Energy Resource Recovery Account (ERRA) 2017 Forecast of Operations

Transcription

1 Application No.: A Exhibit No.: SCE-1 Witnesses: S. DiBernardo S. Liu E. Martinez T. Cameron E. Lavik R. Thomas M. Palmstrom T. Frontino S. Lelewer K. Seeto R. Hite M. Sheriff D. Hopper D. Wong (U -E) Energy Resource Recovery Account (ERRA) 01 Forecast of Operations PUBLIC VERSION Before the Public Utilities Commission of the State of California Rosemead, California May, 01

2 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents Section Page Witness I. INTRODUCTION...1 S. DiBernardo II. 01 ERRA FORECAST PROCEEDING REVIEW REQUIREMENT... A. 01 ERRA Forecast Proceeding Revenue Requirement Functionalized ERRA-Related Revenue Requirement... a) b) ERRA-Related Generation Service Revenue Requirement... ERRA-Related Delivery Service Revenue Requirement... III. SCE S BUNDLED ENERGY FORECAST... E. Martinez A. B. C. D. E. F. G. H. I. Retail Sales Forecast Summary... Methodology... Historical Trends... Economic Outlook...1 Weather Assumptions...1 Other Factors Influencing the Forecast...1 Total Retail Sales Forecast by Customer Class...1 Customer Forecast...1 Annual and Monthly Bundled Energy...1 J. Sales Forecast Used for Rate Setting...1 R. Thomas IV. FORECAST ENERGY PRODUCTION AND COSTS FROM SCE S PORTFOLIO OF RESOURCES...0 E. Lavik A. B. Introduction...0 Energy Production Forecast Methodology...0 -i-

3 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness C. D. E. Validation of SCE s Energy Production Forecast Energy and Cost Forecast Summary... SCE s Utility-Owned Generation and Purchased Power Contracts Hydro Facilities... SCE Solar Photovoltaic Generation... CHP and Renewables... a) b) c) Energy Forecast... Payment Forecast...0 Energy and Capacity Prices...0. Utility-Owned Natural Gas Facilities...1 a) SCE Peakers...1 (1) () Background and Production...1 Costs... b) Mountainview Generating Station.... Interutility Contracts Production... M. Palmstrom a) b) c) WAPA/MWD Agreements... Pasadena Corporation Grant Deed... Interutility Contract Resource Costs.... New System Generation Contracts... E. Lavik a) b) Production... Costs Bilateral Contracts Production... -ii-

4 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness a) b) Production... Costs.... Generic and Bilateral RA Contracts... a) Production.... Local Capacity Requirements (LCR) Contracts... a) b) Production... Costs.... Green Tariff Shared Renewables (GTSR) Program... F. Other SCE Resources and Programs... S. Lelewer 1. Nuclear... a) b) Production... Costs...0 (1) () () Introduction...0 Nuclear Fuel Management...0 SONGS Nuclear Fuel Expense...1 (a) Fuel Expense Generation Related...1 (i) Permanent Disposition of Used Fuel...1 (b) Other Costs Non-Generation- Related...1 (i) Interim Storage...1 () PVNGS Nuclear Fuel Expense... -iii-

5 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness (a) Fuel Expense Generation Related... (i) (ii) (iii) (iv) PVNGS Unit 1... PVNGS Unit... PVNGS Unit... Permanent Disposition of Used Fuel... (b) Other Costs Non-Generation- Related... (i) Interim Storage.... Catalina Fuel Costs... R. Hite. Demand Response... D. Hopper G. CAISO Costs and Short-Term Market Activity... E. Lavik 1.. CAISO Costs... Short-Term Market Activity Costs... H. I. Gas Price Sensitivity... Direct GHG Costs... J. Gas Hedging Costs... S. Liu 1.. Transaction Fees... Option Premiums... K. Gas Transportation and Storage... M. Palmstrom 1. Transportation... a) SoCalGas Transportation Agreement for Mountainview...0 -iv-

6 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness b) c) SoCalGas Transportation Agreements for UCSB and CSUSB...0 SoCalGas Transportation Agreements for SCE s Peakers...0 V. FINANCING COSTS...1 T. Cameron A. B. Commission Decisions Regarding Financing Costs and Collateral Costs...1 SCE s Current Short-Term Financings Credit Facilities...1 Collateral Requirements... Fixed Rate Bonds Supporting Fuel Inventories... Commercial Paper... Costs of Collateral Issuance... C. Additional Financial Instruments Supporting Collateral... VI. CARRYING COSTS... A. B. C. Fuel Inventory Carrying Costs... GHG Compliance Carrying Costs... Collateral Carrying Costs... VII. GHG FORECAST COSTS AND REVENUES AND RECONCILIATION... M. Sheriff A. B. Overview Cap-and-Trade Costs and Reconciliation of Prior Period GHG Costs...0 T. Frontino 1. Sources of GHG Costs...1 a) Direct Costs...1 -v-

7 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness (1) () Compliance Costs...1 Procurement Contract Costs... b) Indirect Costs... (1) () QF Contract Costs... Market Purchase Costs.... GHG Emissions Volume Forecast Methodology... a) GHG Emissions Associated with Direct Costs... (1) () GHG Emissions Associated with Compliance Exposure... GHG Emissions Associated with Procurement Contracts... b) GHG Emissions Associated with Indirect Costs... (1) () GHG Emissions Associated with QF Contracts... GHG Emissions Associated with In- State Market Purchases of Electricity... c) Forecast of 01 GHG Emissions Volumes GHG Emissions Price Forecast Methodology... SCE s Forecast 01 GHG Costs... Reconciliation of Prior Period GHG Costs... C. 01 Administrative and Customer Outreach Costs Forecast and Prior Period Reconciliation... M. Sheriff Administrative Costs Forecast Customer Outreach Costs Forecast... -vi-

8 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness. Reconciliation of Prior Period Administrative and Customer Outreach Costs... D. 01 GHG Allowance Revenue Forecast... K. Seeto 1. Amortization and Reconciliation of Prior Period GHG Allowance Revenues... E. 01 Proposed GHG Revenue Return... M. Sheriff Expected December 1, 01 GHGRBA Balance and Prior Period Revenue Return True-Up GHG Cost and Revenue Distribution for EITE and Volumetric Returns Residential California Climate Credit... GHG Costs and Revenues by Rate Schedule... R. Thomas VIII. 01 FORECAST REVENUE REQUIREMENT AND RATEMAKING PROPOSAL... S. DiBernardo A. B. Introduction... Estimated 01 ERRA-Related Generation Service Revenue Requirement Estimated 01 Fuel and Purchased Power Revenue Requirement... a) b) Fuel Expense...1 Purchased Power Expense Estimated December 1, 01 ERRA Balance... Estimated Energy Settlement Refunds and Litigation Costs... C. Estimated 01 ERRA-Related Delivery Service Revenue Requirement... -vii-

9 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations Table Of Contents (Continued) Section Page Witness 1. Estimated New System Generation Net Capacity CAM-Related Cost... a) b) Introduction CAM Eligible Costs..... Estimated December 1, 01 NSGBA Balancing Account... Estimated 01 Spent Nuclear Fuel Revenue Requirement... IX. DIRECT ACCESS, DEPARTING LOAD AND COMMUNITY CHOICE AGGREGATION COST RESPONSIBILITY SURCHARGES... D. Wong A. B. C. Introduction... Total Portfolio Costs Market Price Benchmark...0 Appendix A Estimated December 1, 01 Balancing Account Balances... Appendix B Indifference Rate Calculation... -viii-

