Day-Ahead Market Evolution Detailed Overview Presentation to Technical Panel July 8, 2008
Focus of Presentation • Provide some detail (“nuts and bolts”) of the “common elements” of the day ‐ ahead design • Currently working on a detail design document for the common elements which is expected to be presented to you through market rule amendments throughout the coming months 2
Reminder of Day-Ahead Design Work • Identify day ‐ ahead mechanism improvements that would result in net benefits to the province as a whole relative to the existing Day ‐ Ahead Commitment Process (DACP) • Elements which provide the majority of benefits to Ontario, specifically: 1. Day ‐ ahead unit commitment improvements ( operational and integration of the changing supply mix expected to emerge in the next few years) 2. Better scheduling incentives (includes imports/exports), reduced transaction costs 3. Day Ahead Demand Response Efficiencies (providing opportunities to better manage demand response are common to all options 3
Common Elements • Common design elements enhancing constrained algorithm includes: – 3 ‐ part bids/offers – 24 ‐ hour optimized unit commitment process – multi ‐ passes of the constrained schedule using peak and average – adding day ‐ ahead exports – review and change the existing guarantees • Discuss the design of each item above and including how design differs from today algorithm 4
Why Three Part Offers/Bids • Multi ‐ part offers/bids requires market participants to submit not only the incremental cost of energy but also other financial costs and physical limitations in advance of operations • Allows all energy offer/bid components (total cost) to be used in determining the most economic dispatch for entire system ‐ more accurately reflects the complex cost structure of some generators and loads • Drives correct outcomes as these offers/bids accurately reflect: – The cost of being available for dispatch – The physical restrictions of the load or generator 5
Typical Three-part Offer Incremental • Incremental energy offer Energy + • Start ‐ up cost (cost to get to minimum loading Costs to point) reach/maintain minimum output • Minimum generation cost + • Minimum generation block • Ramp rates • Minimum run time Operational • Minimum down time Restrictions • Maximum stops per day • Maximum daily energy limit 6
Start-up Cost • Start ‐ up cost is the cost to bring an off ‐ line resource up to the minimum generation level • Includes all unit specific procedures such as ramp up and synchronisation • Submission options: – Hourly Start ‐ up cost – A single cost for each hour of the day – Time Since Last Stoppage – Cost is submitted as a function of the time the unit was last on line – No Start ‐ up Cost – A $0 startup cost 7
Ongoing Minimum Generation Cost • Minimum generation cost is the ongoing cost to maintain resource output at the minimum generation level • Can be changed hourly 8
Minimum Level of Generation • The Minimum Generation (or “Min Gen”) level is the lowest output a facility is physically capable of sustaining while remaining on ‐ line • Only for a short period during start ‐ up or shut ‐ down can a resource be below this level • Initially the Min Gen limit indicated during Facility Registration 9
Multi-Part Offer Example ($) Generator A offer: 60 •50MW minimum: $2,500/hr •50MW to 100MW: $20/MWh 50 •100MW to 150MW: $30/MWh 40 30 20 10 0 50 100 150 (MW) Min Gen. Incremental Energy Generator A must operate at least to MW minimum 10
Multi-Part Offer Example ($) Generator A offer: 60 •50MW minimum: $2,500 •50MW to 100MW: $20 50 •100MW to 150MW: $30 40 30 20 10 0 50 100 150 (MW) Dispatching Generator A to meet a 110MW demand results in a cost of $3,800 = $2,500 + 50MWx$20 + 10MWx$30 11
Multi-Part Offers Compared Generator A Generator B $50 $30 $31 $20 110MW 110MW Generator B offer: 110MW at $31, no min ‐ gen or start ‐ up cost Cost of Generator A = $3,800 Cost of Generator B = $3,410 A market that incorporates 3 ‐ part offers would schedule Generator B. Today’s market does not see the min ‐ gen offer and would schedule Generator A based on its lower incremental offer. 12
Difference From Today • Currently single part (incremental) offer/bid structure • No consideration of the total cost of being available for dispatch or the physical restrictions of the load or generator • Physical limits and costs to reach/maintain minimum output are used after the fact to constrain on units in multiple hours to respect minimum run times and settle production cost guarantees 13
