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www.spp.org Overview IDC – Interchange Distribution Calculator Market Flow Calculator Revenue Uplift / Schedule Infeasibility CAT – Curtailment Adjustment.

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Presentation on theme: "www.spp.org Overview IDC – Interchange Distribution Calculator Market Flow Calculator Revenue Uplift / Schedule Infeasibility CAT – Curtailment Adjustment."— Presentation transcript:

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2 www.spp.org Overview IDC – Interchange Distribution Calculator Market Flow Calculator Revenue Uplift / Schedule Infeasibility CAT – Curtailment Adjustment Tool 2

3 www.spp.org 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. What is a flowgate? 3

4 www.spp.org Elements 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 flow OTDF 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 4

5 www.spp.org PTDF Flowgate Example A collection of Transmission system elements grouped together and controlled to a collective rating Flowgate examples: SPPSPSTIES, SPSSPPTIES, GENTLMREDWIL 5

6 www.spp.org OTDF Flowgate Example What if situation: one line for the loss of another; for example: LAKALASTJHAW Lake Road -> Alabama 161kV ftlo St Joe -> Hawthorn 345kV If the contingent element trips, a portion (0-100%) of the power flows onto the monitored element Classic n-1 contingency; most flowgates fall in this category 6

7 www.spp.org Permanent & 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 load Temporary Flowgates are built on-the-fly to control the unknown or short-term issues These may be due to planned or unplanned outages Unforeseen loading may cause a temporary 7

8 www.spp.org Monitoring Real Time loading of flowgates Real Time loading flowgate 8

9 www.spp.org IDC/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 units Other Tagged Transactions external to SPP Network and Native Load (NNL) external to SPP market footprint Market Flow 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) 9

10 www.spp.org Interchange Distribution Calculator 10

11 www.spp.org History of NERC and NERC Standards IRO-006-4 Reliability Coordination Transmission Loading Relief IDC Background IDC Inputs TLR Levels IDC Factors 11

12 www.spp.org Transmission 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 TLR Market 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. 12

13 www.spp.org NERC Links NERCs Website http://www.nerc.com/ NERC Reliability Standards http://www.nerc.com/page.php?cid=2|20 FERC Approved Standards http://www.nerc.com/filez/standards/Mandatory_Effective _Dates_National_Energy_Board.html http://www.nerc.com/filez/standards/Mandatory_Effective _Dates_National_Energy_Board.html 13

14 www.spp.org Standard IRO-006-4 Reliability Coordination Transmission Loading Relief A. Introduction 1. Title: Reliability Coordination Transmission Loading Relief (TLR) 2. Number: IRO-006-4 3. 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. 14

15 www.spp.org NERC 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 15

16 www.spp.org NERC 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-006-4. 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 16

17 www.spp.org NERC 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. 17

18 www.spp.org NERC 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. 18

19 www.spp.org Interchange Distribution Calculator IDC was created to implement the TLR process explained in IRO-006 Attachment 1 Procedures for curtailment and reloading of Interchange Transaction to relieve overloads on transmission facilities modeled in the IDC IDC is a NERC Tool for the Eastern Interconnect The IDCWG is a NERC working group that is responsible for implementing IDC and other tools in support of the NERC RCs. The IDCWG reports to the Operating Reliability Subcommittee (ORS) 19

20 www.spp.org Inputs to IDC Monthly Model developed by the IDCWG System Data Exchange (SDX) every 20 minutes eTag Marginal Zones from PJM (every 5 min) and MISO (quarterly) **Not used** Market Flow SPP/PJM/MISO Phase shifter Tap settings 20

21 www.spp.org TLR Levels TLR Level 1 Notify Reliability Coordinators of potential SOL or IROL Violations TLR Level 2 Hold transfers at present level to prevent SOL or IROL Violations TLR 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 Service TLR Level 3b Curtail Interchange Transactions using Non- Firm Transmission Service Arrangements to mitigate a SOL or IROL Violation 21

22 www.spp.org TLR 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 Service TLR Level 5b Curtail Interchange Transactions using Firm Point-to-Point Transmission Service to mitigate an SOL or IROL violation TLR Level 6 Emergency Procedures TLR Level 0 TLR concluded 22

23 www.spp.org What 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 23

24 www.spp.org How 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. 24

25 www.spp.org Priority of Transmission Rights determine sequence of curtailing in case of an over load situation that required calling TLR on NERC IDC 1.Secondary Non-Firm (late redirect from Firm) NS1 2.Non-Firm PTP Hourly NH2 3.Non Firm PTP Daily ND3 4.Non Firm PTP Weekly NW4 5.Non Firm PTP Monthly NM5 6.Non Firm Network (Non-designated) NN6 Voluntarily dispatch before going to TLR Level 5 7.Firm PTP (All) F7 8.Firm Network (designated Resources) NF7 (accomplished by re-dispatching Units) 9.Load shedding TLR Level 3 TLR Level 5 TLR Level 4 25