10 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations List Of Tables Table Page Table II-1 Estimated 01 ERRA Forecast Revenue Requirement Changes ($000)... Table II- 01 ERRA Forecast Proceeding Revenue Requirement Changes ($ thousands)... Table III- 01 Bundled Customer Load Forecast (GWh)... Table III- Annual Retail Sales by Customer Class (GWh)...1 Table III- Year-End Customers by Customer Class...1 Table III- Bundled Energy at CAISO (GWh)...1 Table IV- 01 Energy Forecast of the SCE Portfolio (GWh) Confidential... Table IV- 01 Forecast of Fuel and Purchased Power Costs ($000) Confidential... Table IV- 01 Forecast of SCE SPVP Production (GWh)... Table IV- Annual Capacity Factors by Technology...0 Table IV- 01 Forecast of Posted Energy and Capacity Prices...1 Table IV-1 Non-Coincident Contract Capacity Quantities and Expiration Dates for SCE s Major Interutility Contracts... Table IV-1 SCE Entitlement to Hoover Dam Electrical Output for Year 01 Source: Bureau of Reclamation - CRSR /01 Most Probable Inflow... Table IV-1 Projected 01 Forecast Period Nuclear Fuel Expense 1 (Thousands of Dollars SCE s Share)... Table IV-1 Catalina Diesel Fuel 01 Forecast Delivered Diesel Cost (01-01 Recorded)... Table IV-1 01 Forecast Delivered Propane Cost (MTs) (01-01 Recorded)... Table VI-1 Estimate of 01 Carrying Costs ($000)... Table VI-1 Estimated 01 Fuel Inventory Carrying Costs ($000)... -ix-

11 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations List Of Tables (Continued) Table Page Table VI-1 Estimated 01 GHG Compliance Carrying Costs ($000)... Table VI-0 Estimated 01 Procurement Collateral Carrying Costs ($000)... Table VII-1 SCE s Forecast of 01 GHG Emissions Volumes (Metric Tons COe)... Table VII- SCE s Forecast of 01 GHG Costs ($000)... Table VII- Annual GHG Emissions and Associated Costs (Template D-)...0 Table VII- Weighted Average Cost of GHG Compliance Instruments Calculation (Template C-1)... Table VII- Detail of Outreach and Administrative Expenses (Template D-)... Table VII- SCE s 01 Forecast Consignment in ARB Auctions (Metric Tons COe)... Table VII- SCE s Forecast 01 Allowance Revenue ($000)... Table VII- SCE s Recorded/Forecast 01 Allowance Revenue... Table VII- SCE s 01 Proposed GHG Revenue Returns...1 Table VII-0 Annual Allowance Revenue Receipts and Customer Returns (Template D- 1)... Table VII-1 GHG Allowance Revenue Allocation by Class... Table VII- GHG Costs and Revenues by Rate Schedule (Template D-)... Table VII- History of GHG Revenues, Costs, and Emissions Intensity (Template D-)... Table VIII- Estimated 01 ERRA Forecast Proceeding Revenue Requirement ($000)... Table VIII- Estimated 01 Fuel and Purchased Power Revenue Requirement ($000)...0 Table VIII- 01 Estimated Fuel Expense ($000)...1 Table VIII- Estimated 01 Purchased Power Expense ($000)... Table VIII- CAM Applicable Resources... Table VIII- Estimated 01 CAM-Related Revenue Requirement ($000)... Table VIII-0 Estimated 01 Spent Nuclear Fuel Revenue Requirement ($000)... -x-

12 SCE-1C: ERRA Resource Recovery Account (ERRA) 01 Forecast of Operations List Of Figures Figure Page Figure III-1 Total Non-Farm Employment Growth in the Counties Served by SCE First Quarter 00 to First Quarter Figure III- Residential Housing Starts in Counties Served by SCE...1 Figure III- Total Non-Farm Employment Growth in SCE Service Area Actual and Forecast...1 Figure III- Recorded and Forecast Cooling Degree Days...1 Figure III- Average System Electricity Rates, Actual and Forecast...1 -xi-

13 I. INTRODUCTION Southern California Edison Company (SCE or Company) files this annual Energy Resource Recovery Account (ERRA) Forecast application to request the Commission to authorize SCE s 01 ERRA Forecast proceeding revenue requirement in the amount of $.1 billion. The Commission has established this process for the review and approval of SCE s forecast of fuel and purchased power expenses for the purpose of setting rates. 1 The 01 ERRA Proceeding revenue requirement forecast of $.1 billion is supported in the following chapters of this testimony, and is based on SCE s best estimate of such factors as kwh sales and load, natural gas and power prices, and an estimate of the December 1, 01 balancing account balances included in this revenue requirement. The forecast adopted by the Commission in this proceeding does not determine which procurement-related costs are ultimately eligible for cost recovery, as the actual fuel and purchased power costs must be reviewed by the Commission and found eligible for recovery in a subsequent ERRA Review proceeding or Quarterly Compliance Report (QCR) determination. Consistent with past ERRA Forecast applications, SCE will update its 01 ERRA Forecast proceeding revenue requirement forecast in November 01, so that the latest forecast assumptions can be incorporated into SCE s 01 rates. As directed by the Commission s Phase Decision Adopting Standard Procedures for Electric Utilities to File Greenhouse Gas (GHG) Forecast Revenue and Reconciliation (FR&R) Requests (D.1- -0), issued in A et al., dated October 1, 01, the investor-owned utilities (IOUs) are to include their Greenhouse Gas (GHG) revenue and reconciliation requests as an additional chapter or section within the annual ERRA Forecast applications. In this Application, SCE proposes to return a 1 Decision (D.) and D , and as modified by D Pursuant to SCE s 01 ERRA Forecast D.1--0, SCE is including only the ERRA Balancing Account, the Energy Settlements Memorandum Account (ESMA)/Litigation Costs Tracking Account (LCTA) and the New System Generation Balancing Account (NSGBA) forecast year-end 01 balances in the 01 ERRA Forecast revenue requirement. D.1--0, Ordering Paragraph (OP). 1

14 total of $. million in GHG allowance revenues to eligible customers in 01 based on the Commission-adopted methodologies and utilizing GHG revenues and cap-and-trade costs, including administrative and customer outreach costs, as proposed and supported in this testimony. Based on SCE s estimated GHG allowance revenues available for return to eligible customers in 01, residential customers can expect a semi-annual, on-bill California Climate Credit of $.00 in 01. A discussion of SCE s estimated 01 ERRA Forecast proceeding revenue requirement and the resulting rate change are presented in Chapter II, and the remaining chapters of this testimony address the following: Chapter III, SCE s Bundled Energy Forecast Chapter IV, Forecast Energy Production and Costs from SCE s Portfolio of Resources Chapter V, Financing Costs Chapter VI, Carrying Costs Chapter VII, GHG Forecast Costs and Revenues and Reconciliation Chapter VIII, 01 Forecast Revenue Requirement and Ratemaking Issues Chapter IX, Cost Responsibility Surcharges (Direct Access, Departing Load, and Community Choice Aggregation) Appendix A, Estimated December 1, 01 Balancing Account Balances Appendix B, Indifference Rate Calculation D approved an amendment to Rule.1(c) of the Commission s Rules of Practice and Procedure (Title 0, Division 1, of the California Code of Regulations) to require all applications to identify all relevant safety considerations implicated by the application. One of SCE s core values is to assure public and employee safety. As such, the procurement of fuel and purchased power (whether for SCE-owned units, contracted through Power Purchase Agreements, or purchased through CAISO or other power exchanges), inherently assumes that all power providers are fully compliant with laws, rules, regulations and internally-managed controls to assure that their generating facilities are operated and maintained in a safe working condition. Likewise, SCE s management of air emissions costs (i.e., Greenhouse Gas Cap-and-Trade costs and other similar costs), and transmission capacity procurement activities, also assume the counter-parties to these transactions are fully compliant with laws, rules,

