3What is a flowgate?LODF = Line Outage Distribution Factor indicated % of the flow of the Contingency element that will end up on Monitored element if Contingency trips.Every flowgate has a rating provided by owner of the monitored element. Rating is called SOL (System Operating Limit). NERC Standards require action by RC to maintain flow of flowgate below SOL limit.Some flowgates have a second rating that is called IROL. Those flowgates are critical facilities and if they trip can cause cascade outages. The IROL limit is calculated by off line stability studies. NERC Standards require action if flowgate flow > IROL limit and relief need to be provided within 30 minutes.
4Elements of a Flowgate A Flowgate is either a PTDF or OTDF type PTDF is a Power Transfer Distribution Flowgate that is typically controlling monitored transmission elements to a total real-time flowOTDF is an Outage Transfer Distribution Flowgate that is controlling transmission elements in a ‘what-if’ n-1 situation; The Reliability Coordinator controls the flowgate of a monitored element such that if a contingent element trips, the element monitored is not overloaded
5PTDF Flowgate ExampleA collection of Transmission system elements grouped together and controlled to a collective ratingFlowgate examples: SPPSPSTIES, SPSSPPTIES, GENTLMREDWIL
6OTDF Flowgate ExampleWhat if situation: one line for the loss of another; for example: LAKALASTJHAWLake Road -> Alabama 161kV ftlo St Joe -> Hawthorn 345kVIf the contingent element trips, a portion (0-100%) of the power flows onto the monitored elementClassic n-1 contingency; most flowgates fall in this category
7Permanent & Temporary Flowgates Permanent Flowgates are previously identified constrained paths on the SPP Transmission system as well as external areas to SPP that may be impacted by SPP serving loadTemporary Flowgates are built ‘on-the-fly’ to control the unknown or short-term issuesThese may be due to planned or unplanned outagesUnforeseen loading may cause a temporary
8Monitoring Real Time loading of flowgates Real Time loading flowgate
9IDC/CAT Curtailment / Adjustment Responsibilities NERC IDC Curtailments based on TDF (Gen to Gen)Tagged Interchange Transactions that leave or enter SPP Market footprint.Tagged Interchange Transactions from Self-Dispatched unitsOther Tagged Transactions external to SPPNetwork and Native Load (NNL) external to SPP market footprintMarket FlowSPP CAT Curtailments/Adjustments based on GLDF (Gen to Load)Tagged Interchange Transactions from units that are not Self-Dispatched. (Inter Control Area)Intra-BA Schedules from Market-Dispatched units (NLS or Tagged)Intra-BA Schedules from Self-Dispatched units (NLS or Tagged)
11History of NERC and NERC Standards IRO Reliability Coordination — Transmission Loading ReliefIDC BackgroundIDC InputsTLR LevelsIDC Factors
12Transmission Loading Relief (TLR) The Reliability Coordinators of the Eastern Interconnect use a Transmission Loading Relief tool that is called NERC IDC.In case of an overload on the Eastern Interconnect Transmission System, a Reliability Coordinator can call a Transmission Loading Relief (TLR) event on NERC IDC.The Transmission Loading Relief (TLR) event triggers a calculation by NERC IDC Software that results in:Tag curtailments assigned to Tags and Schedules that have more than 5% impact on the constrained facility that is in TLRMarket Flow relief assigned to the SPP Market, MISO Market and PJM Market if they impact the constrained facility.NNL Obligation assigned to Non-Market Balancing Authorities that require them to re-dispatch generation to accomplish the assigned relief amount.NERC IDC will send out the curtailment and relief information to the Etagging Systems and other Systems of Reliability Coordinators.
14Standard IRO-006-4 — Reliability Coordination — Transmission Loading Relief A. Introduction1. Title: Reliability Coordination — Transmission Loading Relief (TLR)2. Number: IRO-006-43. Purpose: The purpose of this standard is to provide Interconnection-wide transmission loading relief procedures that can be used to prevent or manage potential or actual SOL and IROL violations to maintain reliability of the Bulk Electric System.4. Applicability:4.1. Reliability Coordinators.4.2. Transmission Operators.4.3. Balancing Authorities.
