market pricing initiatives update september 9th 2003 n.
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Market Pricing Initiatives Update September 9th, 2003

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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.

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market pricing issues
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


Real-time Price





significant contributing factors
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
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
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
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.
  • 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
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
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
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
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 reserve1
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 reserve2
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
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
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).