15 1 1 1 regulations and internally-managed controls to assure that their facilities are operated and maintained in a safe working condition. The safety performance of the counter-parties involved (once contracted) is not directly related to SCE s activities at issue in this proceeding, which include the forecast for sales and purchases of power, fuel, transmission capacity and air emissions credits and allowances. Nevertheless, these activities do support public and employee safety, as these transactions are an inherent part of assuring a reliable supply of electricity to SCE customers. Costs incurred by SCE to operate and maintain the SCE office and public spaces, shops, warehouses, transmission, distribution, and power plants in a safe condition are reviewed in SCE s GRC Applications. In addition, per D.1-1-0, SCE filed a Safety Model Assessment Proceeding (SMAP) Application to provide Commission staff and other parties with the opportunity to analyze and understand the various models and methodologies that the energy utilities will be using to prioritize safety in their GRC proceedings. This prioritization of safety is to be achieved through the use of models and methodologies to assess the energy utility s risk, and the mitigation measures the energy utility plans to take to reduce and minimize such risks. D.1-1-0, p..

16 II. 01 ERRA FORECAST PROCEEDING REVIEW REQUIREMENT A. 01 ERRA Forecast Proceeding Revenue Requirement As shown in Table II-1, SCE is forecasting an increase of approximately $ million in its 01 ERRA Forecast proceeding revenue requirement as compared to the revenue requirement used to set the rates in effect today. Table II-1 Estimated 01 ERRA Forecast Revenue Requirement Changes ($000) Estimated Line Description 01 Revenue Requirement In Rates 1/ Rev. Req. Change (a) (b) (c) (d) (e) = (c) - (d) 1. Fuel and Purchased Power / $,1,1 $,,0 $ (,). ERRA Balancing Account $ (1,1) $ (,) $,0. Energy Settlements Memorandum Account - Net Amount / $ 0 $ (1,1) $ 1,1. New System Generation Balancing Account $ (,) $ (,0) $,0. SUBTOTAL ERRA-RELATED $,1, $,,00 $,. GHG Cap-and-Trade Costs $ 0, $,01 $ (0,0). GHG Allowance Revenues $ (,) $ (,01) $,. SUBTOTAL GHG-RELATED $ (,) $ (,00) $ (). TOTAL ERRA PROCEEDING REVENUE REQUIREMENT $,1,1 $,,0 $,1 1/ D (01 ERRA Rev Rqmt) implemented January 1, 01 (Advice Letter 1-E-A). / Amounts Include Spent Nuclear Fuel. / Amount reflects 01 forecast ESMA refunds less forecast litigation-related costs in the Litigation Cost Tracking Account (LCTA). In order to estimate the year-end ERRA, ESMA/LCTA and NSGBA balances, SCE has used recorded amounts through March 1, 01, plus a forecast of the activity SCE expects to be recorded from April through December 01. The rates in effect today are based on the revenue requirement approved by D Pursuant to Section III.B. of the adopted 01 ERRA Forecast Settlement Agreement (D.1--0), SCE has the option to file a Tier 1 advice letter to implement, effective on or about the date one year after the Primary Implementation Date of November, 01, a rate change to increase rates by an equal amount of the reduction effective November, 01 of $0 million, because SCE will have fully returned the required net refund to customers within this twelve-month period. This increase would remain in effect until implementation of a final decision in this proceeding.

17 As discussed in more detail below and in Chapter IV, the primary reasons for the decrease in the estimated 01 fuel and purchased power expenses from the amounts included in the 01 Forecast revenue requirement are summarized below: 1. SCE forecasts a natural gas price of $./MMBtu for 01, which is $0. (approximately %) lower than the average gas price included in the 01 ERRA updated forecast;. SCE expects its sales to be lower than it did for the 01 ERRA forecast;. SCE expects lower fuel-related costs from its natural gas-fueled UOG and tolling resources due to lower forecast natural gas prices;. SCE expects lower open market costs due to lower forecast SP-1 forward market power prices; and. SCE expects lower SRAC payments due to lower forecast market prices. 1. Functionalized ERRA-Related Revenue Requirement SCE s ERRA Forecast proceeding revenue requirement is functionalized between generation service and delivery service. The generation service revenue requirement is recovered from only SCE s bundled service customers, while the delivery service revenue requirement is recovered from all customers to whom SCE delivers electricity, which includes Direct Access (DA) and Community Choice Aggregation (CCA) customers. SCE s delivery service revenue requirement also includes the purchased power costs the Commission has deemed to benefit all customers, and is therefore recovered from all customers through a Cost Allocation Mechanism (CAM). The CAM is explained in more detail beginning in Section C.1 of Chapter VIII. As shown on Line No. in Table II- and as discussed above, SCE is forecasting an increase of $ million in its 01 ERRA Forecast proceeding revenue requirement from the revenue requirement used to set rates in effect today. This sum includes an increase of $. million in its generation service requirement from the rates in effect today, as shown on Line No., and an increase of $0. in its delivery service revenue requirement from the rates in effect today, as shown on Line No.. The discussion below compares the forecast 01 ERRA Forecast proceeding revenue requirement with the 01 authorized ERRA Forecast revenue requirement by function.

18 Table II- 01 ERRA Forecast Proceeding Revenue Requirement Changes ($ thousands) Line Estimated 01 Revenue Rev. Req. Description Requirement In Rates 1/ Change (a) (b) (c) (d) (e) = (c) - (d) 1. Generation Service. Fuel and Purchased Power $,,0 $,0, $ (1,). ERRA Balancing Account $ (1,1) $ (,) $,0. Generator Refunds $ 0 $ (1,1) $ 1,1. GHG Cap-and-Trade Costs $ 0, $,01 $ (0,0). TOTAL ERRA PROCEEDING GENERATION SERVICE $,,0 $,0,0 $,. Delivery Service. New System Generation Rate Component:. F&PP New System Generation $, $,0 $,0. NSG Balancing Account $ (,) $ (,0) $,0. Total New System Generation $ 1,0 $, $, 1. Nuclear Decommissioning Rate Component: 1. Spent Nuclear Fuel $,1 $,1 $ (,0) 1. Total Nuclear Decommissioning $,1 $,1 $ (,0) 1. Distribution Rate Component 1. LCR F&PP Distribution $, $ - $, 1. GHG Allowance Revenues $ (,) $ (,01) $, 1. Total Distribution $ (,0) $ (,01) $,01 1. Public Purpose Programs Charge (PPPC) 0. LCR F&PP PPPC $ 1, $, $, 1. Total Distribution $ 1, $, $,. TOTAL ERRA PROCEEDING DELIVERY SERVICE $, $ (,) $ 0,. TOTAL ERRA PROCEEDING REVENUE REQUIREMENT $,1,1 $,,0 $,1 1/ D (01 ERRA Rev Rqmt) implemented January 1, 01 (Advice Letter 1-E-A). 1 a) ERRA-Related Generation Service Revenue Requirement As shown on Line No. in Table II- above, the increase of $. million in SCE s 01 ERRA forecast generation service revenue requirement is due to a $1. million decrease in the fuel and purchased power cost estimates, including GHG Cap-and-Trade costs, as shown on Lines Nos. and of Table II-, netted with an increase of $. million in the generation service revenue requirement as