15NERC Standard IRO-006-4 TLR R1. A Reliability Coordinator experiencing a potential or actual SOL or IROL violation within its Reliability Coordinator Area shall, with its authority and at its discretion, select one or more procedures to provide transmission loading relief. These procedures can be a “local” (regional, interregional, or sub-regional) transmission loading relief procedure or one of the following Interconnection-wide procedures
16NERC Standard IRO-006-4 TLR R1.1. The Interconnection-wide Transmission Loading Relief (TLR) procedure for use in the Eastern Interconnection provided in Attachment 1-IRO The TLR procedure alone is an inappropriate and ineffective tool to mitigate an IROL violation due to the time required to implement the procedure. Other acceptable and more effective procedures to mitigate actual IROL violations include: reconfiguration, redispatch, or load shedding
17NERC Standard IRO-006-4 TLR R3. Each Reliability Coordinator with a relief obligation from an Interconnection-wide procedure shall follow the curtailments as directed by the Interconnection-wide procedure. A Reliability Coordinator desiring to use a local procedure as a substitute for curtailments as directed by the Interconnection-wide procedure shall obtain prior approval of the local procedure from the ERO.
18NERC Standard IRO-006-4 TLR R4. When Interconnection-wide procedures are implemented to curtail Interchange Transactions that cross an Interconnection boundary, each Reliability Coordinator shall comply with the provisions of the Interconnection-wide procedure.
19Interchange Distribution Calculator IDC was created to implement the TLR process explained in IRO-006 Attachment 1Procedures for curtailment and reloading of Interchange Transaction to relieve overloads on transmission facilities modeled in the IDCIDC is a NERC Tool for the Eastern InterconnectThe IDCWG is a NERC working group that is responsible for implementing IDC and other tools in support of the NERC RC’s.The IDCWG reports to the Operating Reliability Subcommittee (ORS)
20Inputs to IDC Monthly Model developed by the IDCWG System Data Exchange (SDX) every 20 minuteseTagMarginal Zones from PJM (every 5 min) and MISO (quarterly) **Not used**Market Flow SPP/PJM/MISOPhase shifter Tap settings
21TLR LevelsTLR Level 1 — Notify Reliability Coordinators of potential SOL or IROL ViolationsTLR Level 2 — Hold transfers at present level to prevent SOL or IROL ViolationsTLR Level 3a — Reallocation of Transmission Service by curtailing Interchange Transactions using Non-firm Point-to-Point Transmission Service to allow Interchange Transactions using higher priority Transmission ServiceTLR Level 3b — Curtail Interchange Transactions using Non-Firm Transmission Service Arrangements to mitigate a SOL or IROL Violation
22TLR Levels Continued TLR Level 4 — Reconfigure Transmission TLR Level 5a — Reallocation of Transmission Service by curtailing Interchange Transactions using Firm Point-to-Point Transmission Service on a pro rata basis to allow additional Interchange Transactions using Firm Point-to-Point Transmission ServiceTLR Level 5b — Curtail Interchange Transactions using Firm Point-to-Point Transmission Service to mitigate an SOL or IROL violationTLR Level 6 — Emergency ProceduresTLR Level 0 — TLR concluded
23What is a Schedule?A schedule represents a physical transaction on the Transmission System between a Source and a Sink.All schedules that cross BA boundaries require a Tag in the Etagging System of the Eastern Interconnect. (Source and Sink of the schedule are in different Balancing Authority Areas).Schedules typically have an hourly profile, although it is possible to have 5 minute granularity.A Balancing Authority will add up all import and export schedules from its Control Area to determine the Net Scheduled Interchange value (NSI value) for a particular hour for his BA area.Tags / Schedules need to be submitted at least 20 minutes and in some cases 30 minutes before they are supposed to be flowing
24How a Schedule is created? Confirmed TSR (Transmission Service Request) on the transmission system for full path of the intended Schedule / Tag.The Transmission Rights and TAG on the approved path may be used by customer between the Source BA and Sink BA.The schedules are then created in E-Tag System and other SPP scheduling System (RTOSS)Scheduling systems (RTOSS for SPP) validates the Schedule against Transmission Rights and approve the schedule.Net Scheduled Interchange for a BA is calculated from the set of schedules that is available in the Scheduling System.
