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 Initiatives Update September 9th, 2003

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Market pricing initiatives update september 9th 2003

Market Pricing Initiatives UpdateSeptember 9th, 2003


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.


Market pricing initiatives update september 9th 2003

Pre-dispatch Price Forecast

vs.

Real-time Price

Pre-dispatch

Real-time

Real-time

Pre-dispatch


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.


Initiatives

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

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).


Questions

Questions?


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