Market Pricing Initiatives Update September 9th, 2003

1. Market Pricing Initiatives UpdateSeptember 9th, 2003

2. Market Pricing Issues • Disconnect between Pre-dispatch prices and Real-time prices. • Counter-intuitive prices in times of shortage. • Size, content and variability of uplift.

3. Pre-dispatch Price Forecast vs. Real-time Price Pre-dispatch Real-time Real-time Pre-dispatch

4. Significant Contributing Factors • Sensitivity to changes from forecast to real-time. (i.e. generation and transaction performance) • Manual use of ‘Out-of-market’ Control Action’s. (i.e. use of voltage reduction to provide Operating Reserve) • Calculation difference between Pre-dispatch and Real-time price. (i.e. Intertie Price setting, actual vs. peak forecast) • Algorithm schedules “just enough”

5. Impact on Marketplace The Pricing Issues have extremely significant negative impacts on the marketplace: • distort the economic signals of the market, which detracts from efficient operation of IMO Administered Markets; • minimize the ability of Market Participants to respond to price detracting from reliable operation; and • jeopardize the short and long term success of the marketplace by reducing investor and market participant confidence.

6. Current Status • Market Consensus - maintaining status quo is not acceptable: • pricing signals and outcomes; • reduced market efficiency; and • reliability at risk (short and long-term). • Supply is tight in Ontario for foreseeable future • Market structure schedules “just enough” resources to meet market demands • Significant increase in average HOEP would cause hardship to load customers

7. Integrated Approach • Objective: • Provide understandable market prices, improve efficient operation of IMO-administered Markets and reliable operation of IMO-controlled Grid • Strategy: • Reduce frequency of need for control actions, then change manner in which control actions are utilized i.e. put Control Action Operating Reserve “in the market”. • Introduce all initiatives in a controlled manner.

8. Initiatives • Includes Initiatives that are already underway or complete: • Removal of the 4/2 hour Restrictions; • Enhanced market information; • Hour Ahead Dispatchable Load (HADL); • Reducing the Failed Intertie Transactions and • Spare Generation on Line • Include first step of Control Action Operating Reserve in the market

9. Reducing Failed Intertie Transactions • High priority for the IMO, NYISO and MISO. • Stakeholder discussions are taking place to reduce frequency and magnitude of failed transactions between the IMO and other jurisdictions. • Current frequency and magnitude of failures while slightly improved is still not acceptable.

10. Spare Generation On-Line • Goal to get available spare generation on-line in “shoulder” periods • Guarantee recovery of start-up, speed no load and minimum generation costs, and minimum run-time • Voluntary - consistent with rest of market commitments • Guarantee of these costs and having spare generation on-line is comparable and consistent with neighbouring markets/jurisdictions • Program is a natural progression towards a Day Ahead Market (Market Evolution Program)

11. Control Action Operating Reserve (OR) • OR is acquired to meet industry reliability obligations. • 10 & 30-minute requirements equal ~1375 MW: • 10-minute = ~950 MW and is equal to the largest unit; • 30-minute = ~475 MW and is equal to 1/2 of the largest unit; and • 200 MW of supplemental reserve. • Control Action OR: • 400 MW of 3% voltage reduction; • 280 MW of 5% voltage reduction; and • ability to disregard the 30-minute requirement.

12. Control Action Operating Reserve • Objective was to reduce pricing issues. • Proposal was to offer Control Action OR into the market based on its value. • Value was difficult to determine directly - use participant issues to arrive at an approximate value.

13. Control Action Operating Reserve • Implement the OR proposal in STEPS • quantity and price approved by the IMO Board • prudent approach recognizing the uncertainty • allow assumptions to be benchmarked • allow participants to react to changes • STEP 1 - implemented August 6th, 2003 • 200 MW in the pre-dispatch and real-time offered at: • 30Min OR - $30.00 • 10Min NS OR - $30.10

14. Control Action Operating Reserve • Subsequent STEPS • timing and prices to be determined • proposed quantities include: • an additional 200 MW of 3% voltage reduction capability; • 280 MW of 5% voltage reduction capability; • the inclusion of the 30 minute shortfall provisions

15. Initial Results • The data and analysis presented is for the period August 7 through August 12, inclusive. We are presently analysing the data from August 23 to present. • In general the impacts have not been significant, but the limited impacts witnessed to date are judged to be, in large part, due to the short period of implementation, a modeling constraint that limited the use of the control action operating reserve in pre-dispatch, and the market conditions which were not particularly severe during this period.

16. Initial Results cont’d • During the study period, the use of control action operating reserve in the market is estimated to have increased the average HOEP by about $0.65/MWh (relative to an average estimated HOEP without the control actions of $44/MWh). • The Intertie Offer Guarantee (IOG) payments are estimated to have been reduced by about 5 k$ (relative to total IOG payments of 290 k$). • During the period, control action operating reserve was scheduled in the real time: • market schedule approximately 2.9% of the time (this is the schedule that affects HOEP) and in the • constrained schedule 11.5% of the time (this is the schedule that affects the actual dispatch).

17. Questions?