25Priority of Transmission Rights determine sequence of curtailing in case of an over load situation that required calling TLR on NERC IDCSecondary Non-Firm (late redirect from Firm) NS1Non-Firm PTP Hourly NH2Non Firm PTP Daily ND3Non Firm PTP Weekly NW4Non Firm PTP Monthly NM5Non Firm Network (Non-designated) NN6 Voluntarily dispatch before going to TLR Level 5Firm PTP (All) F7Firm Network (designated Resources) NF7 (accomplished by re-dispatching Units)Load sheddingTLRLevel 3TLRLevel 4TLRLevel 5
26How is the priority of schedules determined Schedule priority is determined by the priority of the TSR (Transmission Service Right) purchased by the Transmission customer.The higher the priority the more the schedules are “protected” against curtailments by NERC IDC and CAT in case of a TLR event.
27Introduction to IDC Factors TDF –Transfer Distribution FactorGSF –Generation Shift FactorLSF –Load Shift FactorGLDF –Generation-to-Load Distribution FactorLODF –Line Outage Distribution FactorPTDF & OTDF Flowgates
28Transfer Distribution Factors Transfer Distribution Factors (TDF’s) represent the impact of an Interchange Transaction on a given flowgate.TDF is the measure of responsiveness or change in electrical loading on system facilities due to a change in electric power transfer from one area to another expressed in percent (up to 100%) of the change in power transfer.TDFs address the question, “What portion of a power transfer shows up on flowgate X?”
29TDFs used in the IDCTDFs are used to determine which Interchange Transactions are eligible for TLR curtailment in the IDC.Only those Interchange Transactions with a TDF of 5% or greater are subject to TLR Curtailments.If a tag indicates a TDF of 8.3% on flowgate X, this means that 8.3% of the transfer amount on that tag flows on flowgate X.Use the following formula to calculate the MW impact on a flowgate for a particular Interchange Transaction: MW impact = (Interchange transaction MW) x (TDF)
30Generation Shift Factors Generation Shift Factors (GSF) describe a generator’s impact on a flowgateThe Generation Shift Factors (GSF) represent the change in flow on a flowgate due to an incremental injection at a generator bus, and a corresponding withdrawal at the swing busIDC disregards losses ⇒the principles of superposition applies.GSF between any two generators is the difference between the generators’ GSF to the swing busGSFk→m= GSFk→swing–GSFm→swing
31GSF Used in the IDCGSFs are the most basic IDC calculation –used in TDF calculations (all TLR levels) and GLDF calculations (TLR level 5)GSFs on the Flowgate GSF display in the IDC indicate which generators contribute to or relieve congestion on a selected flowgate.If a generator indicates a GSF of 10% on flowgate X, this means that 10% of the generator’s output flows on flowgate X, provided the injection is withdrawn at the swing busUse the following formula to calculate the MW impact on a flowgate for a particular generator:MW impact = (Gen MW) x (GSF)
32Load Shift FactorsLoad Shift Factors (LSF) describe how changes in system loading impacts a flowgate.
33LSF Used in the IDC?LSFs are used to calculate GLDFs, which are used to determine NNL obligations under a TLR Level 5.LSFs are shown along with GSFs on the GLDF displays in the the IDC.The LSFs alone are not used by the IDC – the LSF is a component of the Generation-to-Load Distribution Factor (GLDF)
34Generation-to-Load Distribution Factors Generation-to-Load Distribution Factors (GLDF) describe a generator’s impact on a flowgate while serving load in that generator’s Balancing Authority AreaA GLDF is the difference between GSF and an LSF and determines the total impact of a generator serving its native Balancing Authority load on an identified monitored flowgate.
35GLDF Used in the IDCGLDFs are used to determine NNL obligations under a TLR Level 5.Only those generators with a GLDF of 5% or greater are subject to NNL obligations.GLDFs are shown in the Flowgate GLDF display and the CA GLDF display in the IDC.In the Flowgate GLDF display the user selects a flowgate and is shown a list of generators that contribute to flow as a byproduct of serving their own Balancing Authority Area load (i.e., the NNL impact).In the CA GLDF display, the user is shown a listing of flowgates that are impacted by generators serving their own Balancing Authority Area load.
