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MISO Energy Market

MISO Energy Market. May 13, 2005 Chetty Mamandur Manager, Network Topology Modeling cmamandur@midwestiso.org 317-249-5834. MISO at a Glance. 108,000 MW peak load 122,000 MW generating capacity 100,000+ miles of transmission lines 16.5 million customers $12.6 billion installed assets.

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MISO Energy Market

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  1. MISO Energy Market May 13, 2005 Chetty Mamandur Manager, Network Topology Modeling cmamandur@midwestiso.org 317-249-5834

  2. MISO at a Glance • 108,000 MW peak load • 122,000 MW generating capacity • 100,000+ miles of transmission lines • 16.5 million customers • $12.6 billion installed assets

  3. MISO Fast Facts • Control centers in Indiana and Minnesota • 27 utility members (36 control areas) • Operational since December 15, 2001 • Energy Market Operations Beginning April 1, 2005

  4. Indiana Control Center • PICTURE 3

  5. ISO/RTO Map - (SeTrans dissolved)

  6. Recent Developments • MISO Energy Market began operations April 1, 2005 • MISO/PJM Joint Operating Agreement • (market to non-market Terms prior to April 1, 2005 and Market to Market Terms post Market start) • Seams talks with TVA, SPP, MAPP, & IMO

  7. Market Benefits • Efficiency of equipment usage • Generators • Transmission grid • Increased options for supply of energy and optimal use of energy resources across the region • Security constrained unit commitment and economic dispatch for load across a broad regional footprint • Transparency of energy pricing data • Market based congestion management • Deferral of generation construction through utilization of a wider set of assets • Meeting requirements of FERC Order 20 • Congestion management • Energy imbalance

  8. Impact of the Midwest Market • All resources within the MISO footprint will be evaluated as a pool of resources • Generation dispatch and outage management will be centralized and managed from MISO • MISO’s Market Participant will use new/ enhanced systems • MISO OASIS for reservations • E-tag Software • Day-Ahead, Real-Time System (DART) • Financial Scheduling System • Financial Transmission Rights System (FTR) • Physical Scheduling System (PSS) • Customer Service Requests - Siebel • Congestion will be primarily managed through LMP methodology and if necessary TLR procedures and seams agreements

  9. Key Participant Components May not have assets Marketer Load Serving Entity Generation Owner Transmission Owner

  10. Market Activities Pre Day Ahead Post Real Time Day Ahead Real Time Before Market • MISO Planning Activities • MP Planning Activities • Operations – AGC • Metering • Settlement Statements • Settlement Calculations • Settlement Disputes • Demand Bids and Supply Offers • Virtual Bids and Offers • Physical/ Financial Bilateral Transactions • Market Results • FTRs • Forecasting

  11. Energy Market Operations • MISO operates Day-Ahead and Real-Time Energy Markets • Participants can bid to buy and offer to sell energy • Participants can schedule bilateral transactions • MISO performs settlements with participants for transactions • MISO calculate Locational Marginal Prices (LMP) • MISO pays those selling energy, charge those buying energy, and charge those using transmission

  12. Day Ahead & Real Time Markets • Day Ahead (DA) Market • Provides risk management to Real Time Market • Opportunity to schedule transactions • Opportunity to set up Generation Offers – Demand Bids • Real Time (RT) Market • Balancing market from DA • Operations that are going on right now • Schedules that are flowing right now

  13. Reliability Enhancements • State estimator in full use as of 1/1/04 (130,500 data points; 30,500 buses; 5,500 contingencies performed every 8 minutes) • More flowgates monitored (from 400 to 617) • Advanced alarming, additional staffing • More training (including dispatch simulator training)

  14. Day-Ahead Market • Supply Offers and Demand Bids are due at 0900 EST prior to the operating day • MISO uses Security Constrained Unit Commitment (SCUC) to economically commit units to meet bid-in demand • MISO uses Security Constrained Economic Dispatch (SCED) to efficiently allocate Transmission Capacity and minimize Congestion • Day-Ahead Market provides opportunity to hedge Real-Time Market • MISO publishes financially binding Day-Ahead schedule at 1500 EST

