorporates two revenue balancing accountmechanisms known as the Base Revenue Requirement Balancing Account (BRRBA) and the New SystemGeneration Balancing Account (NSGBA). (These accounts are discussed in Chapter IV of this volume.)Under these mechanisms, rates are designed to recover the authorized revenue requirement with anyvariation in recorded revenues (either higher or lower) tracked in a balancing account for subsequentrecovery from, or refund to, retail customers. Consequently, during the period in which the revenuerequirement is in effect, any additional revenues which result from customer growth or increased usageper customer are returned to customers as a rate decrease, rather than being available to offset SCE’s costincreases. Thus, it is necessary to provide for an increase in the annual revenue requirement to recovercost increases caused by increased capital spending, including the need to provide facilities to meet loadgrowth and to replace aging infrastructure facilities, 55 and the impact of price inflation on operatingexpenses. 56 In this manner, SCE is provided a fair opportunity to earn its authorized return on equity. SCEis proposing a ratemaking formula that results in the projected revenue requirement increases for 2013and 2014 that are shown in Chapters II and III of this volume, plus an adjustment in 2013 to includeSmartConnect costs in the GRC revenue requirement after SmartConnect is fully deployed, as discussed54 D.04-07-022 (mimeo), pp. 266-281. D.06-05-016 (mimeo), pp. 290-309. D.09-03-025, (mimeo), pp. 302-307.55 SCE’s rates reflect the embedded cost of existing facilities, which are partly depreciated. Because plant is valued atoriginal cost (without adjustment for inflation) less accumulated depreciation, new facilities that are added toaccommodate load growth will cost more than the average value (for ratemaking purposes) of existing plant. When olderfacilities are replaced with new ones, the associated cost is typically much higher that what is included in rates for theoriginal facilities. Cost increases associated with facility replacement at a historical rate are compounded by SCE’sprogram to increase the rate of facility replacement, as described in Exhibit SCE-03, Volume 3, Part 3.56 As explained more fully in section B.1 below, SCE’s post test year ratemaking mechanism does not include any offset foradditional O&M expense resulting from new customers. This feature, which is consistent with previous attritionmechanisms authorized by the Commission, and SCE’s current PTYR mechanism, is an implicit productivity adjustment.94

12345678910111213141516171819202122in Exhibit SCE-04, Volume 1, Chapter IV. 57 SCE proposes to update its revenue requirement projectionsbased on updated price inflation forecasts that will be made in annual filings prior to 2013 and 2014.These annual filings will also include an adjustment for the cost of nuclear refueling outages at SanOnofre Nuclear Generation Station.Under our PTYR mechanism proposal we may seek recovery of costs imposed on SCE as a resultof Commission actions. SCE's proposed post test year ratemaking mechanism is based on events knownand reasonably anticipated as of the date this testimony is being prepared. Subsequent Commissionactions or other events may require SCE to propose changes to this mechanism.A. Background1. Rate Case PlanUnder the Rate Case Plan, as modified by Commission Resolution ALJ-151 andD.89-01-040, 58 energy utilities file General Rate Case (GRC) applications every three years. The AttritionRevenue Requirement Adjustment mechanism was adopted by the Commission 59 in the early 1980s tocompensate utilities for the increased costs that occurred between test years and has since been a regularpart of utility ratemaking. 60 Over approximately this same period, the Commission utilized an ElectricRevenue Adjustment Mechanism (ERAM) or similar balancing account mechanisms to remove theincentive for SCE to promote electricity sales at the expense of conservation and demand reductionprograms.Annual cost increases can be caused by inflation and plant additions used to maintain andprovide service. Without a means to recognize these increases in rates, SCE will not have a reasonableopportunity to earn its authorized rate of return after the test year, as evidenced by the projectionspresented in Chapters II and III of this volume. Since the BRRBA and the NSGBA prevent SCE from57 As the costs for SmartConnect in Exhibit SCE-04 are estimated in 2009 dollars, the adjustment in 2013 will include O&Mescalation for the period from 2009 through 2013.58 D.89-01-040, 30 CPUC 2d 576.59 In D.92549, issued in conjunction with Edison’s 1981 GRC application, the Commission adopted Staff’s recommendationto implement stepped rate changes for 1982, citing Staff’s argument that “the use of stepped rates would provide a morestable earnings pattern.” 5 CPUC 2d 39, 80.60 In D. 96-09-092, the Commission adopted a five-year performance based ratemaking mechanism that provided annualincreases in SCE’s distribution rates based on a measure of inflation less a productivity factor, and allowed SCE to retainadditional revenues that resulted from sales and customer growth. In anticipation of adopting a PBR mechanism, theCPUC did not authorize an attrition mechanism in SCE’s 1995 test year GRC.95

12345678910111213141516171819202122232425262728retaining the incremental revenue from sales that are above projected levels, SCE must have an explicitratemaking mechanism to permit it to recover increased costs.2. Operational Cost ChangesAfter the test year, SCE’s earned rate of return is directly affected by operational andfinancial cost changes. Operational cost changes due to price increases in the goods and services that weemploy in our operations and the level of capital assets required to operate our business are addressed bythe PTYR mechanism proposed in this exhibit. Financial costs, such as the cost of long-term debt andpreferred stock, are not addressed by the PTYR mechanism.B. Need For Revenue Requirement IncreasesThis section explains why we anticipate that revenue requirement increases will be required during2013 and 2014.1. Inflation And ProductivityDespite the dramatic decrease in price inflation in the U. S. economy that has occurredsince the late 1970s and 1980s, inflation still results in higher costs for the inputs that we use to provideservice to our customers. 61 The labor and nonlabor escalation rates presented in Chapter VII of thisvolume document the operation and maintenance (O&M) inflation expected from 2010 through 2014. Wewill also incur higher costs for capital equipment to replace worn out equipment and to build facilities toserve new customers.In the past, our productivity performance has acted as a partial offset to our increasedcosts, but generally productivity improvements are not sufficient to avoid cost increases, particularlywhen we cannot keep the revenue increases from output (kWh sales, kW demand) increases. In addition,our revenue requirements will increase as a result of the costs associated with serving new customers.These two factors make a post test year ratemaking mechanism necessary to provide SCE a fairopportunity to recover its costs.Under a revenue balancing account, we do not retain any incremental revenue from growthin usage or new customers to offset the increased costs of operation that result from these influences.Under the attrition mechanisms previously authorized by the Commission and SCE’s current PTYRmechanism, it has been assumed that increased O&M costs from customer and usage growth are offset by61 Perhaps the most notable example that consumers will recognize is that the price of gasoline has increased by almost 80percent from 2004 and almost 30 percent from 2009. (Based on the Producer Price Index for gasoline, not seasonallyadjusted.).96

1234567891011121314151617181920212223242526productivity gains that will be achieved during the attrition years. 62 These mechanisms generally havepermitted recovery of O&M cost increases due to input price escalation (O&M labor escalation and O&Mnonlabor escalation) during attrition or post test year periods, but have not permitted recovery of O&Mcost increases due to other factors. Limiting recovery of O&M cost increases in this way results in animplicit expectation that productivity gains will offset O&M cost increases from other sources. (AppendixA provides a mathematical analysis of this question.) This is why our PTYR mechanism adjusts our testyear O&M expense levels for escalation and Commission-mandated and government-mandated changes,but does not include an explicit productivity offset to these adjustments.2. Enhancing SCE’s Financial StandingSCE has returned to financial health and investment grade status, but SCE has not returnedto the financial stature that it enjoyed before the California energy crisis. SCE’s credit ratings are belowmid-2000 levels, before the energy crisis began. A reasonable regulatory mechanism that will allow SCEto recover its revenue requirement during 2013 and 2014 will solidify SCE’s return to financial health.If SCE can achieve higher credit ratings than it currently possesses, customers will benefitfrom reduced financing costs. The Commission should extend SCE’s PTYR mechanism to support SCE’sfinancial recovery. The PTYR mechanism should provide that capital-related costs will be recovered asinvestments are made and enter rate base and it will also allow timely recovery of reasonable costincreases in operation and maintenance costs that result from cost inflation and customer growth.SCE cannot afford a post test year ratemaking mechanism that allows it to recover costsonly associated with average historical levels of capital additions. Nor can SCE afford a post test yearratemaking mechanism that increases its authorized revenue requirement in one year but avoids anyincrease in another. SCE’s capital expenditures are rising sharply from historical levels and those capitalexpenditures will result in substantial revenue requirement increases after the 2012 test year. TheCommission should continue the positive steps that it took in SCE’s 2003 and 2006 General Rate Caseapplications to ensure that SCE’s authorized revenue requirement will be sufficient to permit it to makethe capital investments that are necessary to maintain and expand its system, and serve its customers. 63 As62 D.04-07-022 (mimeo), pp. 273-274.63 The use of an actual capital additions budget, as specified in the 2003 GRC decision, is superior to the escalation of testyear capital additions, as adopted in the 2006 GRC decision, or the escalation of SCE’s revenue requirement, as adopted inthe 2009 GRC decision.97