26 www.spp.org How 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. 26

27 www.spp.org Introduction to IDC Factors TDF –Transfer Distribution Factor GSF –Generation Shift Factor LSF –Load Shift Factor GLDF –Generation-to-Load Distribution Factor LODF –Line Outage Distribution Factor PTDF & OTDF Flowgates 27

28 www.spp.org Transfer Distribution Factors Transfer Distribution Factors (TDFs) 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? 28

29 www.spp.org TDFs used in the IDC TDFs 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) 29

30 www.spp.org Generation Shift Factors Generation Shift Factors (GSF) describe a generators impact on a flowgate The 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 bus IDC disregards losses the principles of superposition applies. GSF between any two generators is the difference between the generators GSF to the swing bus GSFkm= GSFkswing–GSFmswing 30

31 www.spp.org GSF Used in the IDC GSFs 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 generators output flows on flowgate X, provided the injection is withdrawn at the swing bus Use the following formula to calculate the MW impact on a flowgate for a particular generator: MW impact = (Gen MW) x (GSF) 31

32 www.spp.org Load Shift Factors Load Shift Factors (LSF) describe how changes in system loading impacts a flowgate. 32

33 www.spp.org LSF 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) 33

34 www.spp.org Generation-to-Load Distribution Factors Generation-to-Load Distribution Factors (GLDF) describe a generators impact on a flowgate while serving load in that generators Balancing Authority Area A 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. 34

35 www.spp.org GLDF Used in the IDC GLDFs 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. 35

36 www.spp.org GLDF 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 generators 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 36

37 www.spp.org Line 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 Analysis Post-Contingency Flow on Monitored Element = Pre-Contingency Flow on Monitored Element + (Pre-Contingency Flow on Contingent Element)*LODF LODFs are not used in IDC TLR calculations 37

38 www.spp.org PTDF & OTDF Flowgates PTDF –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. 38

39 www.spp.org How 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 min This 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 Authoritys 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 SDX TDF = Σ( GSF x MBASE x DE-RATION ) / Σ( MBASE x DE-RATION ) The Balancing Authoritys 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 ) 39

40 www.spp.org How 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): TDF BA1 –BA2 = TDF BA1 –TDF BA2 The TDF of a tag is the TDF between the source and sink Control Areas TDF Tag = TDF SourceBA–SinkBA = TDF SourceBA –TDF SinkBA Tag path: Every tag has a defined path: Source BA –TP1–TP2–…–TPn–Sink BA The 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:TDF SourceBA–TP1 = TDF SourceBA –TDF TP1 Segment 2:TDF TP1–TP2 = TDF TP1 –TDF TP2 Last Segment:TDF TPn–SinkBA = TDF TPn –TDF SinkBA TDF Tag = TDF SourceBA –TDF TP1 + TDF TP1 –TDF TP2 + TDF TP2 –TDF TP3 + …+ TDF TPn –TDF SinkBA = TDF SourceBA –TDF SinkBA 40

41 www.spp.org How 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 device TDF 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: 1.Tag 1 –segmented through DC/phase shifter: TDF Tag1 = TDF BA1 –P1 + TDF P2 – TDF BA2 2.Tag 2 –AC tag between BA-1 and BA-2: TDF Tag2 = TDF BA1 –TDF BA2 3.TDF Tag1 TDF Tag2 See diagram on the following slide 41

42 www.spp.org Transmission Service Priorities Priority 0. Next-hour Market Service NX* Priority 1. Service over secondary receipt and delivery points NS Priority 2. Non-Firm Point-to-Point Hourly Service NH Priority 3. Non-Firm Point-to-Point Daily Service ND Priority 4. Non-Firm Point-to-Point Weekly Service NW Priority 5. Non-Firm Point-to-Point Monthly Service NM Priority 6. Network Integration Transmission Service from sources not designated as network resources NN Priority 7. Firm Point-to-Point Transmission Service F and Network Integration Transmission Service from Designated Resources FN 42

43 www.spp.org Cont IDC Curtails on a pro-rata basis starting with the lowest service priority Non Firm Service levels 0-6 Firm Service level 7 43

44 www.spp.org Example TLR 5 4 Firm Schedules (total of 400MW) 3200 MW of generation serving Load within BA RC 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 44

45 www.spp.org TagsMWTDF%Total Schedule Impact on FG A1001010 B1002020 C15057.5 D50157.5 Total40045 GenMWGLDF%Total NNL Impact on FG A15008120 B5001575 C400520 D8001080 Total3200295 Example TLR 5 45

