Demand Response Cost-effectiveness Protocols

1. Demand Response Cost-effectiveness Protocols Thursday, January 6, 2011 Eric Cutter, Snuller Price, Nick Schlag: E3

2. Agenda • 10:00 - Introductions • 10:15 – Avoided Cost Calculator • 11:30 – DR Reporting Template • 12:30 – Lunch • 1:30 – Adjustment Factors • 3:00 – Break • 3:15 – Utility Proposals • 3:45 – Administrative Costs • 5:00 - Adjourn

3. DR Process • November DR Workshop • Overview of Avoided Costs, DR Reporting Template • Proposed Decision • Comments • Reply Comments • Final Decision • Today’s January Workshop • Updates since November DR Workshop based on comments

4. Introduction

5. Two Tools • Avoided Cost Model • Publicly available data • Non-proprietary tool • DR Reporting Template • Standardized inputs • Non-proprietary tool • Common metrics for output

6. Avoided Cost Model and Relationships • Benefits Included • Energy purchases or generation cost • Generation Capacity • T&D Capacity • GHG Emissions • Losses • Ancillary Services Procurement Reduction • Reduced RPS procurement • Renewable Integration • Reducing overgen, Ramp • CPUC proceedings with similar approach • Energy Efficiency • DG Cost-effectiveness • Permanent Load Shifting • CEC proceedings with similar model • Title 24 Time-Dependent Valuation for evaluation of building standards Exported to DR Reporting Template Calculated by Avoided Cost Model Under Development

7. Use of Avoided Costs Across Proceedings • Same avoided costs from Avoided Cost Model • DG Avoided Cost Framework • Each proceeding determines how to apply avoided costs • Used for DG (CSI, SGIP) and DR • EE still using previous approach • ALJ will provide guidance regarding application of avoided costs and DR protocols to PLS

8. DR Reporting Template • Increased emphasis on consistency and transparency • Single, transparent Excel workbook for calculating and reporting cost-effectiveness results • Easy to compare and aggregate results

9. Avoided Cost

10. Avoided Cost Calculator Updates • Key Changes to Avoided Cost Calculator • CT dispatch • Allocation of generation capacity value • Financing assumptions and pro forma calculation • CT Dispatch Example

11. Changes to the CT Dispatch Calculations • Several stakeholders were concerned that the capacity factor of the CT was too high • Added a 10% minimum bid margin to the CT dispatch algorithm, similar to CAISO methodology • CAISO Market Performance Report http://www.caiso.com/2777/277789c42ac70.html • Adjusted CT operations based on historical temperature profiles • Heat rate adjustment • Reduced output

12. Integration of Temperature Effects into Capacity Value • Temperature affects the operations—and hence the capacity residual—of a new CT in three ways: • Operating Cost: High temperatures result in increases in the heat rate, which in turn increases the cost of generating a unit of energy • Operating Performance Penalty: At high temperatures, the output of a CT is reduced, lowering the revenues the unit can earn by selling into the real-time market • Peak Performance Penalty: During peak periods, when temperatures are also high, the output of the CT is reduced below nameplate, which increases the CT’s residual value per kW generated during the peak

13. CT Dispatch: Summer Peak Performance Penalty Output curve based on GE LM6000 with SPRINT technology and dry cooling: http://www.hilcoind.com/images/ftp/SFPUC/7/A/LM6000%2060%20Hz%20Grey%202008%20Rev%202.pdf

14. CT Dispatch: Heat Rate Adjustment Based on Temperature Heat rate curve based on GE LM6000 with SPRINT technology and dry cooling

15. Capacity Allocation • Several stakeholder suggested that using a single year of historical load data to allocate capacity value was not representative • After the December workshop, E3 provided several alternatives including utility LOLP and four years of historical data • Final decision allocates capacity value based on four years of historical load data (2006-2009)

16. Capacity Allocation Based on Four Historical Years Percent of Total Capacity Value by Month

17. ComparisonCapacity Allocation • The allocators used to value DR peak impacts are based on the average of the allocators calculated for the period 2006-2009 • In most months, this serves as a reasonable approximation of PG&E’s LOLP Percent of Total Capacity Value by Month

18. Financial Pro Forma Updates • Correction of CT MACRS term from 20 to 15 years • Addition of property tax and insurance costs • Property tax: 1.1% of capital costs per year • Insurance: 0.6% of capital costs per year • Addition of Manufacturing Tax Credit • 9% of half of plant W2 wages (4.5%), based on CEC COG Model • Adjustment of debt/equity shares to reflect current financing climate – still assuming 3rd party owned CT • Increased debt share in capital structure from 50% to 60%

