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SeTrans Grid Company Market Structure and Operations

SeTrans Grid Company Market Structure and Operations. Proposed Market Structure. Assumptions. Market Features. Control Area Concept. Ancillary Services Markets. Firm Transmission Rights. Congestion Management. Assumptions.

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SeTrans Grid Company Market Structure and Operations

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  1. SeTrans Grid Company Market Structure and Operations

  2. Proposed Market Structure • Assumptions. • Market Features. • Control Area Concept. • Ancillary Services Markets. • Firm Transmission Rights. • Congestion Management. 2001 SERC Conference

  3. Assumptions • RTO will be the control area operator. • RTO will not operate a Power Exchange. • All generators under RTO authority will be subject to redispatch under emergency conditions. • RTO will be the Security Coordinator. 2001 SERC Conference

  4. Assumptions • RTO will have authority and responsibility to maintain system reliability: • Normal Conditions. • Emergency Conditions. • Sufficient resources will be under RTO control to respond to all credible system contingencies. 2001 SERC Conference

  5. RTO Market Features • Three Time Periods: - Day Ahead -Hour Ahead -Real Time • Day Ahead submission of hourly balanced schedules with optional hourly adjustments. • Mandatory settlement for all real time deviations from schedule. • Real Time settlements based on Locational Marginal Price (LMP) at generator or load bus. 2001 SERC Conference

  6. RTO Market Features • Ancillary Services acquired through bid based markets. • Transmission service reserved on Contract Path basis. • Firm transmission rights awarded on flowgate basis, not contract path. 2001 SERC Conference

  7. Balancing Entity A Balancing Entity Southern Company Balancing Entity B Balancing Entity C Control Area Concept TVA VACAR Southern Subregion RTO IPP Entergy IPP IPP FRCC

  8. Control Area Concept • Normal operations supported by Ancillary Services purchased from bid based market. • Emergency operations: • Reliability situations which can not be resolved using market mechanisms, i.e. insufficient ancillary services bid. • Mandatory redispatch of all generators. • Mandatory curtailment. 2001 SERC Conference

  9. Ancillary Services • Bid-Based Ancillary Services Market. • FERC Ancillary Services: • Scheduling and Dispatch Services. • Reactive and Voltage Control. • Spinning Reserves. • Supplemental Reserves. • Regulation. • Energy Imbalance. • Congestion Management. • Black Start/System Restoration. 2001 SERC Conference

  10. Ancillary Markets Operated • Capacity and Energy Markets. • Reactive and Voltage Control. • Interconnection agreements and contracts. • Spinning Reserve. • Supplemental Reserve. • Regulation. • Energy Imbalance. 2001 SERC Conference

  11. Day Ahead Process Timeline • Initial Submittal of Balanced Schedules 11:00 AM • - Initial RTO Analysis • Initial Posting of Day Ahead Projections 12:00 PM - Transmission Customer Analysis • Adjustment Submittal 1:00 PM - Final RTO Analysis • Final Posting of Day Ahead Projections 2:00 PM - Day Ahead Settlement Process Closed Initial Submittal Initial Posting Adjustment Submittal Final Posting TC Analysis RTO Analysis RTO Analysis 11:00 AM 12:00 PM 1:00 PM 2:00 PM Iteration 1 Iteration 2

  12. Hour Ahead Process Timeline • Submittal of Balanced Schedules 2 Hours Prior to Real Time • Initial RTO Analysis • Final Posting of Hour Ahead Data 1 Hour Prior to Real Time • Hour Ahead Settlement Process Closed • Final Transmission Customer Adjustments • Scheduling Window Closes Twenty Minutes Prior to Real Time • Transaction Scheduling • Real Time Operations Scheduling Window Closes Initial Submittal Final Posting Real Time Operations RTO Analysis TC Adjustments 2 Hours Prior to Real Time Twenty Minutes Prior to Real Time 1 Hour Prior to Real Time Real Time

  13. Firm Transmission Rights • All firm transmission service customers will receive Firm Transmission Rights (FTRs). • FTRs represent rights to specific flowgate capacity along the contract path specified. • Flowgates are transmission facilities or interfaces that may reasonably be expected to experience congestion during certain time periods. 2001 SERC Conference

  14. Firm Transmission Rights POR TVA Duke FG 1 FG 3 FG 2 FG 4 FG 5 FG 6 Entergy FG 7 FRCC POD

  15. Firm Transmission Rights • Possession of an FTR confers specific rights if the flowgatebecomes congested: • Priority for avoiding redispatch cost. • Priority for avoiding physical curtailment. • FTRs may be freely traded subject to registration with the RTO. The RTO will operate a secondary market. • FTRs may be used for any transaction, not just the one they were awarded for. 2001 SERC Conference

  16. Congestion Management • Required when system parameters exceed security limits. • May apply to day ahead, real time operations or contingency conditions. • System parameters can include: • Current Flows. • Voltages. • Dynamic Stability Limits. 2001 SERC Conference

  17. Congestion Management • When congestion occurs, non-firm service customers may: • Pay voluntary redispatch costs (if a redispatch solution is available). • Purchase Firm Transmission Rights (and thus become firm transmission customers). • Physically curtail transaction. 2001 SERC Conference

  18. Congestion Management • When congestion occurs, firm service customers: • Pay mandatory redispatch costs or reduce schedule(s). • If no redispatch solution exists, all customers may have to physically curtail (based on priority). 2001 SERC Conference

