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Revenue Neutrality Uplift / Congestion Management Tools and Processes Workshop

September 13, 2007. Revenue Neutrality Uplift / Congestion Management Tools and Processes Workshop. Topics. SPP’s Congestion Management Tools and Processes Impacts of Congestion and Schedule Feasibility on RNU Examples of Schedule Feasibility Analysis of High RNU Periods

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Revenue Neutrality Uplift / Congestion Management Tools and Processes Workshop

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  1. September 13, 2007 Revenue Neutrality Uplift / Congestion Management Tools and Processes Workshop

  2. Topics • SPP’s Congestion Management Tools and Processes • Impacts of Congestion and Schedule Feasibility on RNU • Examples of Schedule Feasibility • Analysis of High RNU Periods • Congestion Management and RNU-Related Enhancements • Issues to be Discussed • Open Discussion

  3. SPP’s Congestion Management Tools and Processes

  4. Congestion Management Process Typical Sequence of Events • Flow approaches or exceeds flowgate limit • Reliability Coordinator calls TLR and requests relief from IDC • NERC IDC prescribes Tag, Network and Native Load (NNL), and/or Market Flow curtailments as appropriate • Constraint Manager and CAT receive Target Market Flow from IDC • SPP RC accepts TLR event in Constraint Manager and verifies that the effective limit is appropriate • SPP CAT will calculate appropriate schedule adjustments for those schedules not curtailed by IDC and send to RTOSS • Flowgate is activated in next Security Constrained Economic Dispatch (SCED) • Market System will run SCED, attempting to keep flowgate flow below effective limit • RC continues to monitor flowgate flow and ask for additional relief as necessary

  5. SPP Congestion Management Tools • Market Flow Calculator • SPP tool used to calculate impacts of SPP market dispatched generation and native load schedules on flowgates • Market flow in appropriate priorities are calculated for current hour and next hour and submitted to IDC every 15 minutes • Interchange Distribution Calculator (IDC) • NERC tool used by Eastern Interconnection RCs to manage parallel flows • Calculates impact of tagged transactions and Network/Native Load (NNL) on flowgates • Prescribes equitable curtailment of tags, NNL, and market flow • Curtailment/Adjustment Tool (CAT) • SPP tool used to administer curtailments and/or adjustments of schedules not curtailed by the IDC when market flow reduction is required • “Curtailments” describes reductions of schedules from self-dispatched resources • “Adjustments” describes reductions of schedules from market-offered resources • Constraint Manager • SPP tool used by the Reliability Coordinator as an interface to MOS and IDC • Displays pertinent constraint data and allows for data input necessary to facilitate constraint management • Market Operations System (MOS) • Employs Security Constrained Economic Dispatch (SCED) logic to calculate a dispatch solution that attempts to maintain flow at or below the effective limit of any activated constraints

  6. Interaction of Congestion Management Tools Tag Curtailments 2 Target Market Flow to SPP CAT 3 SPP CAT RTOSS Adjusted Schedules RC Issues TLR NERC IDC 2 5 1 Effective Limit Of Constraint Target Market Flow to SPP Constraint Manager 4 SPP MOS SCED Run Constraint Manager 6 SPP RC accepts TLR 4 Dispatch Instructions and NSI values

  7. SPP Market Flow Calculator • Market flow is currently calculated using impacts down to 0% of generators within SPP market footprint • Market flow is calculated and submitted to the IDC in both forward and reverse quantities • Market flow is calculated on Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs) • CFs are all flowgates, both internal and external, impacted by SPP as determined by CMP required analyses • Market Flow priorities can be F-7 or NN-6 • RCFs are those CFs also impacted by another party to the CMP (such as MISO, PJM, TVA, MAPP, etc.) • Market Flow priorities can be F-7, NN-6, NH-2

  8. IDC/CAT Curtailment / Adjustment Responsibilities • NERC IDC • Tagged Interchange Transactions that leave or enter SPP Market footprint • Tagged Interchange Transactions from Self-Dispatched units • Other Tagged Transactions external to SPP • Network and Native Load (NNL) external to SPP market footprint • Market Flow • SPP CAT • Tagged Interchange Transactions from units that are not Self-Dispatched • Intra-BA Schedules from Market-Dispatched units (NLS or Tagged) • Intra-BA Schedules from Self-Dispatched units (NLS or Tagged)