Incorporating 3 part bids • Initially costs to reach/maintain minimum output or the physical restrictions to be included as a static submission in registration data • Software program will “scrape” information into optimization process • Timing of these submission offer/bid data updates under review • Upgrade to MIM in 2009/2010 will allow for data to be submitted as part of offer/bid process 14
Integrating Three-Part Offers/Bids in Real-Time • “Guts” of real time (RT) algorithms will not change from their current form ‐ incremental energy only • Evaluation process for changes to unit commitments after close of the DA process is completed will be addressed by a manual process or aided by an offline tool ‐ limited use of the three ‐ part offers/bids in real ‐ time 15
What is 24 Hour Optimization? • Dispatch model that determines the optimal commitment (minimizing total of all as offered costs) and scheduling of generation and load response to meet energy and operating reserve requirements over the entire day • Uses three ‐ part offer/bid structure • In contrast current model optimizes hour ‐ by ‐ hour with no regard to future hours 16
Multi-Hour Optimization Example • Assume the following multi ‐ part offers : Start ‐ up Minimum Incremental Minimum Minimum Gen. Cost Energy Offer Load Point Run ‐ Time Cost Generator A $5000 $5500 $30/MWh 300MW 4 hours (400MW) Generator B $6000 $7000 $40/MWh 100 MW 2 hours (500MW) Generator C N/A N/A $50/MWh 0 MW N/A (100MW) 17
Multi-Hour Optimization • Today’s market would commit Generators A and B based on incremental energy offers only • Generator B would be constrained ON in Hour 5 to respect its minimum run ‐ time, constraining down Generator A Hour 1 Hour 2 Hour 3 Hour 4 Hour 5 400 MW 400 MW 400MW 500 MW 400 MW Demand Demand Demand Demand Demand Generator A 400 MW 400 MW 400 MW 400 MW 300 MW schedule Generator B 0 0 0 100 MW 100 MW schedule Generator C 0 0 0 0 0 18 schedule
Multi-Hour Optimization • 24 Hour optimization enables a comparison of total costs, including start ‐ up for the dispatch day to arrive at least cost reliability commitment 100 MW 200 MW 300 MW 400 MW 500 MW Generator A Cost 0 0 $10,500 $13,500 0 Generator B Cost $13,000 $17,000 $21,000 $25,000 $29,000 Generator C Cost $5,000 0 0 0 0 19
Multi-Hour Optimization Hour 1 Hour 2 Hour 3 Hour 4 Hour 5 400MW 400MW 400MW 500 MW 400MW Demand Demand Demand Demand Demand Generator A 400MW 400MW 400MW 400MW 400MW schedule Generator B 0 0 0 0 0 schedule Generator C 0 0 0 100MW 0 schedule With 24 hour optimization, a more expensive incremental energy offer may be selected to save the cost of start ‐ up and minimum run for the extra 100MW Also impacts constrained on/off payments 20
Difference From Today • Constraints are not considered by the current DACP when it determines whether to commit a resource, causing the resulting commitment to be inefficient at times • CBA analysis illustrated 3 part offers/bids along with 24 hour optimization will resulted in approx. savings of $5M/yr through unit commitment efficiencies 21
Multi-pass Constrained Algorithm • Calculation engine design based on multiple passes: – First pass commits resources to forecasted average demand – Second pass adds an additional resources required to meet peak – Lastly pass use commitments from second pass to calculate hourly advisories based on average • Using today’s signal pass method based on peak overstates requirements impacting efficient market operation of both IESO and participants 22
Multi-Pass Runs of Constrained Algorithm Export bids Pass 1 Generation Constrained Run offers Based on Average Ontario demand Forecast to Obtain forecast less Import offers Unit Commitments dispatchable load bids Dispatchable load bids Pass 2 Constrained Run Based on Peak Forecast to Ensure Sufficient Unit Commitment to Meet Expected Peak Demand – Uses a bias to solve with internal bids and offers Blocked on from pass 1: •Non ‐ quick starts (cannot go below minimum) •Import and export schedules Pass 3 Constrained Run Based on Average Forecast to Obtain Advisory Schedules This should be a very quick pass of the algorithm as there is no additional unit commitment than what was determined in Pass 2 23 The schedules produced by Pass 3 are the day ‐ ahead constrained schedules (DACS)
Rule Amendments • Additions of 3 part offers/bids, 24 hour optimization and multiple security constrained passes rules to reflect changes to “calculation engine”, (dispatch scheduling and optimization engine) will be reflected in Appendix 7.5 Market Clearing and Pricing Process 24
Recommend
More recommend