  15. Generators MISO Load Serving Entities Day-Ahead Market Offers Day-Ahead Schedules Day-Ahead LMPs Bids 0900h 1500h

  16. Day-Ahead Market 1500 0900 Network Model Cleared Supply Approved Transmission Outages MISO Market Operations Cleared Demand Physical Schedules Constraints Clear Day-Ahead Market Demand Bids Locational Marginal Prices Time: 0900 – 1500 Supply Offers • All posted at 1500 Resource Parameters

  17. Reliability Assessment Commitment (RAC) • RAC ensures that sufficient resources are available and online to meet the forecasted load for each hour of the next operating day • RAC uses Start-up and No Load costs to determine unit selection • Selected resources are guaranteed to receive Start-up and No Load costs if their revenue is not greater than Start-up and No Load

  18. MISO Reliability Assessment Commitment Timing Load Forecast Start-up & No Load RAC Selections Day-Ahead Schedules 1500h 1700h 1900h

  19. Reliability Assessment Commitment 1900 1700 Start-up Price MISO Market Operations No Load Price Perform Reliability Assessment Commitment Commitment Notification Resource Parameters Day-Ahead Market Schedules Time: 1700 – 1900 • At 1900 and ongoing throughout operating day Real-Time Load Forecast

  20. Real-Time Centralized Dispatch • MISO uses the Security Constrained Economic Dispatch (SCED) program every 5 minutes of the operating hour • MISO sends Control Areas Net Scheduled Interchange (NSI) and basepoints for generators • NSI and Resource Basepoints sent every 5 minutes • Dynamic Schedules sent every 5 minutes • Ramped Control Area NSI sent every 4 seconds • Ramped Dynamic Schedule values sent every 4 seconds • Results of the Centralized Dispatch and actual system activity are inputs to the ex-post Real-Time LMP calculation • Ex-post RT LMPs integrated over the hour are used in settlements

  21. MISO MISO Real Time Centralized Dispatch Timing* EX ANTE Load Forecast Net Scheduled Interchange Resource Information Dispatch Basepoints/Rates EX POST Dispatch Basepoints/Rates Ex Post RT LMPs Actual System Activity * Conceptual representation

  22. MISO Market Settlements Timing Schedule Information DA and RT LMP Settlement Statement Actual Load & Generation Day 7 Day 8

  23. Market Settlement Daily Daily FTR MISO Market Settlements • Market • Charges/ • Credits • Energy • Congestion • Losses • Day-Ahead Market • Cleared Supply and • Demand • Internal Bilateral Schedules • Locational Marginal Prices Settle the Day-Ahead and Real-Time Markets • Real-Time Market • Metering • Internal Bilateral Schedules • Locational Marginal Prices

  24. B C A Illustration Assumptions Key Points • Assumes no losses • Equal line impedance • Matches fixed load to generation output • Dispatches generation according to $/MWh offer • Observes generator maximums • Observes line limits GEN A LOAD C GEN B Because our example assumes no losses, the difference in LMPs between two locations is the same as the difference in Congestion Components of the LMPs

  25. Inject 1 MW A B C 2/3 MW 1/3 MW Withdraw 1 MW 1/3 MW Equal Line Impedance

  26. A B C Withdraw 1 MW 2/3 MW Inject 1 MW Equal Line Impedance 1/3 MW 1/3 MW

  27. A B C 2/3 MW Withdraw 2 MW 2/3 MW Inject 1 MW Line Loadings Inject 1 MW 1/3 MW 1 MW 1/3 MW 1/3 MW 0 MW 1 MW The flows A-B and B-A result in a line loading of 0 MW on branch A-B 1/3 MW

  28. A B C Day-Ahead Market Example Generator at A offers to sell0 to 200 MWh @ $20/MWh Load Serving Entity (LSE) at C wants to buy 390 MWh Generator at B offers to sell0 to 400 MWh @ $40/MWh