19 shown on Line No. of Table II- associated with the estimated year-end 01 ERRA balance, and an increase of approximately $1. million associated with net Generator refunds related to the California Energy Crisis settlements approved by the Federal Energy Regulatory Commission (FERC). SCE s forecast year-end 01 ERRA over-collected balance of $1. million primarily reflects the remaining amount to be amortized in rates related to the two-year amortization of the year-end 01 ERRA over-collected balance, as adopted in D b) ERRA-Related Delivery Service Revenue Requirement In addition to the bundled service generation revenue requirement identified in Table II- above, SCE s estimated 01 ERRA Forecast revenue requirement also includes delivery service amounts. As shown on Line No. in Table II- above, the increase of $0. million in SCE s 01 ERRA forecast delivery service revenue requirement is due to an increase in the New System Generation (i.e., CAMrelated) revenue requirement of $.1 million, an increase of $. million associated with SCE s year-end 01 NSGBA balance, a decrease of $.1 million associated with spent nuclear fuel costs, an increase of $1. million associated with Local Capacity Requirement (LCR) contracts and an increase of $.1 million associated with lower GHG allowance revenues to be returned to eligible customers. As supported in Chapter IV, the increase in the New System Generation revenue requirement of $.1 million is primarily driven by SCE holding the dispatch rights for all new generation contracts in 01. SCE discusses the background for recovering these costs through CAM in more detail in Chapter VIII. The GHG allowance revenue forecast is discussed in Chapter VII.

20 III. SCE S BUNDLED ENERGY FORECAST This chapter presents a summary of SCE s forecast of 01 bundled customer energy load in its service area and a brief description of the methodology used to produce the forecast. A brief discussion of the major factors and assumptions that influence the forecast is also presented. A. Retail Sales Forecast Summary SCE developed its bundled customer energy forecast for this ERRA filing based on a retail customer sales forecast that was completed in Q1 01. The retail sales forecast consists of sales to bundled service, DA, and CCA customers measured at the customer meter. Total retail electricity sales in the SCE service area totaled, GWh in 01. For 01 and 01, SCE is predicting sales of,1 GWh and, GWh, respectively. The predicted decrease in sales between 01 and 01 is about negative. percent. The primary drivers of the lower forecast are weather and behind-the-meter solar PV generation. Temperatures as measured by Cooling Degree Days were warmer than normal in 01. Therefore, the transition from an above-normal weather year to a normal weather year assumed in the forecast has a downward impact on predicted sales in 01 relative to recorded sales in 01. In addition, the significant increase (almost 0% from 01 to 01) in SCE s solar PV generation outlook also contributed to the projected decline in sales from 01 to 01. For the ERRA forecast proceeding, the forecast of retail sales is converted to a forecast of bundled service customer sales, and then converted to a forecast of bundled customer energy at the California Independent System Operator (CAISO) interface (i.e., distribution line losses are accounted for). The difference between bundled sales and bundled energy is that bundled sales represents the energy delivered to and measured at the customer meter as it is billed, while bundled energy consists of the energy delivered to the customer meter plus distribution losses as measured during the hour it is consumed. This definition of load is referred to as measured at the CAISO interface. The CAISO interface is where all wholesale energy transactions and settlements take place. Table III- summarizes the steps in converting retail sales to bundled customer energy at the CAISO interface. Retail sales consist of two components: (1) bundled service customer sales and ()

21 DA and CCA sales. Deducting the forecast of DA and CCA sales from total retail sales yields a forecast of bundled service customer sales. For 01, the retail sales forecast of, GWh less of DA sales and of CCA sales yields a forecast of bundled service customer sales of The bundled service customer sales forecast is then multiplied by one plus an average annual distribution loss factor (expressed as a percentage). This procedure produces a bundled service customer energy forecast at the CAISO of in 01. It is the bundled service customer energy at the CAISO interface for which SCE must obtain supply, and this is the forecast that SCE is submitting for the purposes of this proceeding. Table III- 01 Bundled Customer Load Forecast (GWh) Line Description Total Retail Sales (@meter),,1,. Direct Access Sales (@meter). CCA Sales (@meter). Bundled Service Sales (@meter). Bundled Energy at ISO B. Methodology SCE uses econometric models to forecast monthly retail electricity sales (recorded sales as billed, measured at the customer meter) by customer class. Retail sales include final sales to bundled service, DA, and CCA customers within SCE s service area. 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: (1) residential; () commercial; () industrial; () other public authority; () agricultural; () street lighting; and () interdepartment transfers (IDT). Each customer class forecast (with the exception of IDT) is itself the product of two separate forecasts: (1) a forecast of electricity consumption per-customer or per-buildingsquare-feet, and () a forecast of the number of customers or total building square feet. The IDT forecast, which represents a very small percentage of total retail sales, is based upon the average of recorded monthly sales over the most recent 1-month historical period.

22 Econometric models employ statistical techniques to quantify the relationship between electricity consumption and the various economic, demographic, and other factors that are thought to influence electricity consumption. Examples of such variables are weather, electricity rates, billing days, energy efficiency program savings, employment, personal income, and building floor stock. Historical data is used to determine these relationships. The typical estimation procedure used to construct the models is ordinary least squares (OLS). Model-generated forecasts may be modified based on current trends, judgment, and events that are not specifically modeled in the econometric equations. Once a satisfactory statistical relationship is established, SCE uses historical average values of weather (cooling and heating degree days) and billing days to represent typical or normal conditions in future periods. Forecasts of economic drivers such as employment, personal income, and building floor stock, along with the typical weather and billing day variables, are then plugged into the models in order to derive forecast values of electricity consumption per customer. Moody s Analytics and Dodge Data & Analytics are the principal sources of employment, personal income, and floor stock data, both historical and forecast. The forecasts of both residential and non-residential customers are based on econometric models that relate changes in the number of customers to a change in economic activity. For example, in the case of residential customers, population growth is used as the leading economic variable to forecast the number of customers. Changes in the number of small commercial customers are assumed to be influenced by changes in the number of residential customers, while changes in the number of industrial customers are dependent upon changes in manufacturing employment. C. Historical Trends On a recorded basis, SCE s total electricity sales increased at an average annual rate of negative 0. percent per year between 00 and 01. Sales growth has not been consistently negative during this period. Annual sales growth surpassed and percent in 01 and 01, respectively. However, increased sales in these two years were a result of above-average weather. Customer growth has remained positive during the post-recession period of 00 to 01, averaging 0.% annual growth. In

23 01 and 01, annual customer growth reached 0.%, the highest level since 00 but well below the levels reached during the regional housing boom. Since the end of the Great Recession, the Southern California economy has been strengthening and entering into economic expansion, albeit at a slower rate than anticipated, as outlined in Figure III-1. Employment growth peaked in late 01 and early 01 as housing starts lifted from recession-level lows. Year-over-year job growth has slowed since 01 but remains positive. The number of starts rose from 0 to 01 as a result of increasing multifamily construction as demonstrated in Figure III-. Figure III-1 Total Non-Farm Employment Growth in the Counties Served by SCE First Quarter 00 to First Quarter 01 % % % 0% % % % % 00Q1 00Q1 00Q1 00Q1 0Q1 0Q1 01Q1 01Q1 01Q1 01Q1