36GLDF Used in the IDC Continued Use the following formula to calculate the NNL MW impact on a flowgate for a particular generator:NNL MW impact = (Scaled MW) x (GLDF) x (% ownership)Scaled MW is calculated according to the following formula: Scaled MW = (Load / Available Assigned Generation) x (Pmax)If a generator indicates a GLDF of 9.7% on flowgate X, this means that 9.7% of the generator’s output flows on flowgate X as a byproduct of serving Balancing Authority Area native load.The GLDF is calculated according to the following formula:GLDF = GSF -LSF
37Line Outage Distribution Factor (LODF) Line Outage Distribution Factor (LODF) represents the percentage of flow on a contingent facility that will flow on the monitored elements, if the contingent facility is outaged–Contingency AnalysisPost-Contingency Flow on Monitored Element = Pre-Contingency Flow on Monitored Element + (Pre-Contingency Flow on Contingent Element)*LODFLODFs are not used in IDC TLR calculations
38PTDF & OTDF FlowgatesPTDF –Power Transfer Distribution Factor. PTDF Flowgates are Flowgates that do not consider contingencies during curtailment evaluation. With PTDF Flowgates the monitored branches alone are considered during evaluation.OTDF –Outage Transfer Distribution Factor. OTDF Flowgates are Flowgates that take into account a predefined contingency during curtailment evaluation. With OTDF Flowgates the monitored branches are considered with a specific facility removed from service during evaluation.
39How are GSF, TDF, LSF and GLDF Calculated in the IDC? All factors (GSF, TDF, LSF) are calculated from a master shift factor matrix of each bus and each flowgate every 20 minThis matrix is calculated by simulating an incremental injection in every bus (individually, one at a time) and a corresponding withdrawal at the swing bus. The term is loosely called GSF even though it is calculated for every bus, regardless of being attached to a generator.The Balancing Authority’s TDFs are calculated as the weighted sum of the GSFs in a Balancing Authority Area for every in-service generator –the weighting factors are the generators’ MBASE in the PSSE base case model, adjusted for de-ration as provided via the SDXTDF = Σ( GSF x MBASE x DE-RATION ) / Σ( MBASE x DE-RATION )The Balancing Authority’s LSFs are calculated as the weighted sum of the GSFs in a Balancing Authority Area for every connected load bus as defined in the PSSE base case –the weighting factors are the load MW amount on the buses.LSF = SUM( GSF x LOAD ) / SUM( LOAD )
40How are GSF, TDF, LSF and GLDF Calculated in the IDC? The TDF between two Balancing Authority Areas is the difference between the TDFs of the Balancing Authority Areas (principle of superposition):TDFBA1 –BA2= TDFBA1–TDFBA2The TDF of a tag is the TDF between the source and sink Control AreasTDFTag= TDFSourceBA–SinkBA= TDFSourceBA–TDFSinkBATag path:Every tag has a defined path:Source BA –TP1–TP2–…–TPn–Sink BAThe TDF of a tag is the sum of the TDFs of every segment on a tag –which is equivalent to the TDF between the source and sink BA:Segment 1:TDFSourceBA–TP1= TDFSourceBA–TDFTP1Segment 2:TDFTP1–TP2= TDFTP1–TDFTP2Last Segment:TDFTPn–SinkBA= TDFTPn–TDFSinkBATDFTag= TDFSourceBA–TDFTP1+ TDFTP1–TDFTP2+ TDFTP2–TDFTP3+ …+ TDFTPn–TDFSinkBA= TDFSourceBA–TDFSinkBA
41How are GSF, TDF, LSF and GLDF Calculated in the IDC? Tag path (continued):Special case –segmented tag, or tags through controlled devices (phase shifters and DC ties):100% of the tag scheduled MW flows through the controlled deviceTDF of tag is the sum of the TDF between the Source BA and the entry point to the controlled device, and the TDF between the exit point of the controlled device and the sink BA.Example:Tag 1 –segmented through DC/phase shifter: TDFTag1= TDFBA1 –P1+ TDFP2–TDFBA2Tag 2 –AC tag between BA-1 and BA-2: TDFTag2= TDFBA1–TDFBA2TDFTag1≠TDFTag2See diagram on the following slide