19. Example CT Dispatch • To calculate the value of capacity, E3 assumes that a CT will participate in the CAISO real-time market • Consistent with CAISO Annual Market Report • The parameters that determine the CT’s net revenues include the real-time prices, the cost of fuel, the unit’s heat rate and O&M, and ambient temperature

20. Example CT Dispatch • Step 1: Forecast hourly real-time market prices based on heat rates from July 2009 through June 2010

21. Example CT Dispatch • Step 2: Calculate operating cost ($/MWh) for a CT in each month as a function of the gas price, heat rate, and variable O&M

22. Example CT Dispatch • Step 3: Sort real-time market prices (and corresponding CT operating costs) in descending order (top 1000 hours shown below)

23. Example CT Dispatch • Step 4: Calculate the CT’s revenue assuming it operates when the real-time price exceeds its variable cost plus the 10% bid adder

24. Resulting California Net Cost of CT • Calculation of the final residual value includes several further adjustments • Energy revenues reduced by 7% for plant outages • A/S market participation assumed to increase gross revenues by 11% (based on CAISO market report)

25. Data Sources and References

26. DR Reporting Template

27. DR Reporting Template • Avoided Cost Model • Publicly available data • Non-proprietary tool • DR Reporting Template • Standardized inputs • Non-proprietary tool • Common metrics for output

28. Using the DR Template • Make sure latest inputs are copied from the Avoided Cost Calculator • Create a new tab for your program • Note! One tab for each ‘DR program’ • Input load impacts for the DR program • Input costs for the DR program • Review cost-effectiveness results • Run sensitivity analysis

29. DR Reporting Template • Avoided Cost Inputs • Program Impacts • Program Costs • Results • Optional Benefits • T&D Costs • Adjustment Factors • What constitutes a program • Adding New Program

30. DR Reporting Template Inputs from Avoided Cost Calculator

31. DR Reporting Template Inputs that are IOU Specific

32. Program Impacts Wtd. Avg. Adjusted

33. Program (Ratepayer) Costs • Administrative Costs • Incentive Costs • Equipment Costs (Amortized) • Net Bill/Revenue Reductions • Total Ratepayer Costs

34. Program (Ratepayer) Costs 4. By Category 1. Program Costs 2. Equipment Costs 3. Amortization 4. Total

35. Participant Costs • Incentive Costs • Net Bill/Revenue Reductions • Equipment Costs (Amortized) • Total Ratepayer Costs X 75%

36. Participant Costs 1. Program Costs + X 75% 4. Estimate Costs - 2. Equipment Costs 3. Amortization 5. Total

37. Cost Tests TRC PAC

38. Cost Tests RIM PAC

39. Avoided Cost Benefits Capacity Energy T&D GHG

40. Optional and CAISO Market Benefits

41. Adjustment Factors & T&D Values

42. Base Case Results

43. Sensitivities Sensitivity values (blue cells) set at discretion of CPUC Energy Division

44. Add New Program • Definition of Program • Any program or sub-program with distinct features • Availability, Notification Time, Trigger etc. • Distinct A-E factors • Add Program

45. Portfolio Results • Total DR portfolio cost and results entered in separate tab • Account for dual participation • DR Reporting Template cannot simply sum across programs automatically • Ensure that portfolio impact, costs and benefits are accurate and representative • Calculation will need to be performed by utility outside of DR Reporting Template • Back into representative average A-E factors to that portfolio impacts X avoided costs = portfolio benefits

46. Questions and Excel Demo Example

47. Factor Analysis

48. Factor Analysis Framework • Make appropriate adjustments for differences between DR resource and resources used to determine Avoided Costs • Combustion Turbine, T&D infrastructure etc. • Allow some flexibility for utility specific values and approaches • Reduce analysis to single percentage factor for easy comparison across programs and utilities • Must be supported by analysis and explanation

49. Adjustment Factors • A Factor – Availability • Maximum number, duration and timing of DR calls • B Factor – Notification Time • Length of program notification time • C Factor – Trigger • Flexibility in when DR calls may be made • D Factor – T&D Capacity value • Marginal vs. Avoided T&D costs • Right Time: Coincidence of DR calls with local T&D system peaks • Right Place: Ability to target DR calls based on local conditions • Right Certainty: Reliable enough for T&D deferral • E Factor – Energy Value • Energy value when DR is call as compared to average On-Peak energy prices

50. Adjustment Factor Examples • E3 Produced example approaches for analysis supporting each factor • Suggested approaches only: utility may suggest/develop alternative approaches • Must support analysis with public data • Can use proprietary data (e.g. LOLP), but also perform analysis with public data