  9. SPP Market Footprint Tag 6 WR MISO KCPL Schedule 1* Lacygne 1 Tag 3 HEC JEC Tag 1* Tag 5 Tag 4 EES Tag 2 OKGE HSL Self-dispatched Tag 7* Pirkey Schedule 2* AEP Welsh Offered into SPP Market

  10. NERC IDC – CATTime Line 6 SCED runs at 8.50 AM for interval HE 9.05 4 RC accepts limit in Constraint Manager 8.30 9.00 AM 9.30 8.00 AM 10.00 AM 8.15 8.45 9.15 9.45 2 3 Issue TLR + NERC IDC Run Calculate next hour curtailments CAT run 8.36 AM/8.51 AM Calculate next hour adjustment schedules 1

  11. CAT Logic CAT will adjust EIS and Schedules to accomplish required reduction Current Hour Net Market Flow Required Reduction Net Market Flow Market Flow Target NERC IDC CAT priority order is as follows: Sched priority 0 Sched Priority 1 EIS-2 Sched Priority 2 Sched Priority 3 Sched Priority 4 Sched Priority 5 EIS-6 Sched Priority 6 EIS-7 Sched Priority 7 CAT gets Market Flow Target from IDC (Net) CAT gets Current Hour Net Market Flow from MFC

  12. CAT’s Priority of Curtailments/Adjustments • CAT priority order is as follows: • Sched Priority 0 • Sched Priority 1 • EIS-2 = NH2 net Market Flow – NH2 net schedule impacts (can be negative) • Sched Priority 2 • Sched Priority 3 • Sched Priority 4 • Sched Priority 5 • EIS-6 = NN6 net Market Flow – NN6 net schedule impacts (can be negative) • Sched Priority 6 • EIS-7 = F7 net Market Flow – F7 net schedule impacts (can be negative) • Sched Priority 7

  13. CAT Logic and Negative EIS • CAT Logic will adjust schedules to such amount that the required Market Flow reduction is accomplished • CAT Logic will adjust additional schedules as necessary to remove negative EIS

  14. Impacts of Congestion and Schedule Feasibility on RNU

  15. Definition of RNU • As defined in the SPP OATT - A Market Participant’s hourly charge associated with an EIS Market revenue shortfall that is created when the total of all Energy Imbalance Service Charges in an hour or a Market Participant’s hourly credit associated with an EIS Market revenue excess that is created when the total of all Energy Imbalance Service Charges is greater than the total of all Energy Imbalance Service Credits in an hour. • Simply put, RNU is a net result of the charges and payments of all Market Participants over an hour. • RNU can be positive or negative • Positive = insufficient revenue received by SPP • Negative = excessive revenue received by SPP

  16. Contributions to RNU • Difference between EIS charges and credits • Congestion can result in price separation and schedule curtailments which can exacerbate this difference • Includes inadvertent between SPP Market and external BAs • Uninstructed deviation charges • Over-scheduling • Under-scheduling • Self-provided loss differential Focus of this presentation

  17. What is Schedule Feasibility? • Technical definition • Difference between the operating limit of a flowgate and the net impact on that flowgate of all schedules known to the market system • Includes schedules assessed on the source-to-sink transfer distribution factor down to 0% and the impacts of parallel flow outside the market footprint • Practical application • SPP is using net EIS calculated in CAT to determine if the market is providing “counter-flow” on a flowgate • Net EIS is the net total Market Flow minus the net total impact of schedules in CAT • If net EIS is negative, schedules are infeasible • If net EIS is positive, schedules are feasible

  18. Why is Schedule Feasibility Important? • SPP Market Protocols require SPP to curtail schedules to an amount such that the EIS Market is not providing counter-flow on a flowgate that is in TLR • Schedule infeasibility during congestion is an indication that the EIS Market is providing counter-flow to help control flow on congested flowgate(s) • Schedule infeasibility during congestion can have a large impact on RNU

  19. Schedule Feasibility and RNU During Congestion • To the extent the impacts of schedules are under the operating limit of the constraint • The redispatch of market resources is funded by exposure to the market resulting from schedule curtailments • No additional RNU results from this activity • To the extent scheduled impacts exceed the operating limit • Insufficient schedule curtailments are present – market is providing counter-flow • SPP does not collect sufficient funds to compensate generators redispatching to resolve the constraint • Significant RNU may result, especially with large price separation

  20. EIS = Net Market Flow - Net Impact CAT Schedules Net Market Flow Net impact schedules EIS Counter Flow Net impact schedules Net Market Flow Forward Impact schedules Forward Market Flow Reverse Market Flow Reverse Impact schedules Impact CAT Schedules down to 0% Market Flow down to 0%

