CPUC Avoided Cost Workshop

1. CPUC Avoided Cost Workshop Generation Avoided Costs

2. Organization of Presentation • Goals and Recommended Approach • Discussion of Comments • Input Data Vs. Methodology • Scenarios and Stress Cases

3. Goals for the Avoided Cost Methodology • Disaggregate information by area and time to facilitate detailed analyses where appropriate • Use publicly available data, or information that can be easily provided by utilities • Transparent method • Easily updated

4. Data Sources Forecasts: How Often Are They “Correct”?

5. Generation Avoided Cost Comments • “Thin markets are not accurate” • “Forward prices do not reflect full capacity value - Hedge value” • “Use of CCGT misstates avoided cost in high usage and low-usage periods” • Market price referents • “Separate electric capacity and energy avoided costs are needed” • Source of generation cost inputs

6. 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

7. Megawatt Daily sample of long-term forward data for on-peak delivery ($/MWh for August 22, 2003) Average annual prices derived from on-peak quotes Use 1999 PX data for on-peak to off-peak ratio Data Sources Short-Term Forecast Example

8. NYMEX Gas Futures Extend Forwards through 2008 $/MWh $/mmbtu Electric forwards data Natural gas futures data

9. Recommendation on Market Forwards “Thin markets are not accurate” “Forward prices do not reflect full capacity value - Hedge value”

10. Liquidity of Forward Market Data • Electricity Forwards: Platts does not include volume data. Likely illiquid, especially for 2006. Intercontinental Exchange (ICE) is another potential source. • Gas Futures: NYMEX data indicate good liquidity in the near 24-36 delivery months, less so in the subsequent months • Gas Basis Swaps: No basis swap volume data published, likely illiquid, especially for later months • Illiquidity does not necessarily imply a systematic bias in the data (higher or lower than avoided cost) • It is possible that illiquid markets can be manipulated

11. Comparison of Platts (broker quotes) and NYMEX The comparison shows that forward market prices do not differ significantly by market (NYMEX futures vs. Platts bilateral).

12. Possible alternatives to reliance on illiquid forward markets • Utilities provide their own forward price curves • Average forward prices over several days or multiple sources rather than relying on a single source and day • Econometric electricity price forecast: NYMEX gas with electricity spot price regression • Use NYMEX gas with monthly heat rate assumption • Use forecast from CEC or a production simulation model • Ignore forward markets and move directly to resource balance year With the exception of 1) and 2), it is not clear these alternatives provide a better outcome than E3’s proposed methodology

13. Full Capacity and Hedge Value in The Market Data • Forward contracts are firm delivery at a set price, so no additional hedge value is required. • The forward price contains the market valuation of the capacity needed to ensure firm delivery of the contracted energy. No additional capacity value is required.

14. Data and Approach Generation Cost Level: LRMC • Long Run Marginal Costs (LRMC) used for marginal costs beyond the resource balance year in the forecast. • The LRMC estimate would be based on the cost to own and operate a combined cycle gas fired generator located in the California Control Area. • LRMC sets the annual average costs, and the historical market is used for the shape. • LRMC data source • We recommend that the forecast use publicly available input from the CEC, EIA and possibly EPRI.

15. LRMC Proxy Cost Is a gas fired CCGT a reasonable proxy for the long term marginal cost of electricity in CA? • Reviewed over 350 plant descriptions from NWPPC, WECC and CEC for plants built in last 3 years and in process of being built over next 5 years. Several conclusions can be drawn from this data: 1. Most capacity that has come on line or is planned is from gas fired generation: 73% in US; 90% in NWPPC area; 84% in WECC area; and 98% in California. 2. Combined Cycle (CCGT) plants are the dominant technology: 89% of NWPPC area gas fired plants; 94% of planned gas fired plants in WECC area; 87% of the gas fired plants constructed in the last 3 years or planned in California. 3. Combustion Turbines (CT) comprise of 5% of the NWPPC area gas fired generator market. In the WECC area, of the gas fired plants that had their technology specified 3% of the plants planned were CTs. In California, CTs comprise of 13% of the gas fired plants.

16. Data Sources LRMC- Different Plant Specifications(Data was produced in June, 2002) Data shows significant differences in costs and performance by plant type

17. Data Sources LRMC Example Using EIA, EPRI and CEC estimates of CT and CCGT Costs The levelized cost is fairly close if we use a common set of input assumptions What really drives the LRMC are the gas and financing forecasting assumptions

18. Data Sources Hourly Shape: Historical Market Data Timeline Used for Price Shape DWR Market open PX close 04/98 04/00 01/01 06/01 01/03 Normal times: Relatively stable and low prices UDCs resume procurement for small RNS Electricity crisis: hot summer, gas price spike, emission cost spikes; dry hydro; capacity shortage; rolling blackouts; capped prices

19. Example NP15 Shape Average of Hourly Values by Month

20. Capacity Separation “Separate electric capacity and energy avoided costs are needed”

21. Example of Capacity Separation • Integral of the light blue area is the capacity cost.

22. Market Price Referents “Use of CCGT misstates avoided cost in high usage and low-usage periods”

23. Hourly Costs Already Reflect Market Prices for Various Generator Types • Generators that operate few hours (like peakers) will have relatively high average market prices. • Baseload plants will have relatively low average market prices, as they will be operating when marginal costs are lowest,. Peaker Average Baseload Average

24. Peakers are not getting the capital cost of a CCGT unit • Under LRMC, CCGT’s recover the full capital cost of their plant IF they: • have a heat rate of 7100 BTU/kWh • operate at 91.6% capacity factor • Peaker units have higher heat rates, so their margin when they operate is lower --- so less capital recovery. • Peaker units would also operate far fewer hours, so there would be even less margin to cover return on and of the capital

25. Scenarios and Stress Cases May be Suitable for DR and Dispatchable DG or Rate Programs

26. Scenarios High Gas Price/High Growth Scenario Scenario- Higher growth pushes the resource balance year to 2007, the transition to LRMC begins at 2006 and we have 75th percentile gas prices until 2010 and base case LRMC after. Resource Balance Year Electric Forward data from Platts Long Run Marginal Cost (CCGT) LRMC with High Gas Transition to LRMC LRMC with Base Case Gas

27. Stress Case Model

28. Using the Model to Create Scenarios

29. Example of program evaluation • Avoided cost values for a range of alternative scenarios for a dispatchable program with fewer than 4 hours per dispatch and 50 dispatches per year. PG&E climate zone 12, weighted average of planning divisions