  19. Congestion Management • Congestion may be caused by external loop or parallel flows. • To the extent that these can be identified, efforts will be made to curtail these flows prior to calling for internal redispatch. • External parties may be given the option of voluntary redispatch. • External parties that hold Firm Transmission Rights will be treated as any other firm service customers. 2001 SERC Conference

  20. Locational Marginal Pricing • LMPs will be calculated on the following schedule: • Following initial submission of day ahead schedules. • Following submission of hour ahead schedules. • Hourly for real time settlement process. • Projected LMP prices for the next 24 hours will be published each hour. 2001 SERC Conference

  21. Locational Marginal Pricing • Locational Marginal Price: The marginal cost of supplying the next increment of electric demand at a specific location on the electric power network, taking into account both generation marginal cost and the physical aspects of the transmission system. 2001 SERC Conference

  22. Locational Marginal Pricing • LMP will be used to price all energy deviations from schedule regardless of cause, including: • Energy Imbalance. • Redispatch. • Ancillary Services. 2001 SERC Conference

  23. LMP Example $25 $20 $10 $40 $15 SAMPLE SYSTEM (lossless system assumed) Load = 50 MW each 70 MW each

  24. Uncongested System Total Load = 250 MW Marginal unit 70MW 40 MW 70 MW $25 $20 $10 100 MW Limit 60 MW Flow $40 70 MW LMP= $25 $15 • Settlement • All Loads and Generators are Bilateral • LMP of $25 Charged to Deviations From Scheduled Amount Load = 50 MW each Generator = 70 MW each Marginal Generator

  25. Congested System Left Load = 150 MW Right Load = 100 MW Partial Congestion Marginal unit Marginal unit 50 MW 60 MW $25 70 MW $20 $10 50 MW Limit 50 MW Flow 0 MW LMP= $20 LMP= $25 $40 70 MW $15 • Settlement • LMP of $20 Charged to Deviations From Scheduled Amount on Left • LMP of $25 Charged to Deviations From Scheduled Amount on Right Marginal Generator Load = 50 MW each Generator = 70 MW each

  26. Fully Congested System Complete Congestion Left Load = 150 MW Right Load = 100 MW Marginal unit 70 MW 10 MW $25 70 MW $20 Marginal unit $10 0 MW Limit 0 MW Flow 30 MW LMP= $40 LMP= $20 $40 70 MW $15 • Settlement • LMP of $20 Charged to Deviations From Scheduled Amount on Left • LMP of $40 Charged to Deviations From Scheduled Amount on Right Load = 50 MW each Generator = 70 MW each Marginal Generator

  27. FTR Congestion Hedging TTCA-B = 1000 MW B A Firm FTRs = 1000 MW Total Scheduled Flow = 1100 MW Firm Scheduled = 800 MW Non Firm Scheduled = 300 MW Redispatch Required = 100 MW 2001 SERC Conference

  28. FTR Congestion Hedging $20/MW $40/MW A B 100 MW 100MW RTO Pays Generator B $40/MW*100 MW = $4000 RTO Receives From Generator A $20/MW*100 MW = $2000 RTO Cash Flow = $2000-$4000 = -$2000 RTO is Revenue Short Congestion Costs of $2000 must be recovered from transactions 2001 SERC Conference

  29. FTR Congestion Hedging IDRA = $20/MW IDRB = $40/MW B A TTC Allocated to FTR Owners Scheduled FTR = 800 MW < 1000 MW Firm Customers allocated NO congestion Cost All Congestion Costs Directly Assigned to Non-Firm 2001 SERC Conference

  30. FTR Congestion Hedging IDRA = $20/MW IDRB = $40/MW A B Non-Firm Charged Congestion Allowable Non-firm Flow = 1000 - 800 = 200 Scheduled Non-firm = 300 MW Non-firm Congestion Cost = (Scheduled - Allowed)*(IDRB-IDRA) Non-firm CC = (300-200)*(40-20) = $2000 RTO Congestion Costs = $2000 RTO is Revenue Neutral 2001 SERC Conference

  31. FTR Congestion Hedging IDRA = $20/MW IDRB = $40/MW A B Congestion Costs Paid by FTR Customers = $0 Congestion Costs Paid by Non FTR Customers = $2000 RTO Congestion Costs = $2000 The Model Directly Assigns Congestion Costs to Those Creating the Congestion 2001 SERC Conference

  32. FTR Congestion Hedging TTCA-B = 600 MW A B Firm FTRs = 1000 MW Total Scheduled Flow = 1100MW Firm Scheduled = 800 MW Non Firm Scheduled = 300 MW Additional redispatch required = 500 MW. Additional redispatch available = 200 MW. 1. Curtail 300 MW nonfirm. 2. Use 200 MW of redispatch for firm. 3. If TTC drops below 600 MW, curtail firm on a priority basis.

  33. Model Summary • LMPs are charged/paid based on deviations from schedule. • Neither a Pool nor a PX are required. • Bilateral contracts are the primary power market. • Congestion costs are paid only by those creating the congestion. 2001 SERC Conference

  34. Model Summary • Firm customers make no congestion cost payments unless they cause the congestion. • FTRs allocated based on flowgate impact. • FTRs can be used for alternate paths that impact the same flowgate. • FTRs provide incentive to sell unused rights into market. 2001 SERC Conference

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