CPUC Avoided Cost Workshop

1. CPUC Avoided Cost Workshop Introduction and Overview

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. 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. 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. 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. Summary of Energy Efficiency Avoided Cost Values

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. Dimensions of the Analysis

9. Price Elasticity Price Elasticity Hot Hot Hot of Demand of Demand afternoon afternoon afternoon Externality Externality T&D T&D Environmental Environmental Reliability Reliability Cost Externality Externality Externality Externality Avoided Avoided Generation Generation Costs Costs Energy Value EnergyValue Market Prices Avoided Cost Monday Tuesday Wednesday Thursday Friday Monday Tuesday Wednesday Thursday Friday Hourly Electric Cost Structure

10. Electric Formulation of Avoided Cost Natural Gas Commodity Commodity Period 1 (2004-2008) Platt’s / NYMEX Period 2 Transition Period 3 (2008-2023) LRMC Period 1 (2004-2008) NYMEX Period 2 Transition Period 3 (2008-2023) Long-run Forecast   1 + Ancillary Services (A/S) 1 + LUAF + Compression  + Market Multiplier T&D Costs  + 1 + Energy Losses 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” T&D Costs  (1 + Peak Losses ) + Environment  (1+ Energy Losses)

11. Generation Marginal Cost Forecast Working Group Framework Market Data (Short Term) Long Run Proxy (Long Term) Electric Forward data Gas Futures data Long Run Marginal Cost (CCGT) 2004 2006 2008 2023

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. Market Elasticity Estimates Market Multiplier (On Peak RNS = 5%) • 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

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

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

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

17. Emission Prices & Plant Heat Rates • Includes NOx, PM-10, and CO2 emission credit prices • Heat rate assumption • Lower bound: 6,240 Btu/kWh • Upper bound: 14,000 Btu/kWh

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

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

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

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. Comparison of MPR in RPS • Gas Price Comparison

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

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