  29. A B C Resulting Schedule if No Transmission Constraints MISO will schedule all 200 MWhoffered by Generator at A Flow on Line AC is 196.67 MISO will schedule 390 MWh of Load at C Line Flow A-C 200 x 2/3 = 133.333 190 x 1/3 = 63.333 Total MW = 196.67 MISO will schedule 190 MWhoffered by Generator at B

  30. A B C Calculating Marginal Price MISO will schedule all 200 MWhoffered by Generator at A $40/MWh MISO will schedule 390 MWh of Load at C $40/MWh $40/MWh If load increased by 1 MWh at any buswe would increase schedule of Generator B by 1 MWh at a cost of $40 Marginal Price is $40/MWh MISO will schedule 190 MWhoffered by Generator at B

  31. Settlement of Unconstrained Scenario • MISO will pay generators the marginal price for their scheduled output • MISO will charge load the marginal price for scheduled demand • When there are no transmission constraints, MISO pays out what it collects

  32. Congestion and LMPs • Congestion occurs in the transmission network • When the transmission capacities at one or more facilities or interfaces become fully utilized • Capacity is based on operational security criteria (usually “n-1”) • Congestive elements tend to interact with each other • Their costs must be analyzed in combination • The LMP approach to transmission congestion pricing achieves this • Via price-based dispatch subject to constraints on power flows

  33. Congestion and LMPs • When congestion occurs in the Day-Ahead (DA) and Real-Time (RT) markets, congestion costs are reflected in market prices • As components (positive or negative) in the LMP spot prices paid to sellers and collected from consumers of energy • As transmission congestion charges (positive or negative) from MISO to customers with bilateral transactions • Hourly congestion charge for transmission of Ptrans MW Charge = Ptrans x [ CC of LMPwithdraw – CC of LMPinject ]

  34. Schedule all 200 MWhfrom Generator at A A B C Schedule 390 MWh Load at C Schedule 190 MWhfrom Generator at B Original Schedule with Transmission Congestion Maximum flow on Line AC is 153 MW Flow on Line AC is 196.67 which violates limit of 153 MW

  35. A B C New Least-Cost Schedule Redispatch occurs to reduce flow to line limit Schedule 69 MWhfrom Generator at A Flow on Line AC is 153, at the limit of 153 MW Schedule 390 MWh Load at C Schedule 321 MWhfrom Generator at B

  36. A B C What is Locational Marginal Price (LMP)? LMP at a bus is the cost of serving an increment of load at the bus Schedule 69 MWhfrom Generator at A Flow on Line AC is 153, at the limit of 153 MW $20/MWh Schedule 390 MWh Load at C $40/MWh • If we add 1 MWh of load at bus A, we would increase output of Generator at A by 1 MWh at cost of $20 • LMP at bus A is $20/MWh • If we add 1 MWh of load at bus B, we would increase output of Generator at B by 1 MWh at cost of $40 • LMP at bus B is $40/MWh Schedule 321 MWhfrom Generator at B

  37. A B C Calculating LMP Schedule 69 MWhfrom Generator at A Flow on Line AC is 153, at the limit of 153 MW $20/MWh Schedule 390 MWh Load at C $XX/MWh $40/MWh • For an increase in load at C of 1 MWh: • Increasing Gen A by 1 MWh would violate flow limit • Increasing Gen B by 1 MWh would violate flow limit Schedule 321 MWhfrom Generator at B

  38. 68 A B C 391 323 Calculating LMP Schedule 69 MWhfrom Generator at A Flow on Line AC stays at the limit of 153 MW $20/MWh Schedule 390 MWh Load at C $60/MWh $40/MWh • For an increase in load at C of 1 MWh: • Increase Gen B by 2 MWh at cost of 2  $40 • Decrease Gen A by 1 MWh at cost of -1  $20 • Net cost is $60 • LMP at Bus C is $60/MWh Schedule 321 MWhfrom Generator at B

  39. Settlements of Constrained Scenario • MISO will pay generators the LMP for their scheduled output • MISO will charge load the LMP for scheduled demand • When there are transmission constraints that affect LMPs, MISO collects more than it pays out; totaling $9,180 in this example • This excess congestion revenue is the source of payments to FTRs

  40. Questions?

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