46 www.spp.org In 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 TDFs 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 will see how it is distributed. Example TLR 5 46

47 www.spp.org ([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) = 6.5 Using the equation: Tag A = (13(.1)(100))/6.5 = 20 Tag B = (13(.2)(100))/6.5 = 40 Tag C = (13(.05)(150))/6.5 = 15 47

48 www.spp.org 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. 48

49 www.spp.org Re-Cap of NERC IDC logic Reliability Coordinator (RC) issues (or re-issues) a TLR on a flowgate When RC issues TLR event he enters the TLR Level (1, 2, 3A, 3B, 4, 5A, 5B) 3A is Next hour Non Firm Curtailments 3B is Current hour Non Firm Curtailments 5A is Next hour Firm Curtailments 5B is Current hour Non Firm Curtailments When 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 Target NERC IDC is sending results to SPP CAT, SPP Constraint Manager and Etagging System 49

50 www.spp.org SPP Congestion Management Tools 50

51 www.spp.org SPP 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 Calculator 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. 51

52 www.spp.org 52 SPP 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

53 www.spp.org SPP Market Flow Calculator 53

54 www.spp.org Why 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. 54

55 www.spp.org SPP 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 55

56 www.spp.org SPP Market Flow Calculator 56

57 www.spp.org SPLITTING UP MARKET FLOW IN PRIORITIES Market Flow Forward NH2 NN6 F7 RCF Flow gate F7 NN6 CF Flow gate 57

58 www.spp.org Market Flow split up CF flow gates Firm NN6 Filling buckets from left to right with Market Flow (1) (2) unlimited Firm NNL Limit 58

59 www.spp.org Total flowgate loading Tags for Physical & external Market Schedules NERC IDC is responsible to assign curtailment amount to the Tags Schedules from Self-dispatched Resources Unscheduled Market 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 Flows Flowgate loading (MW) Schedules from Market dispatched Resources MARKET FLOW 59

60 www.spp.org Ways to control a Flowgate Two ways to initiate congestion management process TLR- 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. 60

61 www.spp.org Schedule Feasibility & Revenue Neutrality Uplift (RNU) 61

62 www.spp.org Positive 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. 62

63 www.spp.org Summary of Schedule Feasibility Netting all scheduled impacts across a flowgate interface determines the approximate flow that would occur if all generation followed schedules exactly If the net of these impacts across a flowgate exceeds the limit, the flowgate is considered schedule infeasible If the impacts across the flowgate is less than or equal to the limit, the flowgate is considered schedule feasible 63

64 www.spp.org Schedule Feasibility Through schedule feasibility, SPP encourages participants to pay into market Example: Generation is expected to run at 100 and scheduled at 100 If SPP cuts schedule from generation to load by 20 MW The generator becomes long energy, and the load becomes short energy and settled in the EIS market The difference in prices (e.g., load prices exceeding generation prices) provide money to pay for redispatch GOAL: Those who contribute to loaded flowgates pay and consequently positive RNU is reduced 64

65 www.spp.org Example of Negative EIS (Schedule Infeasibility) BA A Load 1500 MW BA B Load 1500 MW Market dispatched unit Self dispatched unit 600500 600 400 500 CAT Schedule 400 MW Flowgate Market Flow 200 MW EIS = Market Flow – CAT Scheduled Impact -200 = 200 - 400 65

66 www.spp.org Removing Negative EIS If flowgate is overloaded and flow needs to be reduced from 200 150 MW Market 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 EIS Physical relief occurs from SCED Schedule curtailment is necessary to maintain schedule feasibility, but will not necessarily effect physical relief 66

67 www.spp.org What is Revenue Neutrality Uplift (RNU)? RNU ensures settlement payments/receipts for each hourly settlement interval equal zero Positive RNU: SPP receives insufficient revenue and owes market participants SPP charge a tax across the market to pay participants Negative RNU: SPP receives excessive revenue SPP pays out a credit across the market 67

68 www.spp.org Types of RNU 1.Uninstructed deviation charges If a generator is unable to meet its dispatch instruction within an allowable tolerance 2.Over/under scheduling If a market participant captures profit by manipulating schedules between its own generation and load assets to arbitrage price separation difference between EIS charges and credits SPP collects less than we pay out Congestion can result in price separation and schedule curtailments 68

69 www.spp.org Types of RNU 3.Energy Imbalance Service Over- or Under- collections due to various causes 69

70 www.spp.org Positive RNU Occurs When… Load insulated from paying congestion costs because of schedules In other words, little or no revenue collected by SPP Generators are compensated for relieving flowgates Because SPP is revenue-neutral, we cant pay generators RESULT – SPP must pay generators and tax all participants (as shown by positive RNU) 70

