1. 1 CPUC Avoided Cost Workshop Introduction and Overview

2. 2 Efficiency Avoided Cost Background The draft avoided costs were developed by a stakeholder group (August to December 2003) Developed with an open and transparent methodology Participants in five working meetings included CPUC, CEC, four CA IOUs, NRDC, ORA Spreadsheet tools available on internet Only public data sources were used Focus for avoided costs was strictly EE Draft report was released on January 8, 2004

3. 3 Goals of this Workshop The CPUC staff will produce a report on the outcomes of the workshop Document the positions of the parties Include comments previously filed Workshop is an opportunity to clarify existing comments, and add new comments To aid the report, each comment should be as specific as possible, including; Avoided cost issue being addressed Relevant proceedings to which the comment applies Specific comment

4. 4 Structure of the Workshop Summary of Results Presentation Provide a high level introduction or refresher on the efficiency avoided cost project Methodology Discussions in the Three-day Workshop Summarize methodology to answer as many questions and comments submitted as possible Discussion of appropriateness of avoided costs to particular applications

5. 5 Some of the issues to be addressed during this workshop… Generation Thin markets Hedge value Capacity and energy separation Market referents and generation cost shape Emission Costs Double counting? Treatment of unpriced emissions T&D Reliability of load reductions affect the value Is time and location worth the effort? Market Price Effect Does it exist, and should it be recognized?

6. 6 Summary of Energy Efficiency Avoided Cost Values

7. 7 Avoided Cost Principles Use a flexible and transparent method that can be updated or modified for other applications Use publicly available data Use forward-looking market data whenever possible

8. 8 Dimensions of the Analysis Avoided Cost StreamTime DimensionArea Dimension Avoided Electricity Generation HourlyUtility specific Avoided Electric Transmission and Distribution HourlyUtility, planning area and climate zone specific Avoided Natural Gas Procurement MonthlyUtility specific Avoided Natural Gas Transportation and Delivery MonthlyUtility specific Environmental Externality Adder Annual value, applied by hour according to implied heat rate System-wide (uniform across state) Reliability AdderAnnual valueSystem-wide (uniform across state) Price Elasticity of Demand Adder TOU period (on- vs. off- peak) by month System-wide (uniform across state)

9. 9 Hourly Electric Cost Structure

10. 10 Formulation of Avoided Cost Electric Period 1 (2004-2008) Platt’s / NYMEX Period 2 Transition Period 3 (2008-2023) LRMC 1 + Ancillary Services (A/S) Period 1 (2004-2008) NYMEX Period 2 Transition Period 3 (2008-2023) Long-run Forecast 1 + LUAF + Compression Commodity Natural Gas Commodity Market Multiplier 1 + Energy Losses T&D Costs  (1 + Peak Losses ) Environment  (1+ Energy Losses) T&D Costs Environment    + + + +  “NYMEX” = “New York Mercantile Exchange” “LRMC “ = “Long-run marginal cost” = all-in cost of a combined cycle gas turbine (CCGT) “LUAF “ = “Loss and unaccounted for”

11. 11 Generation Marginal Cost Forecast Working Group Framework 2004200620082023 Electric Forward data Gas Futures data Long Run Marginal Cost (CCGT) Market Data (Short Term) Long Run Proxy (Long Term)

12. 12 Ancillary Services (A/S) Costs Average of A/S costs as percent of total energy costs, during non-crisis period (8/99-5/00, 8/01-7/03): 2.84% Apply 2.84% to shaped hourly energy price 2004: 2.84% * $45.57/MWh = $1.29/MWh of load 2005: 2.84% * $46.65/MWh = $1.32/MWh of load 2013: 2.84% * $60.00/MWh = $1.70/MWh of load

13. 13 Market Elasticity Estimates On-Peak: 8 am to 6 pm, Working Weekdays, May to October Off-Peak: All Other Hours “RNS” = “Residual net short”, as % of retail sales, transacted at market Market Multiplier (On Peak RNS = 5%)

14. 14 T&D Avoided Costs by Planning Division SDG&E $77.76 SCE $36.00 $21.00 $5.00 PG&E $70.00 $38.00 $5.00

15. 15 Allocation of T&D Based on Temperature by Climate Zone Temperature Loads T&D Capacity Cost Drives Load Information Missing or Difficult to Obtain in Many Areas Temperature Use temperature as a proxy for load, and as the basis for allocating costs to hours of the year. T&D Capacity Cost

16. 16 Summer Peak Load vs. Temperature Fresno Yellow 8am to 10pm Similar analysis done on 33 PG&E areas as part of CEC Title 24 development

17. 17 Emission Prices & Plant Heat Rates Includes NOx, PM-10, and CO 2 emission credit prices Heat rate assumption Lower bound: 6,240 Btu/kWh Upper bound: 14,000 Btu/kWh

18. 18 3 Day Snapshot of Electric Avoided Costs Avoided Cost is Based on PG&E’s San Jose Planning Division

19. 19 Disaggregated Electric Avoided Costs Shape is Based on PG&E’s San Jose Planning Division

20. 20 Comparison of the Results Existing Efficiency Avoided Costs Impact on EE Program Evaluation by Type MPR in Renewable Portfolio Standard SCE QF Prices

21. 21 Comparison of Annual Avoided Cost New Total is Shown for PG&E, CZ 13, Secondary Voltage

22. 22 Comparison for Efficiency Programs Levelized Avoided Cost ($/MWh) over 16 Year Life for All Devices AC Load Shape Based on SEER 12 to SEER 13 Change in Fresno New Avoided Costs are based on PG&E, Climate Zone 13, Secondary

23. 23 Comparison of MPR in RPS Gas Price Comparison

24. 24 Comparison of Market Price in RPS Replacing gas forecast eliminates the difference in the MPR results between EE model and RPS model

25. 25 Comparison of Price Shape Price shapes are extremely similar SCE Revenue Calculator from Renewable RFP Efficiency Avoided Cost Averaged by Hour for Each Month