Market Pricing Initiatives Update September 9th, 2003

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.

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

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”

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.

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

Integrated Approach Objective: Strategy: 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.

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

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.

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)

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.

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.

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

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

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.

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).

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