Least Cost Plan & Electric Restructuring

1. Least Cost Plan& Electric Restructuring Grace Hu Chief Economist District of Columbia Public Service Commission Thimpu, Bhutan October 7, 2002

2. The Public Service Commission The Public Service Commission of the District of Columbia was established by Congress in 1913 as an independent District Government agency to regulate the electric, gas and telephone companies in the District. Check www.dcpsc.org for more infor.

3. Type of Proceedings • (1) Formal Litigation • (a) Company’s Application • (b) Notice of Intervention • (c) Pre-hearing conference • (d) Order designates issues based on pre-hearing conference • (e) Company’s Direct Testimony • (f) Intervener's Direct Testimony • (g) Rebuttal Testimony • (h) Pre-hearing briefs • (i) Post-hearing briefs • (j) Commission Order

4. Type of Proceedings (Cont.) • Rate case needs to be finished in 9 months. Both PSC hearings and community hearings were conducted. • (2) Paper Proceedings • Comments • Reply Comments • Commission Order

5. Type of Cases on the Energy Side • (1) Rate Case • (2) Least Cost Plan Case • (3) Industry Restructuring Case • (4) Merger Case • (5) Tariff Update

6. Conserve kWhPEPCO’s Least Cost Plan • Purpose of the Plan • An integrated least-cost resource planning strategy requires the utility to consider all feasible demand-side options for implementation in this jurisdiction, to weigh these options against supply-side options and to develop a plan which contains the most cost-effective strategies for the utility and its customers. • The Plan considers possibilities of conserving energy, generating and transmitting power, cutting costs, serving customers and protecting the environment. This long-term plan will meet customers’ growing needs at the lowest costs. • See Appendix 1, pages 1-11.

7. Reserve Margin Analysis • Compute your reserve margin by taking the difference between the installed capacity and the net peak demand (gross demand minus impact of Demand-Side Management Programs) • D.C. Commission used to require a 16% reserve margin • Regional reserve margin (22%) may be different from state’s (16% in the case of D.C.) • See Appendix I, Page 12

8. System Planning Model • Based on linear and mixed integer liner programming techniques. • Model identifies least cost plan additions. • Least cost expansion plan is entered into the linear programming model to determine marginal capacity and energy costs. • Objective function: Minimize over the planning horizon the discounted present value of incremental capital costs and operating costs of existing and new generating units. • See Appendix 1, Page 46.

9. SPM model (Cont.) • Constraints include system constraints and plant or unit constraints • The sum of all new plus existing plant capacity must meet or exceed forecasted peak demand by 16% (minimum reserve margin)

10. Planned Investment Approach • 1. Used to calculate marginal transmission, marginal subtransmission, marginal distribution and marginal customers costs • 2. This approach is not a mathematical or economic model but a considerably simple calculation

11. Planned Investment Approach (Cont.) • Components needed to calculate these marginal costs • Total demand related additions to transmission plant • Growth in system peak • Incremental cost per CP kW • Real carrying charge rate • Annualized cost per CP kW • See Appendix 1, Page 47.

12. Avoided Costs and Least Cost Plan • Marginal costs are generally used for rate design purpose and avoided costs are used for least cost plan purpose. • Avoided costs: The costs avoided as a result of conservation measures are used to account for the benefits for the conservation measures. • Utilities avoided costs are a major component to calculate benefits of utilities. If benefits are greater than costs, the DSM program is cost effective. The avoided costs play a major role in screening DSM programs.

13. Demand-Side Management Programs • Program Screening – Various Cost/Benefit Tests were applied. • All-Ratepayers Test measures the impact of DSM on the customers’ bills. • Rate Impact Measure (RIM) Test measures the impact of DSM on the customers’ rates. • We currently consider both. However, many programs passed the All-Ratepayers Test would not pass the RIM test.

14. DSM Programs (Cont.) • We no longer have LCP requirement since PEPCO sold its generation assets. • We have a Reliable Energy Trust Fund (RETF) which collects a surcharge to finance (1) Energy Efficiency Programs (2) Renewable Resource Programs and (3) Low-Income Direct Assistance Programs.

