Western Area Power Administration

1. Western Area Power Administration Rocky Mountain Region Customer Meeting - October 30, 2002 Standard Market Design and Regional Transmission Organizations Updates Jane Meyer, Ron Moulton, Mark Fidrych, Bob Easton, Jeff Ackerman, Ed Hulls, Bob Kennedy

2. Agenda • Overview of Standard Market Design • Overview of WestConnect Ruling • Overview of RTO West Ruling • How will the scheduling process change? • Will transmission rights change? • What could happen to existing contracts?

3. Agenda (Cont.) • Will the cost of transmission change? • How could the planning process change? • How is Western’s merchant preparing for possible changes? • How is Western’s control area preparing for possible changes? • Locational Marginal Pricing (LMP) Overview

4. Standard Market Design Overview Jane Meyer Restructuring Project Manager RMR & CRSP

5. FERC believes Standard Market Design is Needed • FERC’s goal is to promote economic efficiency in electricity for the benefit of all Americans • Order 888 in 1996 • Required all public utilities to: • file open access non-discriminatory transmission tariffs • Functionally unbundle wholesale power services from transmission services • Imposed a reciprocity condition for non-public utilities

6. FERC believes Standard Market Design is Needed • Order 2000 • Encouraged all transmission owners to voluntarily place their transmission facilities in the hands of Regional Transmission Organizations (RTO) • Industry has been working toward that goal: • Independent System Operators (ISO) formed in California, New York, New England, PJM, and ERCOT • RTOs formed in Midwest (MISO), Southeast (SETrans), Southwest (WestConnect), and Northwest (RTO West)

7. FERC believes Standard Market Design is Needed • FERC issued Notice of Proposed Rulemaking (NOPR) - July 31, 2002 • Long name: “Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design” • FERC Docket No. RM01-12-000 • http://www.ferc.gov/Electric/RTO/Mrkt-Strct-comments/smd.htm

8. FERC believes Standard Market Design is Needed FERC’s Vision: • Same set of rules for all users of the grid administered by a fair and independent entity • Eliminate Residual Discrimination • Lower Costs to Customers • Customer protection through market power mitigation measures and oversight • Clear transmission pricing and planning policies to incent investment in infrastructure • Provide a framework for effective State & Federal regulation

9. Standard Market Design - Major Elements • Independent Transmission Provider (ITP) • New transmission tariff • Transmission pricing reform • Organized Day-Ahead (DA) and Real-Time (RT) spot markets • Mitigation of market power and market monitoring • Resource adequacy • Regional planning process

10. Independent Transmission Provider • Jurisdictional utilities mandated to turn over control of their transmission facilities to an independent entity - Independent Transmission Provider • Regional Transmission Organization (RTO) • Independent System Operator (ISO) • Independent Transmission Company (ITC)

11. Independent Transmission Provider • Jurisdictional utilities had three options: • Become an Independent Transmission Provider • Cannot have financial interest, either through an affiliate or any market participant • Contract with Independent Transmission Provider for operational control of transmission facilities • Join a Regional Transmission Organization

12. Options for Non-jurisdictional Utilities • SMD NOPR proposes that existing reciprocity tariffs filed under 888 OATT will be grandfathered • FERC requested comment on this provision

13. Independent Transmission Provider • Operates transmission facilities • Administers Standard Market Design transmission tariff • Transmission pricing • Congestion management • Administers organized spot market • Long-term planning and expansions • System impact and facilities studies

14. Independent Transmission Provider • Transmission transfer capability calculations • Market monitoring and market power mitigation, including establishing bid caps and must-offer requirements • Establish long-term resource adequacy requirements

15. New SMD Transmission Tariff • Today - Two types of transmission service • Network Integration Service • Point-to-Point Service • SMD - Network Access Service • Characteristics of Network Integration Service - access to all generators on the grid • Characteristics of Point-to-Point Service - rights are tradable • Bundled retail load of jurisdictional utilities must take transmission service under Tariff

16. Transmission Pricing • Today - Network and Point-to-Point transmission customers pays transmission charge for embedded costs • SMD • Load pays embedded costs through access charge • Load pays only one access charge for Network Access Service • Pancaking (payment of more than one transmission rate for delivery from source to sink) is eliminated

17. Organized Spot Markets • Independent Transmission Provider must operate day-ahead and real-time markets for energy and ancillary services, in conjunction with the transmission market • Voluntary, bid-based, security-constrained day-ahead spot energy market