24 Figure III- Residential Housing Starts in Counties Served by SCE 0,000 0,000 Actual to 01 Forecast 0,000 0,000 0,000 0,000, D. Economic Outlook With the background described above, as of when this forecast was produced in late 01 and early 01, Moody s Analytics was forecasting a strengthening regional expansion in 01 and 01. For example, employment is expected to increase. percent in 01 and. percent in 01 (see Figure III- below). Additionally, housing starts are expected to pick up by 0% in 01 and 0% in 01 from a year earlier. However, housing starts are not expected to return pre-recession levels, as shown in Figure III-. 1

25 Figure III- Total Non-Farm Employment Growth in SCE Service Area Actual and Forecast % % Actual to 01 Forecast % 0% % % % E. Weather Assumptions SCE uses 0-year average temperature conditions as its definition of normal weather. Normal weather conditions are assumed throughout the forecast period. For purposes of model estimation and forecasting, actual and normal temperature data are transformed into cooling degree days (a measure of summer season cooling load) and heating degree days (a measure of winter heating load). As shown in Figure III- below, the SCE service area experienced higher-than-normal cooling degree days from 01 to 01. Because the forecast for 01 and beyond assumes normal weather, a slowing trend is automatically built into the forecast for 01 as forecast electricity sales transition from 01, a year of warmer-than-normal summer weather conditions, to forecast normal summer weather conditions in 01 and 01. 1

26 Figure III- Recorded and Forecast Cooling Degree Days % % % 0% 0% 0% 0% 0% 0% F. Other Factors Influencing the Forecast Other factors influencing the growth trend in total retail sales during the forecast period are electricity rates, energy savings from SCE s energy efficiency programs, and self-generation, such as residential rooftop solar installations and behind-the-meter combined-heat-and-power generation. SCE s average electricity rate was relatively constant in current dollars between 00 and 0, and increased in 01, 01, and 01. Rates declined in 01 and will do so again in 01, and at the time the forecast was prepared, the expectation was that rates would be increasing slightly in 01. Historical and forecast system average rates are shown in Figure III-. All other things being equal, higher electric rates reduce average electricity use per customer. 1

27 Figure III- Average System Electricity Rates, Actual and Forecast Actual to 01 Forecast Energy efficiency (EE) savings represent electricity consumption that would have taken place in the absence of specific utility-funded programs. Therefore, the forecast of total retail sales in 01 and 01 would have been higher in the absence of these programs. SCE treats customer self-generation from thermal and solar (photovoltaic) sources in a similar manner in its forecast. SCE reflects some EE trends in the econometric estimation of kwh consumption per customer. Additionally, anticipated EE savings exceeding historical norms are deducted after-the-fact on an incremental basis as needed. G. Total Retail Sales Forecast by Customer Class Table III- below presents SCE s forecast of total electricity sales by customer class. The table shows actual recorded sales in 01 and forecast numbers for 01 and 01. The projected average annual growth in total retail sales is negative. percent in 01 and negative.0 percent in 01 relative to recorded retail sales in 01. 1

28 Table III- Annual Retail Sales by Customer Class (GWh) Line Customer Class 01 01* 01* 1. Residential 0,0,0,. Commercial, 1,0 1,. Industrial,,0,0. Other**,,,0. Total Retail Sales,,1, *Forecast **Includes Public Authorities, Agriculture, and Street Lighting Sales 1 H. Customer Forecast Table III- shows SCE s forecast of total electricity customers. SCE expects the number of customers to increase 0. percent in 01 and 0. percent in 01. As discussed above, customer growth is closely tied to activity in the residential construction sector, but usually with a lag of to 1 months. In other words, a change in the number of new customers is typically a result of a change in the number of housing starts that occurred to 1 months earlier. As housing starts continue to increase, SCE expects customer growth to increase in 01 and 01. Table III- Year-End Customers by Customer Class Line Customer Class 01 01* 01* 1. Residential,,,0,1,1,. Commercial 1,,01,. Industrial,,,1. Other**,,,1. Total Retail Sales,0,0,0,,, *Forecast **Includes Public Authorities, Agriculture, and Street Lighting Sales 1 I. Annual and Monthly Bundled Energy By the end of 01, DA partial reopening to non-residential customers was completed. In the near term, SCE is expecting increases in DA load to be small or remain flat as the DA phase-in has been completed. SCE had its first departing CCA load starting in May 01 in the form of Lancaster Choice Energy (LCE). CCA departing load will be larger in 01 and 01 than the partial-year departure of 1

29 load in 01. SCE has incorporated its best estimate of the migrating CCA load in this application based on information SCE has received. As a result, SCE s bundled sales growth has been reduced relative to retail sales growth. Annual bundled energy at the CAISO delivery point is derived by adjusting the annual bundled sales forecast for distribution losses. Specifically, SCE applies a historical average loss factor to retail sales in the following way: Annual Bundled CAISO = Annual Bundled Sales * DLF, where DLF is the ratio of CAISO settlement quality meter data and bundled sales at the customer meter averaged over the years 0 to 01. Monthly bundled energy at the CAISO delivery point is derived through a series of steps that begins with the annual bundled energy forecast. Annual bundled energy is first allocated to each hour in a year using a set of hourly load shape equations. The load shape equations were created by econometric methods that relate each hour s recorded load to daily average temperature, calendar variables such as day of week, month, holidays, and various time trend variables. Monthly energy is then derived by summing the hourly load associated with each calendar month. Finally, monthly bundled customer peak demand is determined by selecting the maximum hourly load in each calendar month. Table III- presents actual recorded bundled monthly energy at CAISO in 01 and the forecast of monthly bundled energy at CAISO in 01 and 01. SCE agreed with LCE to assume an opt-out rate of 0 percent for municipal accounts and percent for residential and non-residential accounts in a February 1, 01 , in order to reflect a much lower actual opt-rate seen to date than the default 0% for residential and non-municipal non-residential service accounts used in the 01 ERRA Forecast Update. 1

30 Table III- Bundled Energy at CAISO (GWh) Line Month January,. February,. March,1. April,0. May,. June,. July,01. August,. September,00. October,0. November, 1. December, J. Sales Forecast Used for Rate Setting SCE proposes a revision in the type of sales forecast used for final rate setting. Currently SCE uses the official corporate sales forecast, which is an estimate of the amount of energy SCE expects to actually deliver over the course of the forecast year. However, in recent years the influx of rooftop solar generation has led to a condition where delivered energy (in kwhs) differs from the kwhs SCE actually bills for. This difference is due to the Commission s policy of netting under the current Net Energy Metering (NEM) structure. Left uncorrected, the difference between delivered and billed kwh will lead to revenue deficiencies (all other things being equal), which then shifts the responsibility for the revenue shortfall to all rate groups, including those with little to no NEM participation. The proposed revision modifies SCE s rate setting methodology so that retail rate levels are set in a manner that more closely recovers the authorized revenue requirement, and reduces the cost shift between rate groups. In ERRA proceedings, SCE s retail rates are calculated by allocating the authorized retail revenue requirement to each Rate Group through a System Average Percent Change (SAPC) methodology. The SAPC methodology adjusts existing rate levels up or down through a scaling process, where the scaling factors for each function include the effect of adjustments to revenue requirements and delivered forecasted sales. 1