1234567891011121314151617181920212223242526272829discussed in more detail below, the post test year ratemaking mechanism adopted in the 2009 GeneralRate Case contained significant flaws. It does not serve as a model for this case.C. Features Of Our Proposed MechanismWe propose a PTYR mechanism with the following features:• An annual advice letter providing notice of the revenue requirement change for the followingyear.• O&M escalation using the GRC escalation rate methodology, updated at the time of the adviceletter filing.• Capital-related cost increases using SCE’s Board-approved capital budget, calculated in thefollowing volume of this exhibit, updated for changes in SCE’s authorized cost of capital.• Inclusion of SmartConnect costs beginning in 2013, after SmartConnect is fully deployed.• An annual revenue adjustment to reflect the number of nuclear refueling outages at San OnofreNuclear Generating Station (SONGS) and cost per refueling outage as adopted in thisproceeding and updated for escalation. 64• A mechanism to address major exogenous changes in SCE’s costs.These features are discussed in more detail in the following sections.1. Annual PTYR Mechanism Advice LetterSCE will file an annual PTYR mechanism advice letter by November 1 of 2012 and 2013for the following year, consistent with current procedure. This advice letter will specify the revenuerequirement adjustment for O&M escalation, changes in capital-related costs, and the expected number ofnuclear refueling outages and related costs.2. O&M EscalationChapter VII of this volume describes SCE’s methodology for determining escalation ratesfor labor and non-labor O&M expense. SCE proposes to use the same methodology, with someadjustments as discussed below, to determine O&M escalation rates to calculate the O&M expenseadjustments for 2013 and 2014.a) Latest Global Insight Escalation Rates Will Be UsedSCE’s annual revenue change advice letter will be filed by November 1 of 2012and 2013 for the following year. SCE will employ the latest Global Insight escalation rates that are64 This SONGS refueling O&M expense methodology also would apply in Test Year 2012, should an outage occur in thatyear.98

1234567891011121314151617181920212223242526272829available on October 1 of the year in which these filings are made. These will be from the “Control”projection if Global Insight publishes more than one projection.b) Escalation Rates Will Be “Trued Up” To Actual, But Previous Forecast Errors WillNot Be Recovered Or RefundedThis provision applies to the O&M escalation adjustment for 2014. In theNovember 2013 advice letter filing, SCE will compute the authorized level of O&M expense for 2014 byapplying compound escalation factors from 2012 through 2014 to the authorized level of O&M expensefor 2012. These escalation factors will be the latest available, so that actual escalation will becomeincorporated as it becomes known. This procedure will ensure that the 2014 O&M escalation adjustmentcaptures all of the latest information for escalation from the test year forward.The 2014 authorized level of O&M expense will be calculated as the 2012 levelmultiplied by an escalation factor for 2013 and an escalation factor for 2014, based on the latest GlobalInsight escalation rates available by October 1, 2013. The escalation factor for 2013 will not be the factoremployed in the November 2012 advice letter for 2013 post test year ratemaking, but the factor based onthe latest information. However, there will be no true-up to the 2013 authorized level of O&M expenseresulting from updates to the escalation factor for 2013.c) Other Differences From Escalation Rates Calculated Through The Test YearThe labor O&M escalation rates for 2010 and 2011 incorporated union wageincreases and target wage increases for nonrepresented employees, as discussed in section A.3.(a)(2) ofChapter VII of this volume. For the annual advice letters, union wage increases and target wage increasesfor nonrepresented employees granted prior to the adoption of a Phase 1 decision in this application willbe incorporated in the labor escalation rates used in the 2013 and 2014 PTYR advice letters.d) Projected Labor And Non-Labor Escalation Rates For 2013 And 2014SCE’s projected labor and non-labor escalation rates for 2013 and 2014, based onthe information available at this time, are presented in Chapter VII of this volume.It is important that the escalation rates embedded in SCE’s PTYR mechanism beindustry-specific or company-specific, as SCE’s proposed escalation rates are. Use of a general inflationindex such as the Consumer Price Index (CPI) or Gross Domestic Product Chain-Weighted Price Index(GDPPI) should be avoided. The CPI tracks prices paid by consumers and excludes large categories of99

123456789101112SCE’s costs. In addition, it excludes health care costs paid by employers. 65 The GDPPI covers the entireU.S. economy and thus is far too broad to be an accurate measure of SCE’s input price inflation.e) Benefit Escalation RatesTestimony in Exhibit SCE-06, Volume 2, Chapter VII, discusses SCE’s medicalprogram costs for the test year and medical program cost escalation in 2013 and 2014. Escalation isprojected to be 10 percent in 2013 and 10 percent in 2014. These projected escalation rates should beapplied directly to medical program costs and PBOP (Post Retirement Benefits Other Than Pensions)costs without any updating when the PTYR advice letters are filed. It is reasonable to apply theseescalation rates to PBOP costs, since PBOP costs are dominated by medical costs.Other than medical cost escalation, SCE has not estimated special escalation ratesfor benefits for 2013 and 2014, but instead will use A&G labor and nonlabor escalation rates, as shown inTable X-41 below.Table X-41Benefit Escalation Rates13141516173. Capital-Related Cost IncreasesAs discussed in more detail in other parts of this application, we are engaged in amulti-year program of construction expenditures to meet sharply increased levels of system load growth,and to expand replacement of aging infrastructure. (See Exhibit SCE-03, Volumes 1 and 3.) Our proposedPTYR mechanism includes capital costs associated with a budget-based forecast of capital expenditures,65 D.04-07-022 (mimeo), p. 278.100

1234but we also propose that the associated revenue requirements be subject to refund if our capital spendingbudgets are not fully implemented. 66Our projected capital additions, including cost of removal, for 2013-2014 are shown in thefollowing table.Table X-42Proposed Capital Additions, 2013-2014($ millions)LineNo. 2013 20141. 4,676.2 4,101.2(These amounts include gross capital additions plus cost of removal.)567891011121314151617181920SCE is not proposing that its capital additions for test year 2012 be covered by this type of“one-way balancing account” mechanism. This is because when the Commission is considering anddeciding our test year request, we are close to the in-service dates for our capital projects. The customer isprotected because any variance between forecast and recorded capital additions is explained in our nextGRC application.4. Nuclear Refueling OutagesAs discussed in Exhibit SCE-02, Volume 1, during the post test year period, SCE projectstwo refueling outages at San Onofre Nuclear Generating Station (SONGS) during the post test yearperiod, one in 2013 and one in 2014. (Should a refueling outage occur in 2012, the mechanism describedhere will also apply in 2012.) In 2009 dollars, the total cost of each outage is projected to be$46.0 million. SCE’s share is $36.0 million. These costs will be escalated using the latest values of thenuclear labor and nonlabor escalation rates presented in Chapter VII of this volume.In November of each year, SCE files an advice letter to establish the authorized baserevenue requirement for the subsequent year. In that advice letter, SCE projects the number of nuclearrefueling outages for the following year. Depending on the actual operation of SONGS 2&3, there may bezero, one, or two outages in each year. As discussed in Exhibit SCE-02, Volume 1, SCE’s Base Revenue66 We will create a “one-way” balancing account that will refund any over-estimate of the revenue requirement associatedwith our post test year capital additions, including the cost of removal. The balancing account calculation will becumulative over the combined two-year period. This is the same as the balancing account that was adopted in our 2003General Rate Case. D.04-07-022, (mimeo), p. 277.101