18. Organized Spot Market • NOPR includes the use of Locational Marginal Pricing (LMP) of energy and congestion in both day-ahead and real-time markets • NOPR includes the use of financial transmission rights to assure that transmission is used by those entities that value the transmission the most • Congestion Revenue Rights

19. Market Monitoring • NOPR lays out framework • Independent market monitoring unit • Evaluates state of market • Identifies need for changes in market rules • Identifies load pockets & areas where infrastructure is needed for competition • Reports to FERC, Regional State Advisory Committee, and Board of Directors

20. Resource Adequacy Requirements • Long-term Resource Planning will be policed by independent Transmission Provider • Mandate load serving entities to provide their share of resources through own resources and contract purchases • Guard against over reliance on spot markets • Assure that there are adequate transmission, generation, and demand-side resources

21. Reaction by Industry • Western Governors • FERC should specifically set aside the Western Interconnection from its SMD rule and concentrate on working with the states to develop RTOs that address the specific problems in the Western Interconnection. This process should begin with a well-defined and factually-supported statement of the problems in the Western Interconnection. (September 17, 2002)

22. Reaction by Industry • Northwest Congressional Delegation • In short, we believe this is an unnecessary, poorly conceived and dangerous academic experiment that would inject volatility and uncertainty into the comparatively stable and affordable energy system in the Northwest. We would urge the Commission to abandon the proposal. (September 27, 2002)

23. Reaction by Industry • Senate Energy and Natural Resources Committee hearing September 17, 2002 • Senators were uniformly critical. • Only two of the nine witnesses supported the proposed SMD rule. • Kentucky Governor Patton slammed the proposed rule, saying it fails the test of adopting policies that are in the best interests of the entire nation.

24. SMD Comments Due • The Commission extended comment period to November 15, 2002, except for comments which address the following: • (1) market design for the Western Interconnection; (2) transmission planning and pricing, including participant funding; (3) Regional State Advisory Committees and state participation; (4) resource adequacy; and (5) CRRs and transition issues • Comments dealing with the issues are due January 10, 2003

25. Western Review of SMD NOPR • Organized Western-wide review teams to develop responses/positions to questions in SMD NOPR • Coordinating with BPA and DOE • Customer comments & input welcome • Bulk of Western’s comments will be submitted in January

26. SMD Delayed • Final rule delayed until next summer • In the meantime, RTOs have been approved and market designs are being developed by the stakeholders

27. RTOs in the West

28. Overview of WestConnect Ruling • Jurisdictional Participants (Applicants) • Arizona Public Service Company • El Paso Electric Company • Public Service Company of New Mexico • Tucson Electric Power Company • Non-Jurisdictional Participants (Involved to varying degrees) • Salt River Project • Western Area Power Administration • Southwest Transmission Cooperative, Inc. (AEPCO) • Tri-State G&T Association, Inc. • Website: http//www:westconnectrto.com

29. Overview of WestConnect Ruling • Requested Declaratory Order - October 16, 2001 • FERC Ruled - October 10, 2002 • Approved scope • Approved governance structure • Approved license plate rate for an interim period • Approved voluntary conversion of existing contracts • Requested more details about self-tracking

30. Overview of WestConnect Ruling • FERC Ruling (Continued) • Approved congestion management proposal as a “Day One” mechanism and directed Applicants to engage in further discussions to develop a congestion management program that reflects market-driven solutions to clear congestion operations and that does not create seams among the Western RTOs.

31. Overview of WestConnect Ruling • FERC clarified that it is not their intent to overturn, in the final SMD rule, decisions that are made in the WestConnect Ruling • Unclear what FERC has decided and therefore will not be overturned • FERC was silent on many issues • Critical items, such as congestion management, were approved with modifications • Western needs clarification and details

32. Overview of WestConnect Ruling Ron Moulton Restructuring Project Manager DSW

33. RTOs in the West

34. Overview of RTO West Ruling • RTO West Participants • Avista Corporation • Bonneville Power Administration • Idaho Power Company • NorthWestern Energy L.L.C. (formerly Montana Power Co.) • PacifiCorp • Puget Sound Energy, Inc. • TransConnect ITC • Nevada Power Co., Sierra Pacific Power, Co., Portland General Electric • British Columbia Hydro and Power Authority