31 Since 1, SCE s retail tariffs have included the NEM Program. This Program allows certain retail customers to net kwh amounts of surplus energy exported against amounts delivered to the customer over the customer s monthly billing period, and to further net bills over an annual period. In the recent NEM Successor Tariff Decision, the CPUC established a successor NEM tariff that includes no cap on participation, as well as the elimination of the 1.0 megawatt cap on the size of participating generating facilities. As a result of the current observation in the difference between delivered and billed kwh, and the expansion of the NEM Program, the retail rate design calculations in ERRA proceedings should be modified to explicitly reflect the impacts of the NEM Program. Instead of developing retail rate levels using the corporate sales forecast (which is based on delivered kwhs), the rate levels should reflect the fact that retail charges are not assessed on a portion of the delivered energy as a result of netting under the NEM Program. Thus, the retail rate levels should be based on SCE s kwh deliveries that are expected to result in authorized revenues to SCE (i.e., billed kwhs), and exclude those deliveries that are expected to result in no authorized revenues due to the netting structure of the NEM Program. This will result in an improved rate design in that the actual revenues that SCE expects to receive will be equal to those authorized in each function. SCE s proposed revision will modify the SAPC adjustment methodology by specifying that the sales forecast used to establish new rate levels reflect the expected billed amount of kwh, netted pursuant to the NEM Program, instead of the forecasted delivered energy. Forecasted billed kwh will thus be used to adjust ERRA-related revenues, as well as revenues associated with other functions not specifically proposed in the ERRA proceeding. This change explicitly links the kwh billing determinants to the sales forecast, and results in an SAPC adjustment inclusive of the effect of energy that is offset due to NEM netting. 1

32 IV. FORECAST ENERGY PRODUCTION AND COSTS FROM SCE S PORTFOLIO OF RESOURCES A. Introduction This chapter describes SCE s resource portfolio and the associated forecast costs that SCE proposes to recover in its ERRA balancing account. SCE s resource portfolio is comprised of its utilityowned generation (UOG), which includes nuclear, natural gas, hydroelectric, fuel cells, and renewable generation resources; SCE s purchased power resources, including CHP and renewable resources, interutility contracts, and bilateral contracts; and proxy (i.e., generic) costs from anticipated future solicitations and market purchases. SCE s 01 forecast also includes executed contracts from SCE s Local Capacity Requirements (LCR) solicitations for the Western Los Angeles (LA) Basin and Moorpark regions, as approved in D and proposed in A.1--01, respectively. The decrease in SCE s 01 fuel and purchased power cost forecast can be generally attributed to four major factors. First, SCE expects its sales to be lower than it did for the 01 ERRA forecast. Second, SCE expects lower fuel-related costs from its natural gas-fueled UOG and tolling resources due to lower forecast natural gas prices. Third, SCE expects lower open market costs due to lower forecast SP-1 forward market power prices and increased generation from renewables. Fourth, SCE expects lower SRAC payments due to lower forecast market prices. SCE used $./kw-year as the proxy price to meet Generic Capacity need as outlined in the 01 Estimated Cost of New Renewable and Fossil Generation in California Final Staff Report study issued by the CEC. B. Energy Production Forecast Methodology In this ERRA Forecast application, as in its past forecast applications, SCE forecasts energy production from its portfolio primarily using the Ventyx Planning and Risk (PROSYM) software. The The proxy capacity costs are further discussed in Section IV.E. Ventyx is the current owner of the originally developed Henwood PROSYM tool. Ventyx s Planning and Risk Software is primarily powered by the PROSYM engine. 0

33 Ventyx models are used to: (1) forecast the least-cost dispatch (LCD) of dispatchable resources in SCE s portfolio; () optimize hydro dispatch; and () perform Monte Carlo simulations of forced outage rates of individual units. The simulated dispatch is based on a forecast of power, gas, and GHG prices, physical constraints of each generating unit, and contractual limitations. SCE s forecast methodology economically dispatches resources in a least-cost manner as directed by the Commission, rather than force-dispatching resources to meet SCE s forecast of bundled customer demand. Under the LCD principle, a generating resource or contract is simulated to dispatch if its marginal operating cost is less than the market price of power, while simultaneously observing all operating constraints. 1 For a given hour, the difference between the forecast bundled load and the total forecast economic dispatch of SCE s resource portfolio constitutes SCE s projected open position for the hour. SCE based its 01 power price forecast on the forward power broker quotes for 01 in effect as of February, 01. The -hour flat price as of February, 01, was $./MWh for SCE derived its hourly price forecast by applying on-peak and off-peak hourly price profiles to the respective monthly on-peak and off-peak forward quotes for 01 in effect as of February, 01, 1 such that the simple averages of the hourly on-peak and off-peak forecast prices for a particular month match the forward on-peak and off-peak power prices for that month. SCE updated its existing MRTUbased statistical models to generate hourly price profiles for the SP-1 and NP-1 zones. 1 The Ventyx models were not used to develop forecasts of competitive market power or GHG prices. These prices were developed independently, as discussed in the following paragraphs. The GHG price forecast was incorporated as part of the resource dispatch cost similar to natural gas prices in order to reflect the additional GHG cost for the generation resources that have GHG emissions. 1 Energy- and use-limited hydroelectric and peaking resources are also dispatched pursuant to LCD; this analysis also incorporates opportunity cost principles regarding water and emissions limitations, respectively, to ensure that such units are dispatched during higher-priced hours, when it is most economic to do so. 1 SCE has contracts in NP-1. SCE used relevant prices to forecast the cost of those contracts. 1 SCE used forward prices from the same trading day for power, GHG, and natural gas price forecasts to maintain the consistency of the forward market outlook. 1 The statistical models incorporated historical MRTU data from the CAISO s Integrated Forward Market (IFM). 1

34 SCE used the Intercontinental Exchange s (ICE) settlement price of a 01-vintage GHG allowance as the basis for its 01 GHG price forecast. The ICE settlement price as of February, 01, was $1./MT for 01. This price is assumed to be constant for any GHG emissions produced in Lastly, SCE based its daily natural gas price forecast on monthly NYMEX forward prices at the SoCal Border in effect as of February, 01, plus intrastate transportation charges from Southern California Gas Company (SoCalGas), as applicable. 1 The 1-month average NYMEX forward gas price as of February, 01 was $./MMBtu for 01. Within a given month, SCE assumed that the daily gas price forecast is equal to the monthly forward price. C. Validation of SCE s Energy Production Forecast SCE follows a consistent process to forecast its energy production and costs for the subsequent calendar year, supported by a robust internal validation process. SCE s forecast process is discussed below. The first stage of SCE s forecast process involves developing all forecast inputs. These inputs include, but are not limited to, SCE s forecast of power, gas, and GHG prices; production from UOG resources (nuclear, hydro, gas, fuel cells and renewable facilities); CHP and renewable energy production and costs; gas hedging costs; CAISO costs, etc. These inputs are developed and vetted by various business groups or divisions responsible for each input and then submitted to senior managers in SCE s Power Supply Organizational Unit for further review and approval. Once approved, the forecast inputs are utilized in PROSYM, which is an industry-standard production cost model capable of modeling various types of resources with differing constraints. SCE uses PROSYM to forecast its LCD activities. Once the dispatch results are produced, SCE conducts a 1 In prior years, direct and indirect GHG costs were reviewed in a separate GHG Cost and Revenue Forecast application. Pursuant to D.1--0, they will now be reviewed in this proceeding, and are discussed in further detail in Chapter VII. 1 Not all generating resources in SCE s portfolio utilize transportation service from SoCalGas.