  21. Example of Negative EIS BA A Load 1500 MW BA B Load 1500 MW CAT Schedule 400 MW 600 400 400 Flowgate 600 500 500 Market Flow 200 MW EIS = Market Flow – CAT Scheduled Impact -200 = 200 - 400 Market dispatched unit Self dispatched unit

  22. Previous Example: Removing Negative EIS • If flowgate is overloaded and flow needs to be reduced from 200  150 MW • Market System (SCED) will redispatch to create 50 MW Market Flow reduction from 200  150 MW (physical relief) • Schedules need to be curtailed from 400 MW  150 MW to remove the negative EIS • Physical relief occurs from SCED • Schedule curtailment is necessary to maintain schedule feasibility but will not necessarily effect physical relief

  23. Relationship between RNU and Infeasibility Negative EIS Positive RNU 0 Generally removing negative EIS lowers the RNU level, however may not bring RNU to 0 0 0 RNU scale Infeasibility = negative EIS scale

  24. Possible States of Flowgate in SPP Tools • Activated, but not binding or violated. • Market System is able to dispatch economically with a resulting flowgate flow lower than its effective limit • No price separation exists • No different than a SCED run without flowgate activated • Binding, not violated • Market System redispatches keeping flowgate flow at its effective limit • Price separation exists • Violated • Market System is unable to keep flowgate flow at or below the effective limit (e.g., insufficient ramp rate, lack of sufficient adjustable generation impacting flowgate, etc.) • Price separation exists and can be significant • Negative LIP prices can exist on constraint side of flowgate as a result

  25. Congestion Examples Impacting RNU Note: Yes (+) means adjusting schedules below dispatch instructions

  26. Diagram 1. Constraint Violated, TLR Issued • SPP RC issued TLR, flowgate was violated • Market system unable to reduce flow to effective limit • Prices separation exists: assume -$1,500 on constrained side of flowgate and $200 on unconstrained side of flowgate • Resources are dispatched on constrained side below scheduled values • Resources are dispatched on unconstrained side above scheduled values • No adjustment / curtailment of schedules

  27. actual DIAGRAM 1. Generation Generation 200 MW schedule schedule 200 MW LIP=200 LIP=-1,500 +$40,000 actual + $300,000 Resource is paid substantial EIS amount Resource is paid high EIS amount schedule Constraint Violated RNU = $340,000 schedule actual actual LIP=40 LIP=60 +/-$0 +/-$0 Load has no or low EIS amount Load has no or low EIS amount Load Load

  28. Response to Situation in Diagram 1. • Identify reason why Market System is not able to reduce flow to the effective limit • Ask for more relief in NERC IDC if additional schedules could be curtailed to get more physical relief • Consider going to higher TLR level if that could help situation • Contact Market Participants if necessary to get possible limitations resolved (e.g., locked out units, high min or low max of resources) • Contact Transmission Owner to discuss the situation and maybe develop temporary operating guide that would allow a temporary higher flowgate limit • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  29. Diagram 2 SPD Able to Control Flow Constraint Binding, No Curtailments • SPP RC issued TLR • Flowgate was activated in SPD and SPD bound the constraint • Prices separation exists: assume $20 on constrained side of flowgate and $150 on un-constrained side of flowgate • SPD dispatches resources down, below scheduled values, on constrained side of flowgate • SPD dispatches resources up, above scheduled values, on un-constrained side of flowgate • No adjustment / curtailment of schedules

  30. actual DIAGRAM 2. Generation Generation 200 MW schedule schedule 200 MW LIP=20 LIP=150 actual -$4,000 +$30,000 Resource pays low /medium EIS amount Resource is paid high EIS amount schedule Constraint Binding RNU = $26,000 schedule actual actual LIP=30 LIP=60 +/-$0 +/-$0 Load has no or low EIS amount Load has no or low EIS amount Load Load