42Transmission Service Priorities Priority 0. Next-hour Market Service — NX*Priority 1. Service over secondary receipt and delivery points — NSPriority 2. Non-Firm Point-to-Point Hourly Service — NHPriority 3. Non-Firm Point-to-Point Daily Service — NDPriority 4. Non-Firm Point-to-Point Weekly Service — NWPriority 5. Non-Firm Point-to-Point Monthly Service — NMPriority 6. Network Integration Transmission Service from sources not designated as network resources — NNPriority 7. Firm Point-to-Point Transmission Service — F and Network Integration Transmission Service from Designated Resources —FN
43Con’tIDC Curtails on a pro-rata basis starting with the lowest service priorityNon Firm Service levels 0-6Firm Service level 7
44Example TLR 5 4 Firm Schedules (total of 400MW) 3200 MW of generation serving Load within BARC Relief Requested 100MW on FG X.IDC calculates relief as:Total schedule Impact divided by (Total schedule impact + Total NNL impact). SI / (SI + NNL)In this example there is no non firm interchange tags that have a TDF 5% or greater
45Example TLR 5Tags MW TDF% Total Schedule Impact on FGABCDTotalGen MW GLDF% Total NNL Impact on FGABCDTotal
46Example TLR 5In this example, the relief would be distributed by the above mentioned equation.45 / (45+295) which = 13%.13% * 100 = 13MW of relief from schedules.The remaining 87MW of relief will come from NNL.This 13 MW of relief from schedules is then distributed among all the schedules based on their TDF’s using the following equation:([Relief required] * [TDF] * [Tag MW]) divided by ([Sum of TDF^2] * [Tag MW]).Using the example schedules above in the calculation you willsee how it is distributed.
47([Relief required]. [TDF]. [Tag MW]) divided by ([Sum of TDF^2] ([Relief required] * [TDF] * [Tag MW]) divided by ([Sum of TDF^2] * [Tag MW])Relief required = 13MW([Sum of TDF^2] * [Tag MW]) = (.1)^2(100) + (.2)^2(100) + (.05)^2(150) + (.15)^2(50) = 6.5Using the equation:Tag A = (13(.1)(100))/6.5 = 20Tag B = (13(.2)(100))/6.5 = 40Tag C = (13(.05)(150))/6.5 = 15
48Therefore, 20mw would be curtailed from tag A, if you multiple that by Therefore, 20mw would be curtailed from tag A, if you multiple that by .1 TDF you will get 2 mws relief. Tag B would provide 8 mws relief, tag C would provide .75 mws relief and tag D would provide 2.25 mws relief. This relief added together will result in 13 mws relief on the FG. Therefore, it took 90 MWs of schedule curtailments to provide the 13 mws of relief on the FG. The remaining 87MW of relief would have to come from NNL obligations.
49Re-Cap of NERC IDC logic Reliability Coordinator (RC) issues (or re-issues) a TLR on a flowgateWhen RC issues TLR event he enters the TLR Level (1, 2, 3A, 3B, 4, 5A, 5B)3A is Next hour Non Firm Curtailments3B is Current hour Non Firm Curtailments5A is Next hour Firm Curtailments5B is Current hour Non Firm CurtailmentsWhen RC issues TLR he enters value for Operator Flow Change Request. (negative is asking for more curtailments and lower Market flow Target)NERC IDC calculates required curtailments and Market Flow TargetNERC IDC is sending results to SPP CAT, SPP Constraint Manager and Etagging System
51SPP Congestion Management Tools 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.Market Flow CalculatorUsed 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.
52SPP Congestion Management Tools Curtailment Adjustment Tool (CAT)Administers 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.52
54Why Calculate Market Flow? NERC IDC needs to have the impact of the SPP Market on flowgates just like it gets the impact of Tags on flowgates.That allows NERC IDC to assign relief obligation to both Tags and the Markets in case of a TLR on a flowgate.SPP reports the impact of SPP Market on flowgates every 15 minutes to NERC IDC.Allows for equity between Market and Non-Market Entities.