123456789101112131415161718192021222324Requirement Balancing Account includes a “flexible outage schedule mechanism” 67 to recover refuelingoutage costs. This mechanism should be continued because it will match refueling outage costs withrevenue recovery.5. Treatment Of Major Exogenous Cost ChangesIn SCE’s current PTYR mechanism, SCE is permitted to seek recovery of costs associatedwith exogenous events (“Z-Factors”) that result in a major cost impact for SCE. The existing Z-Factormechanism allows either SCE or the Division of Ratepayer Advocates (DRA) to submit a Letter ofNotification to the Executive Director to identify any potential Z-Factor event. SCE is at risk for eventswhich do not have a financial impact of more than $10 million. In addition, there is a $10 million“deductible amount” applied on a one-time basis to the first year’s revenue requirement associated withany approved Z-Factors. Costs associated with two named contingencies, new municipal utility formationand P.U. Code Section 463 projects, are treated as Z-Factors but without the $10 million threshold or the$10 million deductible. 68The existing Z-Factor mechanism should be continued. Although neither SCE nor ORAhave identified any proposed Z-Factors since SCE’s 2003 GRC was decided, the Z-Factor mechanism hasnonetheless provided the assurance that a clear process is in place to deal with unanticipated majorvariations in SCE’s costs.6. The Commission Should Not Require An Application To Implement Post Test yearRatemakingIn authorizing post test year ratemaking for 2004 and 2005, the Commission imposed arequirement that if SCE’s revenue requirement increase were to exceed $150 million in either year, SCEwould be required to submit an application for that year, rather than an advice letter. 69 The Commissionstated that it was unwilling to permit greater rate increases to be implemented through the “streamlined”advice letter process.67 D.04-07-022 (mimeo), p. 274, Ordering Paragraph 7, pp. 357-358. D.06-05-016 (mimeo), p. 36; Finding of Fact 11, p. 352.D.09-03-025 (mimeo), pp. 13-14, 307; Conclusions of Law 2-3, p. 367; Ordering Paragraph 5, p. 393.68 The Z-factor mechanism was established in SCE’s 2003 Test Year General Rate Case. D.04-07-022 (mimeo), pp. 278-279;Finding of Fact 231, p. 346. Continuation was authorized in SCE’s 2006 and 2009 Test Year General Rate Cases.D.06-05-016 (mimeo), p. 308; Ordering Paragraph 7, p. 382. D.09-03-025, p. 306; Conclusion of Law 213, p. 390;Ordering Paragraph 5, p. 393.69 D.04-07-022 (mimeo), p. 281; Conclusion of Law 53, p. 355.102

12345678910111213141516171819Unlike that GRC application, however, this application contains testimony supportingSCE’s proposed capital expenditures through 2014, not just through the test year. 70 Thus, there is nosubstantial component of SCE’s post test year ratemaking mechanism that is not addressed by testimonyin this application. The Commission should not require SCE to submit a second application in 2012 or2013 to reapprove its proposed mechanism.D. SCE’s Proposed Capital Expenditure Program Will Provide A Much-Needed Boost To TheCalifornia EconomyThe primary reason for adopting SCE’s proposed test year ratemaking mechanism is that it willsupport the capital expenditures that SCE needs to make to maintain its system to properly serve itscustomers. SCE’s plan will also result in lower cost in the long run because infrastructure will be replacedon a planned basis, as opposed to only replacing equipment on an emergency basis when it fails.1. Overall Economic ImpactHowever, there is a secondary benefit to SCE’s proposed capital expenditures: SCE’sexpenditures will result in greater overall economic activity in Southern California. To calculate thisbenefit, SCE engaged the services of IHS Global Insight’s US Regional Service 71 to estimate the overalleconomic effects in Southern California of SCE’s proposed capital expenditures. IHS Global Insight’sstudy is found in Appendix C of this exhibit. They used an economic input/output model to estimate thetotal economic effects of SCE’s capital spending program. Their findings are summarized in Table X-43below:70 Further, when SCE submits its Test Year 2015 General Rate Case application, it will provide an updated forecast of 2013and 2014 capital additions, developed at a much closer point in time (2013 instead of 2010). The Commission will beafforded another review opportunity at that time if it chooses.71 Both the Commission and SCE have used Global Insight macroeconomic projections since at least the early 1980s.103

Table X-43Overall Economic Impacts From SCE’s Proposed Capital Expenditures,2010-2014Impact From SCE’s ProposalIncrease in Average Employment(Full-Time Jobs) 12,760Increase in Total Economic Output($Millions) 21,830Increase in Economic Value Added($Millions) 14,268Increase in Labor Income($Millions) 6,617Increase in State and Local Taxes($Millions) 1,216123456789101112131415161718In calculating these impacts, Global Insight took into account the possibility that ourspending might divert currently-employed resources from other projects. Global Insight also took intoaccount the offsetting effects of higher electricity rates during the forecast period. For this reason, theseare conservative estimates.One might think that the same economic impact would result over the 2010-2014 period ifSCE did not make the capital expenditures and customers had more money to spend for themselves. Butthat is not likely to be the case. The capital expenditures will be financed with equity and debt raised frominside and outside SCE’s service territory. Customers will only pay the revenue requirement associatedwith the capital expenditures in rates, which will be only a fraction of the total expenditures.Thus, as the Global Insight report shows, in addition to the greater direct benefits to ourcustomers that result from our capital expenditure program, when compared to the one implied by DRA’sproposal, our capital expenditure program provides greater broad economic benefits for our serviceterritory.2. Regional Economic ImpactIn addition to the HS Global Insight study, SCE commissioned a study by BeaconEconomics to estimate the regional economic impact within California of SCE’s proposed capitalexpenditure study. Beacon’s study is found in Appendix D to this exhibit. Beacon’s results aresummarized in the following table.19104

Table X-44Regional Economic Impacts From SCE’s Proposed Capital Expenditures,2010-2014123456789101112SCE’s capital expenditures will substantially improve the Southern California economicoutlook over this period.E. The Post-Test Year Mechanism Adopted In SCE’s 2009 GRC Contains Two FundamentalAnalytic Errors That Shortchanged SCE’s Revenue RequirementIn this 2012 GRC, as was the case in our 2009 GRC, SCE’s recorded base year spending does notmatch the Commission-authorized revenue requirement for 2009. The Commission’s final decision inSCE’s 2009 GRC contained a methodological error that forced SCE to temporarily restrain capitalinvestment in late 2008 72 and 2009 to levels below the authorized amounts in order to ensure thatrecorded costs did not exceed authorized revenues in 2010 and 2011. This methodological error by theCommission, in which it overlooked SCE’s year-end 2008 balance of Construction Work in Progress(CWIP), 73 meant that SCE could not spend at the levels ostensibly authorized for 2009, but we are able todo so over the cumulative three-year cycle (2009-2011).72 Additionally, the delay in processing SCE’s GRC Application and the potentially deep cuts to SCE’s operations embeddedin the ALJ’s Proposed Decision required SCE to delay capital spending until a final decision was adopted by theCommission in March 2009. The “stranded” CWIP methodological error was even more acute in the ALJ’s proposeddecision, and would have forced cuts to levels below amounts previously recorded.73 See, FERC Uniform System of Accounts for Electric Utilities, 18 CFR, Part 101, Account 107:A. This account shall include the total of the balances of work orders for electric plant in process of construction.B. Work orders shall be cleared from this account as soon as practicable after completion of the job. Further, if a project,such as a hydroelectric project, a steam station or a transmission line, is designed to consist of two or more units or circuitswhich may be placed in service at different dates, any expenditures which are common to and which will be used in theoperation of the project as a whole shall be included in electric plant in service upon the completion and the readiness for(Continued)105

123456789101112131415161718192021In SCE’s 2009 GRC, as in this 2012 GRC, we proposed a method for the Commission to authorizerevenue requirements for the two attrition or post-test years (in that case 2010 and 2011, in this case 2013and 2014). 74 Our post-test year ratemaking proposal included detailed testimony on our capitalexpenditures for 2010 and 2011. However, in lieu of reviewing our entire capital forecast, theCommission instead adopted a ratemaking method that indexed our total 2009 adopted revenuerequirement by 4.25 percent for 2010 and 4.35 percent for 2011. The post-test year revenue requirementshould provide for recovery of authorized costs and a reasonable opportunity to earn the authorized rate ofreturn. But the post-test year ratemaking formula adopted in our 2009 GRC contained a fundamentalmethodological error 75 that effectively shortchanged our authorized revenues and jeopardized SCE’sability to earn its authorized rate of return.It can take many months for some capital projects to be completed and placed into service. Duringthat interim period, as we continue to make capital expenditures on those projects, we accrue anAllowance for Funds Used During Construction (AFUDC), which recognizes the financing costs beingincurred during construction. 76 The AFUDC accrual is eventually added to the overall cost of the asset,along with corporate overheads, then transferred to “Plant-in-Service” and the cost recovered over itsoperating life. During the period before the asset enters service, the costs are recorded in ConstructionWork in Progress (CWIP), FERC Account 107.The Commission’s decision on our 2009 GRC “stranded” Construction Work In Progress (CWIP)associated with authorized 2009 capital expenditures. That is, 2010 authorized revenues were not enoughto recover the authorized revenue requirement in 2010 when the 2009 CWIP balance is also considered.Our Results of Operations (RO) model, which we are required by this Commission to rely upon and thatContinued from the previous pageservice of the first unit. Any expenditures which are identified exclusively with units of property not yet in service shall beincluded in this account. …74 SCE’s 2009 post-test year ratemaking proposal is described in A.07-11-011, Exhibit SCE-11A, Vol. 1 and summarized inD.09-03-025 §14.75 SCE first brought this methodological error to the Commission’s attention in SCE’s 2006 General Rate Case. SeeApplication 02-05-004, Exhibit 87, page 8.76 See, FERC Uniform System of Accounts for Electric Utilities, 18 CFR, Part 101, Electric Plant Instruction 3(17):Allowance for funds used during construction (Major and Nonmajor Utilities) includes the net cost for the period ofconstruction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used, not toexceed, without prior approval of the Commission, allowances computed in accordance with the formula prescribed inparagraph (a) of this subparagraph. No allowance for funds used during construction charges shall be included in theseaccounts upon expenditures for construction projects which have been abandoned.106