35 thorough validation of the dispatch outcomes by resource. 1 If necessary, SCE will rerun the previous forecast steps if it believes more accurate dispatch results can be realized. Once dispatch results are validated, all energy and cost forecasts are input into SCE s ERRA forecasting tool, an internally-developed, automated software program that aggregates the hourly energy production and cost forecast data. The ERRA forecasting tool produces the ERRA forecast tables included in the following section(s). Prior to inclusion in SCE s ERRA Forecast filing, the forecast tables are reviewed and approved by SCE s senior management. D. 01 Energy and Cost Forecast Summary Because this ERRA application is designed to forecast SCE s energy-related costs that will ultimately be used to establish retail generation rates in 01, a single expected scenario forecast is utilized. All production and residual open position forecasts provided in this section are reflected at the CAISO system interface. To accomplish this, SCE reduced generation production forecasts by the forecast transmission losses and grossed up the forecast retail load by the forecast distribution losses. Table IV- summarizes the monthly forecast production from SCE s portfolio and SCE s open energy positions. Table IV- summarizes the monthly forecast cost of SCE s purchased power resources accounted for in the ERRA balancing account. The remainder of this chapter provides detailed descriptions of the resources and the underlying forecast assumptions. 1 For example, SCE compares its dispatch results against prior ERRA forecasts and reviews any significant discrepancies to ensure that its results are reasonably justified.

36 Table IV- 01 Energy Forecast of the SCE Portfolio (GWh) Confidential

37 Table IV- 01 Forecast of Fuel and Purchased Power Costs ($000) Confidential

38 Table IV- (Continued) 01 Forecast of Fuel and Purchased Power Costs ($000) Confidential

39 E. SCE s Utility-Owned Generation and Purchased Power Contracts 1. Hydro Facilities SCE s hydro resources consist of powerhouses in central and southern California, which provide 1,1 MW of nameplate capacity. SCE s hydro division is organized into two regions, Northern and Eastern. The Northern Division hydro region, also known as the Big Creek Project, is located in central California about 0 miles east of Fresno in the western Sierra Nevada Mountains. Big Creek s nine powerhouses provide 1,01 MW of nameplate capacity. The Eastern Division hydro region consists of SCE s powerhouses located in the eastern and southern Sierra Nevada Mountains, as well as in the San Bernardino and San Gabriel Mountains of southern California. The Eastern Division hydro region s powerhouses provide MW of nameplate capacity. The Big Creek hydro system is a flexible, dispatchable resource, except during the period of spring run-off. During this period, in a normal water year, the generating units typically need to operate near maximum capacity for hours per day to ensure that spill is minimized. For ERRA forecast purposes, SCE optimizes the Big Creek Project by operating at full capacity (when operationally possible) during the highest economic value hours. When Big Creek does not operate at full capacity, it can generally provide ancillary services to the CAISO market. Eastwood powerhouse is a pump-storage unit providing 1. MW of nameplate generating capacity, and is part of the Big Creek Project. The pumpback efficiency is approximately percent, meaning that approximately 1. MWh of pumping energy is required to pump enough water back into the forebay to generate 1 MWh of energy at a later time. Pumpback duration generally varies from two to six hours and consumes approximately MWh per hour. Every three hours of pumpback stores enough water to generate for approximately two hours at 1. MW. Pumpback and generation dispatch for Eastwood are modeled on an hourly basis assuming economic dispatch. To maximize the value of the resource, pumpback normally takes place during off-peak hours when energy prices are lower, and dispatch normally takes place during peak hours when energy prices are higher.

40 1 1 1 SCE s Eastern Division hydro facilities are predominantly run-of-the-river, non-dispatchable resources and their actual MW output varies based on hydrological conditions. As a result, the forecast energy production is largely deterministic. For 01, SCE s forecast of its UOG Hydro production, inclusive of pumpback operations, is shown in Table IV-. This forecast assumes a normal hydrological year for 01, and also incorporates SCE s best estimate of upcoming major planned outages of Big Creek and Eastern Hydro units in 01.. SCE Solar Photovoltaic Generation SCE s Solar Photovoltaic Program (SPVP) is a Commission-approved initiative to install, own, and operate up to 1 MW Direct Current (DC) of utility-owned solar photovoltaic projects on commercial rooftop space and ground-mounts in SCE s service area. 1 SCE estimates that in 01 that its UOG SPVP solar projects will provide a total of approximately 1 MW DC of capacity, primarily (although not exclusively) located in San Bernardino County. These photovoltaic projects generally provide energy during peak usage times. For 01, SCE s forecast of SPVP production, based on the previous year s project capacity factors, is shown in Table IV-. Table IV- 01 Forecast of SCE SPVP Production (GWh) Line Description Jan 1 Feb 1 Mar 1 Apr 1 May 1 Jun 1 Jul 1 Aug 1 Sep 1 Oct 1 Nov 1 Dec 1 Total 1. SCE Owned SPVP Production 1 The Commission originally approved a 00 MW SPVP program, with 0 MW of projects to be UOG and 0 MW to be owned by independent power producers. See D SCE s February 0 Petition for Modification requested the program be modified to include, among other things, a reduction of both the UOG and the Independent Power Producer portions from 0 MW to 1 MW, and the petition was approved on February 1, 01. On July, 01, SCE filed a second Petition for Modification to further reduce the UOG portion of the SPVP from 1 MW to 1 MW, given that 1 MW of ground sites were at risk due to interconnection cost and schedule, and 1 MW of formerly-committed rooftops were no longer viable. SCE proposed that the MW reduction from the UOG SPVP Program be transferred to the Renewable RAM Procurement Program. The Commission approved SCE s petition in D.1-0-0, capping the UOG portion of SPVP at 1 MW. The independent power producer portion of the program maintains its 1 MW program goal.

41 . CHP and Renewables a) Energy Forecast For the 01 Forecast Period, SCE expects 0 of energy deliveries at the CAISO interface as shown in Table IV- from CHP (combined heat and power) and renewable projects. The energy deliveries from cogeneration and renewable projects are effectively must take energy. There are some gas-fired contracts that are dispatched based on market prices. Energy deliveries at the generators meters are forecast to be The projects delivering energy have approximately,1 MW of contract capacity allocated as follows: MW of CHP capacity; , MW of renewable capacity. 1 In addition and not included in the above capacity numbers, SCE has contracted an additional MW of dispatchable capacity through the CHP Program Settlement requests for offers. SCE uses the historical performance of each project to forecast monthly deliveries. During the Forecast Period, the aggregate capacity of new, renewable projects under development, adjusted by their probability of successful development, is approximately 1,0 MW. These new projects ( solar and wind) have not begun producing energy are expected to begin operating during 01 and 01. Because there is no historical performance data for these new projects, forecast energy deliveries are based on contractual expectations, discounted by their expected probabilities of successful development. Table IV- lists the average annual capacity factors for each of the six renewable technologies. These average annual capacity factors are based on expected annual energy and contract capacity for each project aggregated by technology. In addition, for undeveloped projects, both the energy and capacity is weighted by each project s respective probability of successful development. 0 includes generation loss and the Shell Offtake agreement, and excludes 1 GWh allocated to serve Green Tariff customers as a part of the GTSR Program described in Section E.. 1 The contract capacity for a project that is not on-line is weighted by the project s expected commerciallyoperable success rate.