15. DSM Programs • High-Efficiency Air Conditioner Rebate Program • Rebate dropped from $600 to $300 from 1992 to 1997 because of market transformation. • Through the program, PEPCO has increased customer awareness of the benefits of high-efficiency HVAC equipment and has encouraged HVAC dealers, contractors, and retailers to stock high-efficiency equipment. • See Appendix 1, Pages 31-40.

16. New Building Design Program • It is a commercial DSM program. • Program rebates are based on the average incremental cost between standard-efficiency and high-efficiency equipment. • The program also encourages thermal energy storage applications in new buildings.

17. Other Conservation Program Concept • A. Shared Savings Approach • Win-win for both Energy Service Companies and Customers • B. Pay As You Save • Customers pay additional surcharge on their bill to cover the cost of energy efficiency programs.

18. Energy Use Management Programs (EUM) • Residential Time of Use Rates • Kilowatchers Club • A cycling program for central air conditioners, heat pumps, and electric water heaters. • PEPCO limits the cycling of air conditioners to no more than 15 non-holiday weekdays over the five-month period and to no longer than six hours between noon and 8 p.m. For air conditioning, the air conditioner compressors may be cycled off for 13 minutes and then on again for the next 17 minutes of each half-hour of program operation.

19. EUM Programs (Cont.) • Commercial Time of Use Rates • Curtailable Load Program • PEPCO offers summer billing period credits of $8.6 per kW reduced to commercial customers who agree to provide at least 100 kW of load curtailment. Upon receipt of a signal from PEPCO, participating customers reduce their electricity demands to a “firm service level” for the duration of a curtailment request. Participants who fail to reduce their demand to the firm service level pay a penalty of $17.20 for each kW used above the firm service level. • See the Appendix 1, Pages 13-30.

20. Demand Response Programs • Mitigate the Supply-Side market power and enhance reliability. • Regional ISO programs supplement states’ programs.

21. Supply-Side Evaluations • Considering PEPCO’s generating facilities, power purchase agreements, renewable resource options, fuel supply arrangement, and Clean Air Act compliance.

22. Transmission and Distribution Improvement Plans • Commission had established a Productivity Improvement Working Group (PIWG) which consists of PEPCO, Office of People’s Counsel, and Commission Staff. • PIWG meets monthly to discuss G, T, D related projects and all the productivity and fuel related issues.

23. T&D Improvement Plans (Cont.) • PEPCO is required to file a Productivity Improvement Plan (PIP) each year with the Commission. Commission will issue an order once the plan and OPC & Staff’s comments are reviewed.

24. Key Components of PIP • (1) Productivity Improvement Projects • (2) Industry Comparison includes: • Annual unit • Operating availability factors comparison • Equivalent availability factors comparison • Capacity Factor comparison • Equivalent forced outage factors comparison • System heat rate comparison

25. Key Components of PIP (Cont.) • System Energy Losses Comparison • (3) Fuel prices, consumption and expenditures forecast (the % difference between forecasted values vs. actual values were presented too.) • (4) Technical Terms and Engineering Process

26. Regional Transmission Expansion Plan • On Transmission side, PEPCO is a member of Pennsylvania, New Jersey and Maryland Independent System Operator. • Stakeholders and PUC representatives collaboratively decide the transmission expansion plan for the region. • PEPCO participated in regional studies and conducted internal transmission studies.

27. Planning Framework • Step 1: Resource Screening • Step 2: Baseline Load Forecasts • 15 Years • Step 3: Full- Loop Integration • The plans minimize total revenue requirements for their respective scenarios. • Step 4:Sensitivity Analysis and Base Plan Selection

28. Planning Framework (Cont.) • Step 5: Development of Alternative Plans • With the Base plan as a starting point, PEPCO develops alternative resource plans that address a broader set of planning criteria. • Step 6: Analysis of Candidate Plans • Each alternative plan is analyzed to determine how well it meets each planning objective.