123456789has also been used and endorsed by the Commission staff, includes estimates of the capital expendituresin-service dates. Our rate base forecast thus depends on both the capital expenditure amount and theforecast in-service dates. The rate base forecast, in turn, affects the revenue requirement. For example, ifthere is a $100 million project and the annual revenue requirement is $17 million, with an in-service dateof June 1, the first year’s revenue requirement would be $8.5 million. The second year’s revenuerequirement would be $17 million. The first year revenue requirement is pro-rated, but the following yearthe project would be in rate base for a full year, and the revenue requirement is for an entire year. Usingthis simplified example, overlayed with the 4.25 percent and 4.35 percent escalation is graphicallydepicted in Figure X-10 below.Figure X-10Illustrative Revenue Requirement Example20.0017.00 17.00(Millions of Dollars)10.008.508.869.250.00Year 1 Year 2 Year 3Revenue Requirement Authorized Revenues (4.25% & 4.35%)10111213Explaining how this error shortchanged our authorized revenues requires some background onratemaking. While SCE’s proposal in this GRC is to review and approve a post-test year capitalexpenditure forecast, in the event the Commission chooses to use a formulaic approach to setting the posttestyear revenue requirement, at a minimum this error should not be repeated.107

1234567891011121314151617181920212223242526272829303132331. The “Stranded” Construction Work In Progress Error In The 2009 GRC AdoptedPost-Test Year Ratemaking FormulasAs described in Mr. Shimmel’s testimony in Exhibit SCE-10, we budget capital on anexpenditure basis, which represents the company’s outlays for capital projects. Given the capital-intensivenature of our business, which is especially so for SCE, we must estimate the level of capital expendituresto ensure we can finance this level of investment. And while we budget by capital expenditure, manyprojects require months to construct, process invoices, and eventually close the work order. We cannotbegin to recover the investments until they are providing service to SCE customers. The commoncharacterization of capital assets serving utility customers is that they must be “used and useful.” Whilethese projects are being constructed, the monthly expenses being incurred by SCE are recorded in“CWIP.” SCE, like most utilities subject to cost-of-service ratemaking, will carry a balance in CWIP untilsuch time as a capital asset is placed into service. This CWIP balance will carry forward from the end ofone calendar year into the next. Ratemaking that follows cost-of-service principles would customarilyrecognize and link the capital expenditures authorized in year one, but closing subsequently, to year twowhen establishing the revenue requirement in year two.In SCE’s 2009 GRC, DRA witness Greg Wilson endorsed the manner in which SCE’sResults of Operation (RO) model converts capital expenditures to capital additions:SCE’s capital exhibits and supporting workpapers (as well as its RO computer model)are organized around capital expenditures. SCE’s capital witnesses provide testimonyregarding the magnitude of the direct capital dollars that are estimated to be spent eachyear, not how much is actually being booked to plant. SCE relies on its RO computermodel to manipulate these direct capital expenditures and calculate the correspondingcapital additions. DRA has studied SCE’s RO model, and believes that it properlycalculates plant additions. Therefore, DRA’s analyses and recommended direct capitaladjustments are also stated in terms of capital expenditures. When analyzing data inthis format, the impact of recommended adjustments to capital expenditures may notshow up in the year in which they are made. For example, suppose a capital project isscheduled to begin construction in 2008, but is not scheduled to be completed until2009. If DRA was to recommend an adjustment to the 2008 expenditures, there willnot be a revenue requirement impact until 2009, when the project is completed, isbooked to plant-in-service, and begins earning a return. 77Due to the timing differences between capital expenditures and capital additions, of thetotal 2009 capital expenditures the Commission approved in SCE’s 2009 GRC, $1.468 billion 78 ($96077 A.07-11-011, Exhibit DRA-13, pp. 8-9.78 The year-end CWIP balance in SCE’s application was $1.890 billion.108

123456million, CPUC jurisdiction) remained in CWIP as of year-end 2009. Note that this $1.468 billion 2009CWIP balance does not depend in any way on the 2010-2011 capital expenditure forecast the Commissiondeclined to review, but is based entirely on the capital expenditure forecasts the Commission did reviewand approve through the end of 2009.Figure X-11, below, compares the forecast revenue requirement – holding capital spendingflat at the level authorized in 2009 for the entire three-year GRC cycle (2009 – 2011).Figure X-112009 GRC CapEx Constant2010 & 2011(CPUC Jurisdiction)5,4005,3005,2002009 GRC - CapEx Constant - 2010 & 2011(CPUC Jurisdiction)Forecast RevenueRequirementExceeds AuthorizedRevenues: $85M5,3395,2545,1005,079(Milllions of Dollars)5,0004,9004,8004,8304,8305,035Forecast RevenueRequirementExceeds AuthorizedRevenues: $45M4,7004,6004,5002008 2009 2010 2011 2012789101112131415In theory, if a utility’s capital expenditure forecast were to be held constant year after yearfor an extended period of time and depreciation rates were adequate, the amount of CWIP closing in agiven year would be mostly offset by new entries and asset retirements, thus mitigating the revenuerequirement effect in the subsequent years.I do not believe the Commission intended to deny continued cost recovery for the verycapital expenditures it authorized in SCE’s 2009 GRC. However, its decision forced us to temporarilyrestrain certain capital investments so that over the three-year GRC cycle (2009-2011) cumulativecompany spending would mirror authorized revenues. SCE was further constrained by the fact that only asmall portion of authorized GRC revenues are “fungible,” or available to be re-prioritized. For example,109

123456789101112131415161718in this test year 2012 GRC revenue requirement approximately 45 percent is earmarked to pay for capitalinvestments authorized through 2009, another 30 percent (2009$) will fund the O&M expense levelsauthorized for 2009, with another 12 percent identified to fund capital spent in 2010 and 2011. The onlypractical way SCE could adjust spending to overcome this methodological error in the 2009 decision wasto adjust the timing of capital investment decisions in a manner that ensured recorded rate base did notcontribute to a higher revenue requirement than was authorized for years 2010 and 2011.I believe the Commission endeavors to meet its responsibility to provide utilities subject tocost-of-service regulation a reasonable opportunity to earn their authorized rates of return. 79 In fact, in our2003 GRC, the Commission rejected the same kind of simplified approach to post-test year ratemaking itadopted in our 2009 GRC. In that 2003 GRC, after noting its concern with relying on a utility’s budgetbasedforecasts, 80 the Commission also noted that focusing solely on recorded spending would overlookthe need for stepped-up spending to replace aging infrastructure. 81Based on these considerations, in our 2003 GRC the Commission adopted a post-test yearapproach that allowed us to include the capital costs associated with our budget-based forecast, with therevenue requirement subject to refund if we under-spent capital relative to the authorized forecast. Icontinue to believe this 2003 GRC approach was ultimately the most fair, both to our customers and toour investors, because it most accurately reflects our actual cost of service over the three-year GRC cycle.I urge the Commission to return to that approach in this 2012 GRC.79 See, Re Southern California Edison Co., D.04-07-022, §11.3, (mimeo), p. 271:We start with the proposition that a utility’s opportunity to earn a fair return on the investments made to provide adequateutility service is realized with the adoption of a just and reasonable forecast test year revenue requirement. Then, to judgewhether post-test year revenue adjustment provisions are appropriate, we inquire into whether there are, or will be,conditions that might undermine a utility’s opportunity to earn its authorized rate of return after the test year. Suchconditions need not be limited to those encountered 20 years ago, when the Commission was approving attritionadjustments because of high costs of utility debt and because the economy was unpredictable and volatile. Interest ratesmay be lower and the economy may be more stable now, but that does not mean there can be no other conditions thatimpact the utility’s ability to earn a reasonable return.80 It should be noted that a utility’s budget represents the most accurate forecast that can be prepared by any entity, and is thesingle most reliable estimate that can be developed.81 Id., p. 276:As we have repeatedly observed in this decision, there is a fundamental problem with budget-based ratemaking that boilsdown to the fact that budgets are not always implemented as planned.…When older facilities are replaced with new ones, the associated costs are typically much higher than what is included inrates for the original facilities. Moreover, the effect of this phenomenon is enhanced by the accelerated pace of plannedcapital spending associated with SCE’s infrastructure replacement program. …110

