Steve Greenleaf Director of Regulatory Policy CAISO

1. CAISO Market Design 2002 And FERC SMD Where We Go From Here Steve Greenleaf Director of Regulatory Policy CAISO Committee on Regional Electric Power Coordination October 1, 2002 Vancouver, BC

2. Overview of MD02 Primary Elements of MD02 • Resource Adequacy – ACAP • Explicit Price Mitigation Measures • Damage Control Bid Cap • Automatic Mitigation Measures • Integrated Forward Market - Simultaneous optimization of energy, ancillary services and congestion management • Locational Marginal Pricing • Day-ahead and Hour-ahead Energy Markets • Firm Transmission Rights/Congestion revenue Rights • Real-time Economic Dispatch

3. Resource Adequacy - ACAP Obligation Rationale for ACAP • A root cause of the California crisis was the weakening of the traditional "obligation to serve" – responsibility of load-serving entities (LSEs) to procure sufficient supply for peak loads and operating reserves • The consequence was that responsibility fell on ISO as supplier of last resort – leading to a real-time scramble for resources to maintain reliability, and to extremely high prices in ISO markets and Out-Of-Market purchases – and resulted in over 13,000 OOM calls! • Therefore, ISO proposed to address its needs – support of its core function, reliable grid operation – through Available Capacity (ACAP) Obligation

4. Key Objectives of ACAP Obligation • Develop a mechanism that supports reliable operation of the system, consistent with the ISO’s statutory obligation under AB1890; • Provide a vehicle through which market participants can contract, schedule and bid in the forward market, thus achieving two key goals of the market design • Moving operational decisions from real time to the forward market. • Stabilizing spot-market prices by creating further incentives for forward contracting and thus a platform for generation and demand-based investment.

5. Key Considerations in ACAP • The ACAP proposal should be consistent with the ISO’s limited role in the energy market – that of supporting reliable system operation. • Customers should not incur additional costs, through ACAP obligation, that do not enhance reliability. • The ACAP obligation should not create a mechanism for exercising market power. • ACAP should provide a platform for capital investment in the California energy market.

6. Integrated Forward Market Design • Integrated Congestion Management, Energy Market, Ancillary Services, Unit Commitment Service • Forward Congestion Management • Locational Marginal Pricing (LMP) based on Full Network Model (FNM) – Enforcement of all network constraints ensures feasible schedules, consistent with physics of electricity flow • Day Ahead and Hour Ahead Energy Markets • LMP-based congestion management requires energy trading to clear congestion, thus creating a bid-based energy market • Eliminate Market Separation Rule and Balanced Schedule Requirement • Accommodates optional balanced bilateral schedules • Firm Transmission Rights (FTRs) • Point-to-point rights needed to allow complete hedging of risk under LMP congestion management

7. Locational Marginal Pricing (LMP) • Provides hourly price signals that reflect physical constraints of system under all load and system conditions • Locational price patterns indicate where additional generation and transmission upgrades are needed • Nodal prices correctly charge grid users for their impacts on congestion • Eliminates distinction between inter-zonal and intra-zonal congestion – manages ALL congestion in forward market to create feasible schedules • For loads, locational price differentials will be mitigated by allocation of FTRs

8. Integrated Forward Market • Balanced schedules will be an option • Physical bilaterals can obtain priority against curtailment for congestion via FTRs or as price takers for congestion charges • Generator ramping schedules must be feasible • Simultaneous A/S market will procure Spin, Non-Spin and Regulation • Replacement Reserve can be eliminated • Procurement based on Energy and Capacity bids • Simultaneous Unit Commitment Service (UCS) • Self-commitment will be an option • Energy, A/S, UCS – subject to transmission constraints • Residual Unit Commitment runs after integrated DA market

9. Redesign of FTRs • LMP requires “source-to-sink” FTRs • Hedge congestion charges calculated as nodal price differences • FTR specifies injection (source) and take-out (sink) points, ignoring paths of flow • Requires "simultaneous feasibility" to define and allocate FTRs • End points may also be trading hubs or load aggregations • Physical scheduling priority still viable in day ahead • Multiple FTR terms – 3-year, annual, monthly • FTRs are settled based on day-ahead prices • FTRs are "obligations" – failure to schedule may result in liability for congestion charge in opposite direction • Proven algorithm for allocating rights • Strong incentives to buy FTRs consistent with expected use of grid • Considering need for "options" (no liability associated) and “flowgate” rights in addition to basic source-sink obligations.

10. Redesign of FTRs • Allocation of FTRs • FTRs to be allocated initially to Load Serving Entities (LSEs) on behalf of end-use consumers, based on historical use of the grid • Allocation to LSEs hedges consumer risk of location-based pricing • Residual FTRs (FTRs in excess of those allocated to LSEs) will be auctioned by the ISO with revenues allocated to Transmission Owners • Converting ETCs to FTRs • Ultimate objective – all grid users subject to same scheduling procedures and time line • Eliminate "phantom congestion" due to current ETC scheduling time line • Conversion require more complex FTR model (obligations plus options; source-sink plus flowgates), requiring unproven allocation algorithms • ETC rights not all the same – one conversion approach may not satisfy all ETC holders • Transitional approach may be to implement Recallable Transmission Service (RTS) to reduce phantom congestion impact, while pursuing ETC-to-FTR conversion on a longer time frame

11. Hour Ahead Market • Revision of HA Market Time Line • Simultaneous congestion management, energy, AS and unit commitment, same as DA • ISO proposes to close HA and Real-time Markets at the same time, i.e., T-60 (60 minutes before start of Operating Hour) • Energy bids not cleared in HA would become bid pool for real time imbalance energy • Need for Hour Ahead Settlement • Only California ISO has 3-settlement system • HA settlement provides a means to limit exposure to real-time imbalance energy charges and deviation penalties • Allows late energy trades to schedule available transmission.

12. Real Time Economic Dispatch • Security-constrained, using Full Network Model • Considers all transmission constraints, loop flows, local reliability needs, generator operating constraints, as well as imbalance energy needs. • Same network model as forward markets; no distinction between inter-zonal and intra-zonal congestion. • Produces real-time 10-minute nodal prices • Congestion costs implicit in nodal price differences • Generators settle at nodal prices • Real-time load deviations may settle at nodal prices or aggregation levels (demand zones)

13. Implementation Phases • Initial implementation • Uses current 3-zone model – zonal rather than nodal prices • Creates integrated congestion, energy and AS markets • Eliminates existing "congestion iteration" in day ahead • Moves Hour Ahead market closer to Real Time (closing T-60) • Does not require changes to FTR design • Final implementation • Builds upon initial implementation • Uses Full Network Model to create nodal energy prices in forward and real time markets • Eliminates inter-zonal vs intra-zonal distinction • Requires new FTR design to hedge congestion risk

14. Conformance with FERC SMD

15. MD02 Implementation Schedule

16. MD02 Process Going Forward • Ongoing “Technical Conference” Process • FERC Order on MD02 resulted in the creation of four “Working Groups” whose purpose is to resolve “open” design issues: • Resource Adequacy • Integrated Forward Markets • Transitional Issues • Locational Marginal Pricing/Congestion Revenue Rights • Objective: To resolve open design issues by, approximately, the end of 2002.