35. Overview of RTO West Ruling • Stage 2 Filing - March 29, 2002 • Request For Declaratory Order • Attachments • Pricing, Congestion Management, Transmission Planning, Market Monitoring . . . • Agreements • Transmission Owners Agreement, Scheduling Coordinator Agreement, Paying Agent Agreement • Implementation Plan (June 28, 2002) • Operational 2006

36. Overview of RTO West Ruling • FERC Ruled - September 18, 2002 • Approved Scope & Governance • Approved License Plate Pricing & Transition Period (8 Yrs) • Conditionally Approved Congestion Management • Approved Voluntary Contract Conversion • Approved Planning & Expansion • Approved Framework for Interregional Coordination

37. Overview of RTO West Ruling • FERC Ruling (Continued) • Rejected TOA Trumps Tariff • Defers Addressing TOA Until Tariff Complete • Directs Applicants to File Tariff (120 days) • Directs Development of Standards of Interconnection • Conditionally Approves Market Monitoring Proposal • Will Not Overturn with SMD Final Rule

38. Overview of RTO West Ruling • Stage 3 Activities (Oct 02 - Jan 03) • Market Design Workgroup • Market Operations • Ancillary Services • Cataloguing/Options • Losses • Metering, Control & Communications • Tariff Development Workgroup • Visit http://www.rtowest.com/ for more information

39. Seams Steering Group - Western Interconnection (SSG-WI)

40. Seams Steering Group - Western Interconnection (SSG-WI) • Steering Group (Closed) • SSG-WI serves as the discussion forum for facilitating the creation of a Seamless Western Market and for proposing resolutions for issues associated with differences in RTO practices and procedures. • Workgroups (Open) • Planning • Congestion Management • Pricing Reciprocity • Market Monitoring • Commons Systems Interface Coordination

41. Seams Steering Group - Western Interconnection • FERC Directed CAISO, RTO West & WestConnect (within 90 days of Order) • Codify the MOU between parties to define their commitments and the forum by which issues will be resolved. • Provide a list of pending issues before the Steering Group and timeline for resolution of those issues. • Visit http://www.ssg-wi.com/ for more information

42. How Could Scheduling Process Change? Mark Fidrych Utility Restructuring Advisor RMR & CRSP

43. How Could Scheduling Process Change? • Today (Day(s) Ahead) • Independently or via Scheduling Agent • Customers have various Op Agreements with Service Providers • Forecast Needs (Determine Loads) • Decide on Supplier(s) • Arrange/Verify Transmission • Submit Pre-Schedule to Control Area for System Reliability Analysis

44. How Could Scheduling Process Change? • Today (“Next Hour”) • Independently or via Scheduling Agent • Evaluate Forecast (Incorporate Load Changes) • Verify Supplier(s) • Verify Transmission • Modify Pre-Schedule

45. How Could Scheduling Process Change? • Today (“Real-Time”) • Independently or via Scheduling Agent • Respond to Contingencies/Curtailments • Adjust Schedules • Acquire Emergency Resources • Interrupt Load • Verify Delivery

46. How Could Scheduling Process Change? • SMD (Day Ahead) • Independently or Load Serving Entity • Network Operating Agreement with ITP • Forecast Needs (Determine Loads) • Determine if want price/delivery certainty • Decide on Supplier(s) • Bilateral Transactions • Venture into the Day-Ahead & Real-time Spot Markets

47. How Could Scheduling Process Change? • SMD (Day Ahead) • Designate Receipt & Delivery Points • Transmission Service Scheduled in the Day Ahead Market • Synchronizes Energy and Transmission Schedules • Analysis of Physically Feasible Dispatch • Source/Sink required for Simultaneous Feasibility Evaluation • Must hold Congestion Revenue Rights (CRR) or Agree to Congestion Costs

48. How Could Scheduling Process Change? • SMD (“Real-Time”) • Independently or Load Serving Entity • Evaluate Forecast (Incorporate Load Changes) • Revise Receipt and/or Delivery Points

49. How Could Scheduling Process Change? • SMD (“Real-Time”) • Independently or Load Serving Entity • Respond to Contingencies • Interrupt Load • Take other Emergency Actions which may be required • Respond to Curtailments • Should only be associated with “trapped loads” • Verify Delivery

50. How Could Scheduling Process Change? • SMD Versus Today • No Longer Required • Load/Resource Balanced Schedule • Transmission Reservations • 100% of Forecasted Load Met by Resource • Designation of Network Resources • New Features • Voluntary, Bid-Based Energy Markets • Ancillary Service Bid-Based Markets • Transmission & Energy Delivery are Coupled