12345678910111213141516171819202122232425But whatever course of action the Commission follows, it must not replicate themethodology adopted in SCE’s 2009 GRC. With a growing need to expend capital on system utilityinfrastructure, review and approval of reasonable post-test year expenditures is necessary for SCE to havean opportunity to earn its authorized rate of return. However, in its decision on our 2009 GRC, theCommission rejected our proposal for determining post-test year amounts, citing two reasons:As we repeatedly observed in prior decisions, there is a fundamental problem withbudget-based ratemaking that boils down to the fact that budgets are not alwaysimplemented as planned. In addition, no party other than SCE provided or analyzeddetailed post-TY plant addition budget forecasts in determining increases. 82I address the first of these reasons – the “spending flexibility” principle of forecast testyear ratemaking in my testimony in Exhibit SCE-01. As to the second reason given for not relying onSCE’s post-test year capital forecast – the fact that no party reviewed those expenditures – we aresympathetic to other party’s resource constraints. But that constraint is not a valid reason for theCommission to ignore the evidence of the growing need to expend capital on aged utility infrastructureand the other reasons supporting our forecasts or to adopt a post-test year revenue requirement thatprecludes recovery of some of the very capital expenditures the Commission authorized.2. By Not Providing For Separate Escalation Of The Other Operating Revenues FromTariffed Services, the 2009 GRC’s Post-Test Year Ratemaking MechanismShortchanged the Authorized Revenue RequirementAnother flaw in the 2009 adopted post-test year ratemaking mechanism was its treatmentof Other Operating Revenues (OOR). OOR arises from various services, such as late fees, in whichindividual customers provide revenues to offset SCE’s revenue requirement, rather than all customers.Because the utility recovers such costs from individual customers, the revenues from these services offsetthe revenue requirement to be recovered from general ratepayers. In other words, the authorized revenuerequirement to be recovered from general ratepayers is “net” of OOR. 8382 Re Southern California Edison Co., D.09-03-025, §14, (mimeo), p. 305.83 See, e.g., Re Southern California Edison Co., D.91-12-076, (mimeo), p. 116: “Revenue credits are applied against utilitycosts in determination of net revenue requirement to be included in rates.” See also, Re Pacific Gas and Electric Co.,D.99-09-031, (mimeo), p. 2: “…Other Operating Revenues … functioned as an offset or reduction in the authorized 1996GRC revenue requirement. Since the revenue requirement was reduced by this amount, it was not included for recovery inrates in the GRC decision.” See also, Re Pacific Gas and Electric Co., D.08-06-038, (mimeo), p. 8: “PG&E proposes tocredit $1,000 received from the City for the easement to Other Operating Revenue. As a result of this action, the funds willreduce the future revenue requirements from customers consistent with conventional general rate case cost-of-serviceratemaking.”111

123456789101112As I discussed above, D.09-03-025’s post-test year formula escalates the total 2009revenue requirement (SCE’s authorized costs). This approach assumes that each of the line itemscomprising the overall revenue requirement is escalated at the same rate, including the tariffed servicerevenues. 84 However, the fees SCE is allowed to charge customers for tariffed services must be explicitlyapproved by the Commission and D.09-03-025 did not authorize SCE to increase any of those fees toprovide for additional revenues. In other words, the decision’s post-test year mechanism implicitlyassumed SCE would be able to increase tariffed OOR by 4.25 percent in 2010 and 4.35 percent in 2011but did not authorize any increase in the fees that generate that OOR. In 2010 this disconnect created a $5million shortfall between the adopted post-test year method and the revenues from fees for tariffedservices, an amount that grew to $10 million in 2011.Like the stranded CWIP error I discussed above, the post-test year ratemaking mechanismthe Commission adopts in this 2012 GRC should avoid this kind of methodological inconsistency.84 In mathematics, this is known as the Distributive Law.112

Appendix AWitness Qualifications

12345678910111213141516171819202122232425262728SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF TODD CAMERONQ. Please state your name and business address for the record.A. My name is Todd Cameron, and my business address is 2244 Walnut Grove Avenue, Rosemead,California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company.A. I serve as a Project Manager for the Treasurers department focusing on escalation and economicservices. My present responsibilities include applying economic and financial analysis toregulatory issues and for internal corporate purposes.Q. Briefly describe your educational and professional background.A. I received a Bachelor’s degree in Economics from San Diego State University and a Master’sdegree in Economics from California State University at Fullerton. Prior to joining SCE I was anEconometrician for Xactware Software (1992 – 1996) and an Economist for the RegionalEconomic Studies Institute (1996 – 1998). In 1998 I joined SCE as a Project Manager focusing onelectric market deregulation. At SCE, I have served as a Project Manager in various departmentsincluding CSBU, HR, TDBU, Controllers, and Treasurers.Q. What is the purpose of your testimony in this proceeding?A. The purpose of my testimony in this proceeding is to sponsor the portions of Exhibit SCE-10, Vol.1, entitled Results of Operations – Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking, as identified in the Table of Contents thereto.Q. Was this material prepared by you or under your supervision?A. Yes, it was.Q. Insofar as this material is factual in nature, do you believe it to be correct?A. Yes, I do.Q. Insofar as this material is in the nature of opinion or judgment, does it represent your bestjudgment?A. Yes, it does.A-1

12Q. Does this conclude your qualifications and prepared testimony?A. Yes, it does.A-2

1234567891011121314151617181920212223242526SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF RUSSELL D. GARWACKIQ. Please state your name and business address for the record.A. My name is Russell D. Garwacki, and my business address is 2244 Walnut Grove Avenue,Rosemead, California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company.A. My current responsibilities include managing the Load Research and Rate Design functions withinSCE’s Regulatory Policy and Affairs (RP&A) department. These functions include thedevelopment of present rate revenue forecasts.Q. Briefly describe your educational and professional background.A. I received a Bachelor of Arts degree in Economics from Whittier College in 1980 and a Master ofArts degree in Economics from Claremont Graduate School in 1983. I have been employed bySCE since 1983. From 1983 to 1993, I worked in the load research area of RP&A, ultimatelysupervising the group. During that time, I gained an understanding of sample design, costallocation, and other regulatory policies and procedures. In 1994, I joined the Customer ServiceBusiness Unit (CSBU) as the Credit Analysis Manager, working to reduce both write-off andcredit operational costs. From 1997 to 1999, I managed the Measurement and Efficiency group,delivering process improvements for CSBU’s Field Services, Credit, Payment, and CustomerCommunication Center functions. From 1999 to 2004, I managed various CSBU activitiesincluding Job Skills Training, Internet Delivery, Benchmarking, and various technical supportfunctions. In 2004, I returned to RP&A to assume my current responsibilities.Q. What is the purpose of your testimony in this proceeding?A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-10, Volume1, entitled Results of Operations – Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking, as identified in the Table of Contents thereto.A-3

12Q. Was this material prepared by you or under your supervision?A. Yes, it was.A-4

12345678910111213141516171819202122232425SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF JOHN GILLIESQ. Please state your name and business address for the record.A. My name is John Gillies, and my business address is 2244 Walnut Grove Avenue, Rosemead,California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company.A. I am a Senior Planner in the Energy Supply and Management Department. I am responsible for theforecast of SCE retail sales, customers, and meter connections for the years 2010 to 2014.Q. Briefly describe your educational and professional background.A. I hold a Bachelor of Arts Degree in Economics from Simon Fraser University in Vancouver,Canada and a Master of Arts Degree in Economics from Carleton University in Ottawa, Canada. Ihave held my current position at Southern California Edison for five years. Prior to this I held theposition of Senior Planner for four years at Arizona Public Service in Phoenix, Arizona.Q. What is the purpose of your testimony in this proceeding?A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-10, Volume1, entitled Results of Operations - Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking, as identified in the Table of Contents thereto.Q. Was this material prepared by you or under your supervision?A. Yes, it was.Q. Insofar as this material is factual in nature, do you believe it to be correct?A. Yes, I do.Q. Insofar as this material is in the nature of opinion or judgment, does it represent your bestjudgment?A. Yes, it does.A-5

12Q. Does this conclude your qualifications and prepared testimony?A. Yes, it does.A-6