55SPP Market Flow Calculator SPP Market flow is calculated by the Market Flow Calculator (MFC) using impacts down to 0% of generators within SPP market footprint and additional to that Market Flow based on impacts >5%SPP Market flow is calculated every 15 minutes and submitted to NERC IDC in both forward and reverse quantities, split up in 3 priorities, NH-2, NN6 and F7(Firm).SPP Market flow is calculated on 188 Coordinated Flowgates (CFs) and 27 Reciprocal Coordinated Flowgates (RCFs)RCFs are those CFs also impacted by another party to the CMP (such as MISO, PJM, TVA, MAPP, etc.)CFs are all flowgates, both internal and external, impacted by SPP Market as determined by CMP required analyses
57SPLITTING UP MARKET FLOW IN PRIORITIES ForwardF7F7NN6NN6NH2RCF Flow gateCF Flow gate
58Market Flow split up CF flow gates Filling buckets from left to right with Market FlowNN6Firm(1)(2)Firm NNL Limitunlimited
59MARKET FLOW Total flowgate loading Flowgate loading (MW) Tags for Physical & “external” Market SchedulesNERC IDC is responsible to assign curtailment amount to the TagsSchedules from Self-dispatched ResourcesUnscheduledMarket Flow (EIS)Market Flow sent to NERC IDC by SPP.NERC IDC is responsible to assign total relief amount to SPP for the Market Flow Impact. SPP is responsible to achieve the relief both on unscheduled and scheduled part of Market Flow Impact.Impact of Parallel FlowsFlowgate loading (MW)Schedules fromMarket dispatched ResourcesMARKET FLOW
60Ways to control a Flowgate Two ways to initiate congestion management processTLR- Typically used when equity between SPP and other parties external to the SPP Market is a concern.CME- Congest Management Event: Used when there are no equity issues, ie, no external transactions (non SPP Market Impactswith a 5% or greater impact of the flowgate.
62Positive EIS / Negative EIS If the SPP Market System is dispatching different than the original CAT schedules, there will be Energy Imbalance flow on the System. There are 2 possible situations:The Energy Imbalance flow has a positive impact on the flowgate. In that case there is “positive EIS” on flowgate. Net Market Flow is > Net impact of CAT schedules.The Energy Imbalance flow has a negative impact on the flowgate. In that case there is “negative EIS” on flowgate. Net Market Flow is < Net impact of CAT schedules.
63Summary of Schedule Feasibility Netting all scheduled impacts across a flowgate interface determines the approximate flow that would occur if all generation followed schedules exactlyIf the net of these impacts across a flowgate exceeds the limit, the flowgate is considered schedule infeasibleIf the impacts across the flowgate is less than or equal to the limit, the flowgate is considered schedule feasible
64Schedule FeasibilityThrough schedule feasibility, SPP encourages participants to pay into marketExample: Generation is expected to run at 100 and scheduled at 100If SPP cuts schedule from generation to load by 20 MWThe generator becomes “long” energy, and the load becomes “short” energy and settled in the EIS marketThe difference in prices (e.g., load prices exceeding generation prices) provide money to pay for redispatchGOAL: Those who contribute to loaded flowgates pay and consequently positive RNU is reduced
65Example of Negative EIS (Schedule Infeasibility) BA ALoad 1500 MWBA BLoad 1500 MW600CAT Schedule 400 MW400400Flowgate600500500Market Flow 200 MWEIS = Market Flow – CAT Scheduled Impact-200 =Market dispatched unitSelf dispatched unit
66Removing Negative EISIf flowgate is overloaded and flow needs to be reduced from 200 150 MWMarket System (SCED) redispatch to create 50 MW Market Flow reduction from 200 150 MW (physical relief)Schedules curtailed from 400 MW 150 MW to remove the negative EISPhysical relief occurs from SCEDSchedule curtailment is necessary to maintain schedule feasibility, but will not necessarily effect physical relief