  31. Response to Situation in Diagram 2 • Physical relief was accomplished, RC will monitor real time flow and adjust effective limit in Constraint Manager, as necessary • Review NERC IDC schedule curtailments in relation to provided market flow relief and ask for more (or less) relief in NERC IDC, as necessary • Consider going to higher TLR level, if necessary • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  32. Diagram 3Constraint Binding, Schedules Curtailed • SPP RC issued TLR • Flowgate was activated in SPD and SPD bound the constraint • SPD was able to keep flow below effective limit • Price separation exists: assume $20 on constrained side of flowgate and $150 on un-constrained side of flowgate • SPD dispatches resources down, below scheduled values on constrained side of flowgate • SPD dispatches resources up, above scheduled values, on un-constrained side of flowgate • Both NERC IDC and CAT are adjusting / curtailing schedules (including NLS) • Schedules of resources on constrained side are not curtailed lower than the dispatch value

  33. actual DIAGRAM 3. Generation Generation 200 MW schedule Curtailment 150 MW schedule LIP=20 LIP=150 -$1,000 actual +$30,000 Resource pays very low EIS amount Resource is paid high EIS amount schedule Constraint binding RNU = $20,750 actual actual Curtailment 25 MW Curtailment 125 MW schedule LIP=30 LIP=60 -$750 -$7,500 Load pays low EIS amount Load pays medium / high EIS amount Load Load

  34. Response to Situation in Diagram 3(Same As 2) • Physical relief was accomplished, RC will monitor real time flow and adjust effective limit in Constraint Manager, as necessary • Review NERC IDC schedule curtailments in relation to provided Market flow relief and ask for more (or less) relief in NERC IDC, if necessary • Consider going to higher TLR level, if necessary • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  35. Diagram 4Constraint Binding, Schedules Curtailed Below Dispatch Value • SPP RC issued TLR • Flow gate was activated in SPD and SPD bound the constraint • SPD was able to keep flow below effective limit • Price separation exists: assume $20 on constrained side of flowgate and $150 on un-constrained side of flowgate • SPD dispatches resources down on constrained side of flowgate • SPD dispatches resources up, above scheduled values, on un-constrained side of flowgate • Over adjustment / curtailment of schedules (including NLS) • Schedules of resources on constrained side of flowgate are curtailed/adjusted below dispatch value

  36. actual DIAGRAM 4. Generation Generation 200 MW schedule 200 MW Curtailment 300 MW LIP=20 actual LIP=150 +$2,000 +$30,000 schedule Resource is paid low / medium EIS amount Resource is paid high EIS amount schedule Constraint binding RNU = $15,500 actual actual Curtailment 50 MW schedule Curtailment 250 MW LIP=30 LIP=60 -$1,500 -$15,000 Load pays medium /low EIS amount Load pays medium /high EIS amount Load Load

  37. Response to Situation in Diagram 4 (Same As 2) • Physical relief was accomplished, RC will monitor real time flow and adjust effective limit in Constraint Manager, as necessary • Review NERC IDC schedule curtailments in relation to provided Market flow relief and ask for more (or less) relief in NERC IDC, if necessary • Consider going to higher TLR level, if necessary • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  38. Diagram 5Constraint Violated, Schedules Curtailed Below Dispatch Value • SPP RC issued TLR • Flow gate was activated in SPD and SPD violated the constraint • SPD is not able to keep flow below effective limit • Price separation exists: assume -$1500 on constrained side of flowgate and $200 on un-constrained side of flowgate • SPD dispatches resources down on constrained side of flowgate • SPD dispatches resources up, above scheduled values, on un-constrained side of flowgate • Schedules of resources on constrained side of flowgate are curtailed / adjusted below dispatch value

  39. actual DIAGRAM 5. Generation Generation 200 MW schedule Curtailment 300 MW 200 MW LIP= -1,500 LIP=200 actual -$150,000 +$40,000 schedule Resource pays high EIS amount Resource is paid high EIS amount schedule Constraint violated RNU = -$127,000 actual actual Curtailment 50 MW schedule Curtailment 250 MW LIP=40 LIP=60 -$2,000 -$15,000 Load pays medium /low EIS amount Load pays medium /high EIS amount Load Load

  40. Response to Situation in Diagram 5(Same As 1) • Identify reason why Market System is not able to reduce flow to the effective limit • Ask for more relief in NERC IDC if additional schedules could be curtailed to get more physical relief • Consider going to higher TLR level if that could help situation • Contact Market Participants if necessary to get possible limitations resolved (e.g., locked out units, high min or low max of resources) • Contact Transmission Owner to discuss the situation and maybe come up with temporary operating guide that would allow a temporary higher flow gate limit • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  41. Diagram 6 Constraint Violated, Schedules Curtailed • SPP RC issued TLR • Flowgate was activated in SPD and SPD violated the constraint • SPD is not able to keep flow below effective limit • Price separation exists: assume -$1,500 on constrained side of flowgate and $200 on un-constrained side of flowgate • SPD dispatches resources down, below scheduled values, on constrained side of flowgate • SPD dispatches resources up, above scheduled values, on un-constrained side of flowgate • Adjustment / curtailment of schedules (including NLS)