12345678910111213141516171819202122232425262728SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF PAUL T. HUNT, JR.Q. Please state your name and business address for the record.A. My name is Paul T. Hunt, Jr., and my business address is 2244 Walnut Grove Avenue, Rosemead,California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company.A. I am the Director of Regulatory Finance and Economics, supervising the Regulatory FinanceDivision of the Treasurer’s Department. My present responsibility is to apply economic, financial,and statistical analysis to regulatory issues and for internal corporate purposes.Q. Briefly describe your educational and professional background.A. I received a Bachelor of Arts degree in Economics from Pomona College in 1975, a Master of Artsdegree in Economics from Stanford University in 1976, and a Doctor of Philosophy degree fromStanford University in 1981. I joined the Southern California Edison Company as an AssociateEconomist in the Treasurer’s Department in July 1980. I was promoted to Economist in 1982 andSenior Economist in 1984. In 1989, I transferred to the Regulatory Policy and Affairs Departmentas a Regulatory Economics Consultant. I returned to the Treasurer’s Department in 1996 as aSenior Economist. In 1997, I was promoted to Project Manager. In 2000, I was promoted toManager of Regulatory Finance and Economics. I was promoted to my present position in 2010.I have testified before the California Public Utilities Commission and the Federal EnergyRegulatory Commission.Q. What is the purpose of your testimony in this proceeding?A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-10, Volume1, entitled Results of Operations - Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking and Volume 2, entitled Plant, Taxes,Depreciation Expense and Reserve, and Rate Base, as identified in the Table of Contents thereto.Q. Was this material prepared by you or under your supervision?A. Yes, it was.A-7

1234567Q. Insofar as this material is factual in nature, do you believe it to be correct?A. Yes, I do.Q. Insofar as this material is in the nature of opinion or judgment, does it represent your bestjudgment?A. Yes, it does.Q. Does this conclude your qualifications and prepared testimony?A. Yes, it does.A-8

12345678910111213141516171819202122232425262728SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF DOUGLAS A. SNOWQ. Please state your name and business address for the record.A. My name is Douglas A. Snow, and my business address is 2244 Walnut Grove Avenue,Rosemead, California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE).A. I am the Manager of Revenue Requirements in SCE’s Regulatory Policy and Affairs (RP&A)Department. As such, I am responsible for overseeing the operation of various Balancing andMemorandum Accounts and the associated disposition of the balances in those accounts forratemaking purposes.Q. Briefly describe your educational and professional background.A. I graduated from Texas A&M University in May of 1982 with a Bachelors of Science Degree inIndustrial Engineering. In June of 1982, I went to work for Southwestern Public ServiceCompany (SPS) in west Texas. While there, I attained a title of Supervisory Engineer and wasresponsible for revenue requirement calculations and rate design for both retail and resalecustomers. I filed testimony on behalf of SPS before the Texas Public Utility Commission and theFederal Energy Regulatory Commission. In November of 1993, I went to work for the SouthernCalifornia Edison Company as a Financial Analyst in the FERC Pricing section in the RP&ADepartment. While working in the FERC section, I was responsible for the rate design for SCE’srequirements sales for resale, Wheeling Access Charges, and wholesale Distribution AccessCharges. In March 1998, I became a Supervisor in the Revenue Requirements division of RP&A,responsible for supervising a group of analysts that oversee the forecasting and recording entriesassociated with all CPUC regulatory mechanisms. In December 2001, I was promoted to theposition of manager in the Revenue Requirements division of RP&A. In August 2006, I waspromoted to my current position as Manager of Revenue Requirements. I have previouslytestified before the California Public Utilities Commission.Q. What is the purpose of your testimony in this proceeding?A-9

123456789101112A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-10, Volume1, entitled Results of Operations – Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking, as identified in the Table of Contents thereto.Q. Was this material prepared by you or under your supervision?A. Yes, it was.Q. Insofar as this material is factual in nature, do you believe it to be correct?A. Yes, I do.Q. Insofar as this material is in the nature of opinion or judgment, does it represent your bestjudgment?A. Yes, it does.Q. Does this conclude your qualifications and prepared testimony?A. Yes, it does.A-10

123456789101112131415161718192021222324252627SOUTHERN CALIFORNIA EDISON COMPANYQUALIFICATIONS AND PREPARED TESTIMONYOF ALAN D. VARVISQ. Please state your name and business address for the record.A. My name is Alan D. Varvis, and my business address is 2244 Walnut Grove Avenue, Rosemead,California 91770.Q. Briefly describe your present responsibilities at the Southern California Edison Company.A. I am a Manager in the Transmission & Distribution Business Unit (TDBU), responsible for thecoordination and reporting of TDBU operation and maintenance (O&M), other operating revenue(OOR), and Capital expenditure budgets. In this capacity, I am responsible for the business unitlevel oversight and coordination of building, reporting, and forecasting TDBU O&M, OOR, andCapital budgets. In addition, I am responsible for overseeing and preparing the cost separation ofO&M, Capital, and Other Operating Revenue (OOR) between FERC and CPUC jurisdictions.Q. Briefly describe your educational and professional background.A. I received my Bachelor of Science degree in Business Administration, with an emphasis inAccounting, from California State Polytechnic University, Pomona in 1994, and a Masters ofBusiness Administration from California State Polytechnic University, Pomona in 2001. I joinedthe Southern California Edison Transmission/Substation Division in 1990 as a Business Trainee.From 1990 to 1995, I was a Budgets & Accounting Analyst in the Transmission/SubstationDivision. In 1995 I was promoted to Material & Accounting Supervisor and served in thatcapacity from 1995 to 1996. In 1996, I was promoted to a Supervisor position overseeingbusiness unit level budget development and reporting in what was then the Power Grid BusinessUnit. In 2003, I became a Manager in the Transmission and Distribution Business Unitresponsible for budget coordination and regulatory support.Q. Have you previously testified before the CPUC?A. Yes. I testified before the CPUC in SCE’s 2006 and 2009 general rate case.Q. What is the purpose of your testimony in this proceeding?A-11

123456789101112A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-10, Volume1, entitled Results of Operations - Requested Revenue Requirements, Ratemaking, Sales Forecast,OOR, Cost Escalation, Post-Test Year Ratemaking, as identified in the Table of Contents thereto.Q. Was this material prepared by you or under your supervision?A. Yes, it was.Q. Insofar as this material is factual in nature, do you believe it to be correct?A. Yes, I do.Q. Insofar as this material is in the nature of opinion or judgment, does it represent your bestjudgment?A. Yes, it does.Q. Does this conclude your qualifications and prepared testimony?A. Yes, it does.A-12

Appendix BProductivity Gains Offset O&M Cost Increases

This appendix explains how limiting recovery of O&M cost increases to only escalation increases resultsin an implicit expectation that productivity gains will offset O&M cost increases from other sources.Let O&M cost be represented by a cost function C(p, q, s, t), where p is an input price index, qequals energy demand, s equals the number of customers served, and t equals time. Further assume thatthe cost function C can be written as the product of the input price index and “real cost” C*:*C(p,q,s,t)= p(t)⋅C( q,s,t)(1)Differentiating equation (1) with respect to t yields:*dC ( p,q,s,t)dp(t)*dC ( q,s,t)= ⋅C( q,s,t)+ p(t)⋅(2)dt dtdtMultiplying the first right-hand term by p(t)/p(t) yields:*dC ( p,q,s,t)1 dp(t)*dC ( q,s,t)= ⋅ p(t)⋅C( q,s,t)+ p(t)⋅(3)dt p(t)dtdtSubstituting equation (1) into equation (3), equation (3) can be rearranged to produce:*dC ( p,q,s,t)⎡ 1 dp(t)⎤dC ( q,s,t)= C(p,q,s,t)p(t)dt⎢+ ⋅p(t)dt⎥ ⋅(4)⎣ ⎦dtThe first right-hand term of equation (4) is simply the rate of input price escalation (in brackets)multiplied by O&M cost, hence this term is equal to the O&M cost increase that is authorized by theCommission’s attrition and post test year ratemaking mechanisms. Thus under standard Commissionratemaking, the second right-hand term of equation (4) must equal zero because no revenue requirementincrease is provided to offset cost increases represented by this term. Thus,And for any non-zero p(t),*dC ( q,s,t)p ( t)⋅ = 0(5)dt*dC ( q,s,t)= 0(6)dtEquation (6) simply shows that under standard Commission attrition and post test yearratemaking, there is no revenue increase authorized for increases in “real cost.” But if demand andcustomers are changing over time (so that demand q and customers s are both functions of time), then wecan totally differentiate equation (6) to produce:**∂C( q,s,t)dq ∂C( q,s,t)+∂qdt ∂sRearranging terms in equation (7) produces:dsdt∂C+*( q,s,t)= 0∂t(7)B-1

***∂C ( q,s,t)⎡∂C( q,s,t)dq ∂C( q,s,t)ds ⎤= −⎢+⎥ (8)∂t⎣ ∂qdt ∂sdt ⎦The left-hand side of equation (8) is the rate of change in O&M productivity over time, while the righthandside is the change in real O&M costs from customer and usage growth. Thus, equation (8)demonstrates that increased O&M costs from customer and usage growth are assumed to be offset byproductivity gains that will be achieved during the post test year period.B-2