67What is Revenue Neutrality Uplift (RNU)? RNU ensures settlement payments/receipts for each hourly settlement interval equal zeroPositive RNU: SPP receives insufficient revenue and “owes” market participantsSPP charge a “tax” across the market to pay participantsNegative RNU: SPP receives excessive revenueSPP pays out a credit across the market
68Types of RNU Uninstructed deviation charges Over/under scheduling If a generator is unable to meet its dispatch instruction within an allowable toleranceOver/under schedulingIf a market participant captures profit by manipulating schedules between its own generation and load assets to arbitrage price separation difference between EIS charges and creditsSPP collects less than we pay outCongestion can result in price separation and schedule curtailments
69Types of RNU Energy Imbalance Service Over- or Under- collections due to various causes
70Positive RNU Occurs When… Load insulated from paying congestion costs because of schedulesIn other words, little or no revenue collected by SPPGenerators are compensated for relieving flowgatesBecause SPP is revenue-neutral, we can’t pay generatorsRESULT – SPP must pay generators and “tax” all participants (as shown by positive RNU)
77Settlements during Congestion with Schedules Curtailed to Feasible State Unit 1EI = (Schedule – Actual) *LIP = ( )*$100 = -$4,000Net Revenue = -$4,000 (Credit)Units 2 & 3EI = (Schedule – Actual) *LIP = ( )*$20 = $260Net Revenue = -$260 * 2 units = -$520 (Credit)Aggregate LoadEI = (Schedule – Actual) *LIP = ( )*$60 = $3,960 (Charge)
78Settlements during Congestion with Schedules Curtailed to Feasible State Total Revenue = -$4,000 - $520 + $3,960 = -$560 (Credit)Infeasible state = $3,200 EIS RNUFeasible state after curtailments = $560 EIS RNU
79Summary of Schedule Feasibility Netting all scheduled impacts across a flowgate interface determines the approximate flow that would occur if all generation followed schedules exactlyIf the net of these impacts across a flowgate exceeds the limit, the flowgate is considered schedule infeasibleRather, if the impacts across the flowgate is less than or equal to the limit, the flowgate is considered schedule feasible
80Schedule FeasibilityThrough schedule feasibility, SPP encourages participants to pay into marketExample: Generation is expected to run at 100 and scheduled at 100If SPP cuts schedule from generation to load by 20 MWThe generator becomes “long” energy, and the load becomes “short” energy and settled in the EIS marketThe difference in prices (e.g., load prices exceeding generation prices) provide money to pay for redispatchGOAL: Those who contribute to loaded flowgates pay and positive RNU is reduced
82The Major Congestion Management differences between pre & post EIS Market Pre-market: A TLR is called causing schedules to be curtailed, and then redispatch occurs to physically reduce the flow on the constraintPost-market: A TLR/CME is called at the same time as redispatch occurring to physically reduce the flow on the constraint, and then schedules are curtailedCME alone maybe sufficient if no non-SPP market impact apply.
83Schedules: IDC vs. CAT curtailables. SPP Market FootprintWRTag 6MISOKCPLSchedule 1*Lacygne1Tag 3HECJECTag 1*Tag 5Tag 4EESTag 2OKGEHSLSelf-dispatchedTag 7*PirkeySchedule 2*AEPWelshOffered into SPP Market
84CAT - Curtailment Adjustment Tool CAT is SPP Market internal tool used to curtail transactions between our Market Participants (MPs). These transactions are NOT physical transactions.Schedules curtailed by CAT are financial transactions used by the market participant to hedge against potential congestion.SPP CAT Curtailments/Adjustments based on GLDF (Gen to Load)Tagged Interchange Transactions from units that are not Self-Dispatched. (Inter Control Area)Intra-BA Schedules from Market-Dispatched units (NLS or Tagged)Intra-BA Schedules from Self-Dispatched units (NLS or Tagged)Used to maintain relationship between Market Schedules and flowgate flowImpact of all CAT < Real Time Flowgate Flow