  42. actual DIAGRAM 6. Generation Generation 200 MW schedule Curtailment 150 MW schedule LIP=-1,500 LIP=200 +$75,000 actual +$40,000 Resource is paid high EIS amount Resource is paid high EIS amount schedule Constraint violated RNU = $106,500 actual actual Curtailment 25 MW schedule Curtailment 125 MW LIP=40 LIP=60 -$1,000 -$7,500 Load pays low EIS amount Load pays medium EIS amount Load Load

  43. Response to Situation in Diagram 6(Same As 1) • Identify reason why Market System is not able to reduce flow to the effective limit • Ask for more relief in NERC IDC if additional schedules could be curtailed to get more physical relief • Consider going to higher TLR level if that could help situation • Contact Market Participants if necessary to get possible limitations resolved (e.g., locked out units, high min or low max of resources) • Contact Transmission Owner to discuss the situation and maybe come up with temporary operating guide that would allow a temporary higher flow gate limit • Check feasibility of schedules and issue higher level TLR, if necessary to remove negative EIS

  44. Conclusions about Schedule Feasibility and RNU • Maintaining schedule feasibility during congestion reduces EIS RNU • Resulting schedules do not match dispatch instructions • Curtailments are schedule reductions only • Redispatch actions can both increase and decrease generation associated with those schedules • SCED considers both $ and MW impact of generation dispatch • CAT only considers MW impact on flowgate • Almost impossible to achieve zero RNU even with schedule feasibility

  45. Examples of Schedule Feasibility and RNU

  46. Schedule Feasibility Example – Congestion with no EIS Schedule = 200 MW DI = 200 LIP = $20 GSF = 0.4 MW GLDF = 0.4 – (-0.2) = 0.6 ~ Actual = 500 Schedule = 500 LDF = -0.2 LIP = $60 Aggregate Load 1 Unit 3 Flowgate Operating Limit = 200 MW Impact of all schedules = 200 (.6) + 200 (.6) + 100 (-0.4) = 200 ~ Unit 1 ~ Schedule = 200 MW DI = 200 LIP = $20 GSF = 0.4 GLDF = 0.4 – (-0.2) = 0.6 Schedule= 100 MW DI = 100 MW LIP = $100 GSF = -0.6 GLDF = -0.6 – (-0.2) = -0.4 Unit 2

  47. Settlement Under Feasible State with no EIS • Unit 1 • EI = (Schedule – Actual) *LIP = (100-100)*$100 = $0 • Units 2 & 3 • EI = (Schedule – Actual) *LIP = (200-200)*$20 = $0 • Aggregate Load 1 • EI = (Schedule – Actual) *LIP = (500-500)*$60= $0

  48. Schedule Infeasibility Example – Congestion with Redispatch but No Curtailments Aggregate Load 1 ~ Actual = 500 Schedule = 500 LDF = -0.2 LIP = $60 Schedule = 200 MW DI = 180 LIP = $20 GSF = 0.4 MW GLDF = 0.4 – (-0.2) = 0.6 Unit 3 Flowgate Operating Limit = 160 MW Schedule Impact = 200 Impact from market dispatch = 180 (.6) + 180 (.6) + 140 (-0.4) = 160 ~ Unit 1 Schedule = 200 MW DI = 180 LIP = $20 GSF = 0.4 GLDF = 0.4 – (-0.2) = 0.6 Schedule= 100 MW DI = 140 MW LIP = $100 GSF = -0.6 GLDF = -0.6 – (-0.2) = -0.4 ~ Unit 2

  49. Settlement Under Infeasible State – No Curtailments • Unit 1 • EI = (Schedule – Actual) *LIP = (100-140)*$100 = -$4,000 • Net Revenue = -$4,000 (Credit) • Units 2 & 3 • EI = (Schedule – Actual) *LIP = (200-180)*$20 = $400 • Net Revenue = $400 * 2 units = $800 (Charge) • Aggregate Load • EI = (Schedule – Actual) *LIP = (500-500)*$60 = $0 • Total Revenue = -$4,000 + $800 = -$3,200 (Credit) • Results in EIS RNU of $3,200

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