Appendix CEconomic Benefits of Proposed Capital Expenditures by the Southern California EdisonCompany

Economic Impacts of ProposedCapital Expenditures by the SouthernCalifornia Edison Company inCaliforniaPrepared by IHS Global InsightU.S. Regional Services800 Baldwin TowerEddystone, PA 19022C-1

Impacts of Proposed Capital Expenditures by the SouthernCalifornia Edison CompanyIntroductionThe purpose of this analysis is to estimate the impacts of proposed capital expenditures by theSouthern California Edison Company (SCE) on the California economy over a five-year periodfrom 2010 through 2014. The expenditures proposed by SCE will be predominantly forimprovements to its existing electric generating facilities and to its transmission and distribution(T&D) systems, but will also include the purchase of new computer software and hardware, theconstruction of new buildings and renovations to existing ones, and the purchase of servicessuch as security and telecommunications.Under the SCE proposal, annual capital spending would range between $2,922.07 million and$3,083.19 million during the five-year period. SCE's proposed expenditure has sizableeconomic impacts on employment, output, value added, and wages. On average, 12,760 jobsare created per year. Furthermore, these jobs are skilled and high paying, providing a averagecompensation of more than $77,000 per employee and producing high value added of about$223,000 per employee.Study AreaTo assess the economic impacts of the SCE capital expenditure, IHS Global Insight defined itsstudy area as the entire state of California. While SCE service area does not include the entirestate, the economic activity generated by the plant will undoubtedly have significant impactsoutside of the service area. By looking at the entire state, we are capturing employees who arecommuting into the service area, and other backward linkages occurring throughout Californiathat are associated with the expenditures.Most of the labor and material inputs needed for the capital expenditures will be obtained, andlikely manufactured in, California, while the electric energy production and distributionmaintained by these improvements would be consumed by residents, businesses, andgovernments located within the service area. California is a very large economy; its 2008 grossstate product of $1,846.76 billion makes it about the eighth largest economy in the world,similar in size to Russia. It is the nation's largest state, containing 12% of the population and13% of gross domestic product. Due to its heavy mix of high-paying service sector jobs,median household income is almost $60,000, or about 15% higher than the national average.IHS Global Insight used the IMPLAN input/output (I/O) model to estimate the total economicimpacts of the capital spending because its high level of sector detail allowed the final demandchanges to be assigned to the appropriate economic sectors. An I/O model such as IMPLANprovides for an accounting of the effects that initial direct spending in one industry has on othersectors through the inter-industry relationships in the economy. IMPLAN contains a set ofmultipliers that produce estimates of the total regional increases in output, value added,employment, and income produced by direct spending. IMPLAN uses national inter-industrypurchasing relationships, adjusted for the structure of the regional economy through the use ofregional purchase coefficients, to derive a set of sector-specific multipliers that are unique tothe regional economy being analyzed. The multipliers are used to derive indirect and inducedeffects, which are then added to the direct effects to obtain the total change in regionaleconomic activity. The sizes of the multipliers are determined by the production functions in theC-2

affected final demand sectors, or on the number and types of industries that supply inputs tothe directly affected sectors. The construction of new generation, transmission, and distributionassets with a high output value per worker generally has a high economic multiplier effectbecause of the large value of inputs that are purchased from within the region.The key assumption in this type of economic impact study is the selection of the sectors wherethe final demand changes will occur, in the case of new spending for generation, transmission,and distribution assets. The capital spending for the generation, transmission, and distributionassets were assigned to IMPLAN's power generation and supply final demand sector. Thespending for general assets was assigned as appropriate to other IMPLAN sectors inaccordance with NAICS classification.Measurement of Economic ImpactsSCE's proposed expenditure affects a large number of sectors in the California economy. Inparticular, most of the activities create direct, indirect, and induced demand for labor leading toa high employment multiplier. The proposed spending in various sectors will require largeamounts of expensive, non-labor inputs such as steel, machinery, and equipment, most ofwhich can be purchased from within the study area, thus indirectly supporting employment inthose activities. The backward linkages for a producing firm in a regional economy consist ofthe other industries from which it buys the inputs needed to make the goods and services itsells.When a direct increase in regional spending occurs, there are two types of economic impactsgenerated through backward linkages that are considered by models such as IMPLAN.Indirect effects are generated when a business that receives an initial, direct increase inspending (e.g., a construction firm that is awarded a contract from SCE to constructnew generation, transmission, or distribution assets) purchases additional inputs fromtheir suppliers located in the region.Induced effects are produced by the increase in local spending of disposable income bythe newly hired workers, including both the new direct workers hired by firms receivingthe initial changes in final demand (e.g., the new construction workers) and by newworkers in the supplying industries (e.g., firms who sell concrete or steel to thecontractor and who, in turn, have to hire new workers to meet the increased demand).The higher the share of inputs that can be bought from suppliers located in the regionaleconomy, the more complete the backward linkages, which will result in larger indirect andinduced effects and higher economic multipliers. This is especially true for investments intransmission, generation, and distribution assets that require a high value of non-labor inputsper unit of output. By contrast, the expenditures for the general assets will have a loweremployment multiplier, as they require fewer inputs to be purchased from within the study area.Finally, when evaluating the regional economic impacts of a project, it is important toemphasize that the changes in all the primary measures of regional economic activity shouldbe considered. In other words, changes in levels of output, value added, and income should beexamined along with changes in employment.Construction produces temporary increases in regional economic activity that decline onceconstruction activity ceases; therefore, we performed five separate IMPLAN analyses for eachcase in order to compare the temporary increases in regional economic activity. According toSCE, the proposed capital expenditures will be made during the year for which they areC-3

scheduled. SCE provided IHS Global Insight with the detailed, annual capital expenditureestimates during the five-year period in current 2010 dollars.Proposed Spending PlanWe have aggregated detailed sectoral investment into four broader categories: general,distribution, generation, and transmission. The total proposed expenditure is allocated todifferent classes of SCE's business, in a pattern that changes over time.SCE plans to invest close to $15 billion from 2010 to 2014, averaging about $3 billion per year.General spending is highest in 2010, the first year of this plan. Investment in distributionaverages almost half of all investment through the five-year period, while general investmentaccounts for a quarter.Proposed Annual Capital Expenditures by Asset ClassExpenditure by Asset Class ($ Million)Asset Class 2010 2011 2012 2013 2014 5-Year TotalGeneral $ 701.61 $ 725.84 $ 825.69 $ 738.74 $ 727.78 $ 3,719.66Distribution $ 1,394.87 $ 1,447.93 $ 1,409.50 $ 1,374.68 $ 1,468.47 $ 7,095.44Generation $ 755.22 $ 525.04 $ 522.71 $ 543.67 $ 470.42 $ 2,817.06Transmission $ 231.49 $ 223.27 $ 280.61 $ 271.86 $ 304.88 $ 1,312.10Total $ 3,083.19 $ 2,922.07 $ 3,038.50 $ 2,928.96 $ 2,971.54 $ 14,944.26Expenditure Shares by Asset ClassAsset Class 2010 2011 2012 2013 2014 5-Year Avg.General 22.8% 24.8% 27.2% 25.2% 24.5% 24.9%Distribution 45.2% 49.6% 46.4% 46.9% 49.4% 47.5%Generation 24.5% 18.0% 17.2% 18.6% 15.8% 18.9%Transmission 7.5% 7.6% 9.2% 9.3% 10.3% 8.8%A breakdown of proposed expenditures by IMPLAN sectors shows how these expendituresaffect the California economy. Investment in each of these sectors is distributed over the entireeconomy due to backward linkages. Each sector has its own strength in terms of creating animpact on the economy. While spending within the power generation and supply sectorremains prominent throughout the five-year period, the yearly distributional changes will affectthe total economic impacts from SCE’s proposed expenditures.C-4