85Interaction of Congestion Management Tools; CME in black line trace 2Tag CurtailmentsETAGGINGNLSTargetMarket Flowto SPP CATSPPCATevery 15 min3RTOSSschedulingAdjustedSchedules1RC Issues TLROr CME2NERC IDC6Effective Limitof ConstraintSent to MOS2TargetMarket Flowto SPP ConstraintManager85SPPConstraintManagerSPP MOS SCEDSFT Topper / SPDRuns every 5 minMarket Flow sentTo NERC IDC every 15 minutes4SPP RC accepts TLRMarket FlowCalculator7Dispatch Instructions and NSI values
86CAT response to TLR event SPP CAT receives TLR event from NERC IDC. Information provided by NERC IDC includes TLR level, and Net Market Flow Target.SPP CAT receives Current Net Market Flow from MFC and Schedules from RTOSSSPP CAT calculates the required curtailments of CAT Schedules using following logic.TLR 3: Adjust Non Firm Market Flow (EIS) and Non-Firm Schedules that have impact >5% to the level of Net Market Flow Target send by NERC IDC.TLR 5: Adjust Firm Market Flow (EIS) and Firm Schedules that have impact >5% to bring negative EIS to 0.(-) EIS = Net Market Flow – CAT Schedules (down to 0% Impact)SPP CAT will send the curtailed CAT schedules to RTOSS System.SPP CAT will recalculate curtailments every 30 minutes minutes (xx:12, xx:42 )
87CAT Response to CMESPP CAT receives the status of the flowgate in the Market Operating System.SPP CAT receives Current Net Market Flow from MFC and Schedules from RTOSSSPP CAT calculates the required curtailments of CAT Schedules using following logic.Non-Firm CME: Adjust Non Firm Market Flow (EIS) and Non-Firm Schedules that have impact >5% to the level of Net Market Flow Target calculated by MFC.Firm CME: Allows the Adjustment of Firm Market Flow (EIS) and Firm Schedules that have impact >5% to bring negative EIS to 0.(-) EIS = Net Market Flow – CAT Schedules (down to 0% Impact)SPP CAT will send the curtailed CAT schedules to RTOSS System.SPP CAT will recalculate curtailments every 30 minutes minutes (xx:12, xx:42 )
88CAT functionality – negative EIS - overscheduled In case of a CME, TLR 3,4 or 5 the Market System will dispatch Available resources down to relief the flow gate, basically lowering the Impact of the Energy Imbalance Flow of Market and at some time creating “counter EIS flow” on the flow gateThe Impact of Energy Imbalance Flow is negative (“negative EIS” on flow gate). In that situation the impact of CAT schedules is greater than Market Flow, this becomes a “Schedule Infeasibility” scenario. In the case of CME, in addition to the conditions above, the flowgate must at also be breaching its limit for it to be a “Schedule Infeasibility” scenario.CAT schedules are adjusted to such level that the Impact of all CAT Schedules is reduced to the Market Flow level. The Energy Imbalance Flow of flow gate is basically reduced to 0 by curtailing CAT Schedules. We then get back in a “scheduled feasible” situation.
89CAT LOGIC CAT Curtailments “CAT Scheduled Flow” 345 MW 145 Market Flow Market System (SCED)keeps total flowbelow 320 MW andpushes Market Flowdown to TargetCAT CurtailmentsCAT will adjustPos EIS andCAT schedulesto accomplishrequired reductionCAT Flow = pos EIS+ scheduled impactCAT schedules345 MWRequiredReductionCAT Flow145Market FlowTargetNERC IDC>0%200 MWCAT priority order is as follows:Sched priority 0Sched Priority 1EIS-2Sched Priority 2Sched Priority 3Sched Priority 4Sched Priority 5EIS (+30)Sched Priority (-10)EIS (-125)Sched Priority 7 (325)CAT gets Market FlowTarget from IDC (Net)“CAT Scheduled Flow”
90CAT’s Priority of Curtailments/Adjustments TLR 3Non Firm CMECAT priority order is as follows:Sched Priority 0Sched Priority 1 (NS)EIS-2 = NH2 net Market Flow – NH2 net schedule impacts (can be negative)Sched Priority 2(NH)Sched Priority 3 (ND)Sched Priority 4(NW)Sched Priority 5(NM)EIS-6 = NN6 net Market Flow – NN6 net schedule impacts (can be negative)Sched Priority 6(NN6)EIS-7 = F7 net Market Flow – F7 net schedule impacts (can be negative)Sched Priority 7 (F7)TLR 5Firm CMEWhile TLR 5 means all Non-Firm schedules are curtailed automatically whether needed or not, Firm CME will only curtail as much as it needs (i.e. Firm CME may only curtail Sched Priority 0 if that is all required to become schedule feasible)