42 Table IV- Annual Capacity Factors by Technology Line Technology Capacity factor 1 Biomass.% CHP.0% Geothermal.% Small Hydro.0% Solar.% Wind.% The energy forecast also includes energy from projects whose contracts are scheduled to expire during, or immediately before, the 01 Forecast Period. SCE assumes that it will re-contract with 0 percent of expired CHP and non-rps-eligible renewable projects that are 0 MW or less. Terminating RPS eligible projects are encouraged to submit bids in renewable solicitations. The total amount of recontracted energy for the forecast period is GWh. For 01, total RPS energy is also adjusted based on the Shell-BPA offtake agreement. Finally, when an expired project signs a new, Commissionapproved contract with SCE, it is counted as an active project. b) Payment Forecast Payments to CHP and renewable projects delivering energy during 01 are forecast to be approximately energy payments of and capacity payments of. The expected monthly energy, energy payments, and capacity payments including re-contracted projects are shown in Table IV-. Total expected payments include $.0 million for the re-contracted projects based on posted avoided costs of energy and capacity. c) Energy and Capacity Prices Energy and capacity prices for each of the CHP and renewable projects are based on the individual project s contract. Many of these projects have contract-specific energy prices. A number of QF projects are paid at the posted avoided cost of energy price. For QF projects with the Standard Offer SCE estimates a cost of from the Shell-Offtake agreement, other out-of-state renewable management costs, and CHP Dispatchable costs. 0

43 Contract, the project s paid capacity price is the firm or as-available avoided capacity price depending on the project s specific dedicated capacity. For older QF projects, many of the projects have capacity prices that are contract-specific. QF projects that are paid at the avoided cost of energy had a number of energy price options from which to choose. These choices were based on the QF Settlement approved by the CPUC in D By the time of the 01 ERRA forecast period, all the SRAC (Short Run Avoided Cost) options will have terminated and SRAC will be based on the average 1-month forward heat rates. The monthly forecast of SRAC energy prices is included in Table IV- below. Table IV- 01 Forecast of Posted Energy and Capacity Prices Finally, forecast curtailments are captured in the 01 ERRA forecast period. SCE anticipates that some amount of energy deliveries from a number of wind and solar projects in the Tehachapi area will be curtailed because of limited transmission availability for the next few years. The impact of curtailed energy deliveries is included in the energy and payment forecasts.. Utility-Owned Natural Gas Facilities a) SCE Peakers (1) Background and Production In the Assigned Commissioner s Ruling (ACR) dated August 1, 00, addressing electric reliability needs in southern California (Rulemaking (R.) and R ), Commission President Peevey ordered SCE to build up to 0 MW of black-start capable, dispatchable generation capacity within its service territory. Four Peaker units with a total capacity of 1 MW began operations in August 00, and the fifth Peaker with a capacity of MW began operation in November 01. SCE included its forecast of UOG peaking unit generation in Table IV-. 1

44 () Costs Effective with the 00 GRC decision, SCE transitioned to GRC-based rate recovery for all capacity and non-fuel variable costs associated with its UOG Peakers. The natural gas cost forecast for these peaking units is included in Table IV-. b) Mountainview Generating Station On July 1, 00, Mountainview Power Company, LLC (MVL), a wholly-owned subsidiary of SCE, transferred ownership of the Mountainview Generating Station (Mountainview) to SCE. The Commission approved the transfer as part of SCE s 00 GRC, in D As a result, Mountainview s capital costs are no longer recovered as purchased power costs through the ERRA, but instead are recovered in SCE s authorized base generation revenue requirement and through base rates. However, Mountainview fuel costs and availability and heat rate incentive payments continue to be recorded in the ERRA balancing account. SCE included its Mountainview generation forecast in Table IV-. The natural gas forecast for Mountainview is included in Table IV-.. Interutility Contracts Production SCE is a party to three major interutility contracts under which it is expected to purchase and/or exchange capacity and associated energy for various periods from January 01 to September 01, except for the City of Pasadena which has no expiration date. These interutility contracts were executed prior to industry restructuring and contain complex terms and conditions that were designed to satisfy the unique needs of SCE and each of the counterparties. The current contracts with Western Area Power Administration (WAPA) and The Metropolitan Water District of Southern California (MWD) expire at the end of September 01. SCE is engaged in discussions with WAPA and MWD for new contracts See SCE s 00 GRC Application, A.0--0, Exhibit SCE-0, Vol., Ch. 1, dated November 00, in which SCE proposed to include the concepts of the PPA incentive mechanisms in the ERRA proceeding. Excluded from this total are SCE s so-called Fringe Service agreements, which provide for small amounts of energy exchanges among neighboring utilities. These include two contracts with the Department of Defense for the Air Force that SCE presented to the Commission in Advice Letters -E and 1-E and contracts associated with retail tariffs.

45 that would have a term start date of October 1, 01. Table IV-1 summarizes these major interutility contracts. Table IV-1 Non-Coincident Contract Capacity Quantities and Expiration Dates for SCE s Major Interutility Contracts The process of forecasting the level of energy deliveries and receipts for interutility contracts with dispatchability (i.e., with WAPA and MWD) is an inherently complex task. SCE is forecasting net interutility contract purchases of 1 GWh in 01. a) WAPA/MWD Agreements SCE has an entitlement of. MW of contingent capacity and 1 GWh of firm energy from the Boulder Canyon Project (Hoover), marketed by WAPA. In addition, SCE s exchange agreement with MWD is projected to allow SCE to integrate MWD s entitlement at Hoover (. MW of contingent capacity and 1, GWh of firm energy) with SCE s own entitlement from Hoover. The combination of SCE s and MWD s entitlements to Hoover provides a total of MW of contingent capacity and 1, GWh of firm energy available to SCE. In addition, SCE receives MWD s entitlement to Parker Dam (0 MW of contingent capacity and 0% of the energy output). In return, SCE provides MWD with (1) exchange energy, at no net cost to SCE, within a twelve-month contract year, () 00 to 00 GWh per year of benefit energy during off-peak hours, and () interchange energy within a month equal to MWD s energy entitlement to Hoover and Parker. MWD must acquire Firm energy is energy obligated from Hoover under the Hoover Power Plant Act. During periods when Hoover is unable to provide energy in amounts equal to the firm energy, WAPA is obligated to provide any deficit, if requested by the purchaser, at a rate equal to WAPA s cost to acquire.

46 additional energy to meet its pumping requirements along the Colorado River Aqueduct that exceed the energy that SCE provides. Due to the lowering of the surface elevation of Lake Mead, which is the forebay to the Hoover power plant, the amount of capacity and firm energy available to SCE and MWD will be reduced from the amounts described in the previous paragraph. For the year 01, the monthly capacity and firm energy available to SCE could range as low as MW and GWh, respectively. The forecast amount of capacity and energy available to SCE out of Hoover is shown in Table IV-1. The Bureau of Reclamation, the owner and operator of Hoover Dam, anticipates a low reservoir elevation through 01, the year when the contract terminates. The reason for the low elevation is due to two major factors: (1) low precipitation since 000 and () surplus water deliveries to California. Historically, California has taken more water from the Colorado River than it is entitled to. In recognition of California agreeing to reduce its excess take from the Colorado River, the Bureau of Reclamation has agreed to declare interim surplus water releases until California can find a substitute for the excess take. California has until 01 to find, develop, and implement means to reduce its excess take from the Colorado River.

47 Table IV-1 SCE Entitlement to Hoover Dam Electrical Output for Year 01 Source: Bureau of Reclamation - CRSR /01 Most Probable Inflow 1 b) Pasadena Corporation Grant Deed On June 0, 1, SCE and the City of Pasadena (Pasadena) entered into the Corporation Grant Deed that transferred ownership of a hydroelectric powerhouse and accompanying parcels of land in Azusa Canyon to Pasadena. In accordance with the exchange provisions of the Corporation Grant Deed, Pasadena delivers to SCE the entire electrical output of the Azusa Powerhouse (nameplate rated at MW). Pasadena then has twelve months from the time of delivery to SCE to request that SCE return a like amount of energy. SCE charges Pasadena for transmission service on the returned energy. If Pasadena does not request the like amount of energy, or any portion thereof, to be returned within this twelve-month period, Pasadena forfeits any subsequent right to the non-returned energy, and the energy is purchased by SCE at a rate of $.0/MWh.