Distribution of SCE's Proposed Expenditure (%)Sectors 2010 2011 2012 2013 2014Power Generation and Supply 77.2% 75.2% 72.8% 74.7% 74.3%Manufacturing and Industrial Buildings 2.8% 5.2% 3.6% 4.4% 4.0%Non-Residential Maintenance & Repair 4.1% 1.9% 3.4% 2.6% 3.7%Other New Construction 0.3% 0.7% 1.2% 1.1% 0.9%Electronic Computer Manufacturing 3.1% 4.3% 4.7% 3.5% 2.9%Furniture and home Furnishing Stores 0.2% 0.5% 0.7% 0.6% 0.7%Telecommunications 2.3% 3.4% 3.7% 3.0% 3.8%Real Estates 0.0% 0.0% 0.0% 1.1% 1.5%Architectural & Engineering Services 0.3% 0.4% 0.4% 0.4% 0.4%Custom Computer Programming Services 9.0% 7.3% 8.4% 7.4% 6.0%Investigation & Security Services 0.5% 1.1% 1.1% 1.0% 0.6%State and Local Non-Education 0.2% 0.1% 0.1% 0.2% 1.3%Total Capital Expenditure 100.0% 100.0% 100.0% 100.0% 100.0%Estimated ImpactsAnnual capital spending under the SCE proposal will generate temporary increases in studyareaemployment, averaging 12,760 person-years of employment on a full-time equivalentbasis during 2010–14. The increase in employment is expressed in person-years, so that onejob equals one person-year of employment. The number of jobs created, additional valueadded, and additional wages generated in the economy due to SCE's proposed expenditureare significant in absolute magnitude. Every $1 million of proposed SCE expenditure createsmore than four jobs in the California economy. The employment multiplier is above 2.0,meaning that for each direct job created by SCE's proposed expenditures, indirect and inducedimpacts will produce more than one additional job in the study area. To the extent that SCE’scapital expenditures continue beyond the study period, the increases in employment, output,value added, income, and taxes will also continue.The impacts on output, value added, and wages are notable. For the California economy as awhole, average annual wages in 2010 range from $55,000 to $58,000, and gross state productper employee is valued at about $136,000. In comparison, the SCE expenditure plangenerates jobs that pay more than $77,000 on average and produce $223,000 of value addedper employee, substantially outpacing the state figures. Thus, SCE’s expenditure plan createshigh-quality jobs.C-5

SEC Electricity Price Forecast(Cents Per kWh, 2010$)Base Scenario2010 2011 2012 2013 2014Residential 15.1 16.6 16.9 17.3 17.6Commercial 14.7 16.2 16.5 16.8 17.2Industrial 11.7 12.8 13.1 13.4 13.6System Ave. 14.3 15.7 16.0 16.3 16.7Alternative Scenario with Higher Rates2010 2011 2012 2013 2014Residential 15.1 16.9 18.1 18.8 19.4Commercial 14.7 16.5 17.6 18.3 19.0Industrial 11.7 13.1 14.0 14.6 15.1System Ave. 14.3 16.0 17.1 17.8 18.4Difference2010 2011 2012 2013 2014System Ave. 0.0% 1.9% 6.8% 9.0% 10.4%It is also important to note that the results here are conservative because we have accountedfor the negative impacts of a possible rate increase. SCE provided two electricity priceforecasts: a base forecast and an alternative incorporating possible rate increases. We usedthe difference between the two scenarios for each year to calculate the loss of disposableincome that would occur due to the higher rates. Since electricity demand is inelastic, thehigher residential rates will act similar to a tax, lowering disposable household income amongthe residents in the service area. The difference between the scenarios becomes moresignificant over the forecast period, which is reflected in the results.C-6

Economic Impacts of the SCE Proposal(Millions of 2010$)2010 2011 2012 2013 2014 2010 through 2014AnnualTotal AverageTotal Expenditure $ 3,083.19 $ 2,922.07 $ 3,038.50 $ 2,928.96 $ 2,971.54 $ 14,944.26 $ 2,988.85EmploymentDirect 5,573 5,152 5,027 4,334 4,184 24,271 4,854Total 14,171 13,234 13,249 11,719 11,427 63,801 12,760Multiplier 2.54 2.57 2.64 2.70 2.73 2.64OutputDirect $ 3,079.35 $ 2,872.74 $ 2,878.65 $ 2,718.57 $ 2,722.08 $ 14,271.38 $ 2,854.28Total $ 4,717.12 $ 4,421.20 $ 4,451.81 $ 4,131.29 $ 4,108.35 $ 21,829.78 $ 4,365.96Multiplier 1.53 1.54 1.55 1.52 1.51 1.53Value AddedDirect $ 2,157.75 $ 1,996.97 $ 2,008.33 $ 1,919.87 $ 1,935.39 $ 10,018.30 $ 2,003.66Total $ 3,080.69 $ 2,867.20 $ 2,891.97 $ 2,713.65 $ 2,713.99 $ 14,267.50 $ 2,853.50Multiplier 1.43 1.44 1.44 1.41 1.40 1.42Labor IncomeEmployee Compensation $ 1,073.67 $ 1,002.23 $ 1,028.56 $ 915.12 $ 901.97 $ 4,921.55 $ 984.31Proprietor's Income $ 366.04 $ 336.07 $ 343.85 $ 326.45 $ 323.19 $ 1,695.60 $ 339.12Total Earnings $ 1,439.72 $ 1,338.29 $ 1,372.41 $ 1,241.58 $ 1,225.16 $ 6,617.15 $ 1,323.43State and Local TaxesPersonal Income taxes $ 48.34 $ 45.20 $ 46.40 $ 41.95 $ 41.33 $ 223.23 $ 44.65Sales Taxes $ 155.44 $ 143.76 $ 143.40 $ 137.59 $ 138.12 $ 718.31 $ 143.66Corporate Income Taxes $ 27.13 $ 25.31 $ 25.13 $ 24.41 $ 24.72 $ 126.71 $ 25.34Other Taxes $ 31.91 $ 29.52 $ 29.45 $ 28.24 $ 28.34 $ 147.46 $ 29.49Total State Taxes $ 262.82 $ 243.79 $ 244.39 $ 232.19 $ 232.52 $ 1,215.70 $ 243.14ConclusionThe expenditure plan proposed by SCE clearly has a positive impact on the Californiaeconomy. It will create 12,760 new jobs and produce more than $4,300 million worth of outputper year during the 2010–14 period. In line with impacts on employment and output, it also hassizable positive impacts on value added, wages, and tax revenues. The computations showthat every $1 million of capital spending by SCE creates more than four jobs in the SouthernCalifornia economy. These jobs are highly desirable, with average employee compensation ofalmost $77,000 per year and value added of $223,000 per year per employee. We haveexplicitly incorporated the offsetting effects of higher electricity rates in our methodology, so weobserve that the overall positive impacts of expenditure proposals remain significant even inpresence of increased electricity rates. The impacts reported in this study are conservativebecause they are net of negative impacts of electricity price increases based on alternativescenario with higher rates. Nonetheless, they are significant positive impacts for the Californiaeconomy as a whole.C-7

Appendix DEconomic Development Impact Analysis, SCE Capital Investment Program

Appendix E

1234567891011121314151617181920212223242526272829303132A.SCE Has A Rigorous Process For Approving And Managing Utility O&M BudgetsSCE has an extensive process in place for approving and managing utility O&M expenses. Asdescribed below, during the Annual Planning Process, each of the Business Units/Departments formulatesits internal O&M budgets utilizing various checks and balances within their respective organization. Afterthe organizations arrive at their individual budget requests these estimates are brought to the corporatelevel for further review and approval.3.Development Of O&M BudgetsThe operating budget, which is used to monitor actual expenses and income, is an itemizedsummary of projected expenditures and income for the year grouped by Business Units and detailed bycost centers. The operating budget is used by senior management to control the prudent use of companyresources, and serves as the basis for earnings and other financial projections.The operating budget is set at the beginning of the year and, except for specific exceptions,is not changed. Specific exceptions would include: if business opportunities for realizing Other OperatingRevenue (OOR) are approved; reorganizations; or if changes to the capital budget involve related changesto the operating budget that are specifically approved. The operating budget process includes four steps:(1) Finalize Internal Market Mechanism (IMM) Agreements, (2) Develop O&M and OOR Budgets, (3)Budget Meetings with Senior Management and Corporate Budgets, and (4) Review Final Budgets.SCE operating units rely on internal company service providers, such as InformationTechnology and Supply Chain Management. The IMM is designed to: (a) provide accountability forproduct/service supply and demand, and (b) encourage and facilitate strong customer/supplierpartnerships. IMM agreements, which specify internal “prices” and service levels, are developed betweenservice providers and internal “customers.” Once IMM agreements have been finalized between serviceproviders and internal customers, they become a component of the O&M budget of both organizations.The operating budget is developed within each organization by estimating labor, material,contractor services and other direct charges and adding any allocations and/or overheads that theorganization expects to receive.The OOR budget represents revenues from sources other than electricity sales. It isdeveloped by reviewing ongoing OOR activities that are budgeted each year, and adjusting the previousyear’s budget accordingly. New OOR activities are subject to the Capital Review Team (CRT) process,and if approved, the OOR budget is revised.When the O&M and OOR budgets have been developed, a series of meetings are heldbetween Senior Management, Corporate Budgets and each Business Unit. Budgets are reviewed againstE-1

12corporate financial targets. If proposed spending exceeds corporate targets, an iterative process begins,which may result in changes to either the corporate targets and/or Business Unit budgets.E-2