29. Planning Framework (Cont.) • Step 7: Preferred Plan Selected • PEPCO selects a preferred plan that balances effects on prices, utility revenue requirements and customer bills, reliability, and customer service objectives. • Step 8: Action Plan • A four-year action plan details PEPCO’s projected capital costs, budgets, and schedules for carrying out the Preferred strategy. • See Appendix 1, page 41.

30. Integration Procedure • Baseline Load Forecasts • See Appendix 1, Pages 48-51. • Marginal Cost Determination • DSM Cost-Effectiveness Analysis • Net Load Forecasts • Resource Integration • See Appendix 1, pages 42-45, 67.

31. Key Planning Assumptions • For alternative cases, the planning assumptions vary. • Key assumptions include: • General Inflation • GDP growth rates • Price of Electricity

32. Built or Buy Decisions • Evaluated outside of the filing of Least Cost Plan • Previously, two projects were considered • PEPCO would like to sign two power purchase agreements • One with Patowmack Power Partners, Inc., (PPP) and the other with Panda-Brandywine L.P. (Panda)

33. Panda and PPP Projects • PEPCO requested that the Commission approve these non-company power projects in the context of a modification to its least-cost plan (LCP) and find the contract payments to be below the Company’s avoided costs.

34. Panda and PPP Projects • The Commission investigated two issues: • (1) Is the need for and the timing of the Panda and PPP projects prudent and consistent with PEPCO’s least cost planning activities? • If so, should PEPCO’s LCP be amended as proposed by PEPCO to include these two contracts?

35. Panda and PPP Projects • (2) Whether the proposed payments for energy and capacity pursuant to the terms of the Panda and PPP contracts are below PEPCO’s applicable avoided costs?

36. Panda and PPP Projects • PEPCO suggested accepting both projects. • OPC suggested accepting one project Panda. • Staff suggested rejecting both projects.

37. Panda and PPP Projects • Staff’s main reasons: • PEPCO would not need any capacity to satisfy the reserve margin requirement until 1995 • PPP was supposed to be on-line starting with 1994 • Panda and PPP created excess capacity for six years, during a time when PEPCO’s reserve margin exceeds 20 percent • See Appendix 2, PSC (B)-7 to PSC (B)-10.

38. Panda and PPP Projects • Based on both need, timing and avoided costs analysis, Staff rejected both projects. • Commission decided to accept Panda rather than PPP.

39. Retail Electric Competition and Consumer Protection Act of 1999 Additional Highlights: • The Commission is actively establishing customer education programs including a Commission hosted website to facilitate price comparisons • See www. dcpsc.org, click on customer information, electric. • Establishing Reliable Energy Trust Fund Programs • Establishing code of conduct between PEPCO and its affiliates • Determining fuel mix information disclosure for the consumers

40. The 1999 Act (Continued) • Establishing procedural rules for complaints, investigations and dispositional hearings • Governing market power proceedings in both retail and wholesale markets • Implementing competitive bidding process to select default service provider prior to July 1, 2004 • New SOS provider should start on January 1, 2005.

41. The 1999 Act (Continued) • In addition: • a) The Act states that the Mayor, in conjunction with the Commission, shall issue regulations governing a municipal aggregation program. • b) Net Metering provisions include: Facilitating the development of distributed generation. • c) Competitive billing shall begin on January 1, 2002.

42. Act Implementation & the “Retail Choice Program” Jan. 1, 2001 • The Commission completed the “Three-Phase” Rate Reductions • The total rate reduction for three-phases amounts to 7% for Residential customers and 6.5% for Commercial customers. • 11 Suppliers/Aggregators were approved by the Commission.

43. Current Statistics • 8.3% of residential and 19.1% of non-residential customers have switched to the third-party suppliers. • In terms of total MWs, 48.9% of the load has switched. • See page 68 for a copy of recent D.C.’s market monitoring report. • For a copy of Electric Policies in the Public Interest, see Appendix 1, Pages 52-66.

44. THANK YOU!