71 www.spp.org ~ ~ ~ Unit 1 Unit 2 Unit 3 Aggregate Load 1 Schedule Feasibility Example – Congestion with no EIS Actual = 500 Schedule = 500 LDF = -0.2 LIP = $60 Schedule= 100 MW DI = 100 MW LIP = $100 GSF = -0.6 GLDF = -0.6 – (-0.2) = -0.4 Schedule = 200 MW DI = 200 LIP = $20 GSF = 0.4 GLDF = 0.4 – (-0.2) = 0.6 Schedule = 200 MW DI = 200 LIP = $20 GSF = 0.4 MW GLDF = 0.4 – (-0.2) = 0.6 Flowgate Operating Limit = 200 MW Impact of all schedules = 200 (.6) + 200 (.6) + 100 (-0.4) = 200 71

72 www.spp.org 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 72

73 www.spp.org ~ ~ ~ Unit 1 Unit 2 Unit 3 Aggregate Load 1 Congestion with Redispatch but No Curtailments Actual = 500 Schedule = 500 LDF = -0.2 LIP = $60 Schedule= 100 MW DI = 140 MW LIP = $100 GSF = -0.6 GLDF = -0.6 – (-0.2) = -0.4 Schedule = 200 MW DI = 180 LIP = $20 GSF = 0.4 GLDF = 0.4 – (-0.2) = 0.6 Schedule = 200 MW DI = 180 LIP = $20 GSF = 0.4 MW GLDF = 0.4 – (-0.2) = 0.6 Flowgate Operating Limit = 160 MW Schedule Impact = 200 Impact from market dispatch = 180 (.6) + 180 (.6) + 140 (-0.4) = 160 73

74 www.spp.org 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) 74

75 www.spp.org Settlement Under Infeasible State – No Curtailments 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 75

76 www.spp.org ~ ~ ~ Unit 1 Unit 2 Unit 3 Aggregate Load 1 Congestion with Schedules Curtailed Actual = 500 Schedule = 434 LDF = -0.2 LIP = $60 Schedule= 100 MW DI = 140 MW LIP = $100 GSF = -0.6 GLDF = -0.6 – (-0.2) = -0.4 Schedule = 167 MW DI = 180 LIP = $20 GSF = 0.4 GLDF = 0.4 – (-0.2) = 0.6 Schedule = 167 MW DI = 180 LIP = $20 GSF = 0.4 MW GLDF = 0.4 – (-0.2) = 0.6 Flowgate Operating Limit = 160 MW Schedule Impact = 167 (.6) + 167 (.6) + 100 (-0.4) = 160 Dispatch Impact = 180 (.6) + 180 (.6) + 140 (-0.4) = 160 76

77 www.spp.org Settlements during Congestion with Schedules Curtailed to Feasible State Unit 1 EI = (Schedule – Actual) *LIP = (100-140)*$100 = -$4,000 Net Revenue = -$4,000 (Credit) Units 2 & 3 EI = (Schedule – Actual) *LIP = (167-180)*$20 = $260 Net Revenue = -$260 * 2 units = -$520 (Credit) Aggregate Load EI = (Schedule – Actual) *LIP = (434-500)*$60 = $3,960 (Charge) 77

78 www.spp.org Settlements during Congestion with Schedules Curtailed to Feasible State Total Revenue = -$4,000 - $520 + $3,960 = -$560 (Credit) Infeasible state = $3,200 EIS RNU Feasible state after curtailments = $560 EIS RNU 78

79 www.spp.org Summary of Schedule Feasibility Netting all scheduled impacts across a flowgate interface determines the approximate flow that would occur if all generation followed schedules exactly If the net of these impacts across a flowgate exceeds the limit, the flowgate is considered schedule infeasible Rather, if the impacts across the flowgate is less than or equal to the limit, the flowgate is considered schedule feasible 79

80 www.spp.org Schedule Feasibility Through schedule feasibility, SPP encourages participants to pay into market Example: Generation is expected to run at 100 and scheduled at 100 If SPP cuts schedule from generation to load by 20 MW The generator becomes long energy, and the load becomes short energy and settled in the EIS market The difference in prices (e.g., load prices exceeding generation prices) provide money to pay for redispatch GOAL: Those who contribute to loaded flowgates pay and positive RNU is reduced 80

81 www.spp.org SPP Curtailment Adjustment Tool (CAT) 81

82 www.spp.org Pre-market: A TLR is called causing schedules to be curtailed, and then redispatch occurs to physically reduce the flow on the constraint Post-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 curtailed CME alone maybe sufficient if no non-SPP market impact apply. The Major Congestion Management differences between pre & post EIS Market 82

83 www.spp.org EES Self-dispatched 1 Offered into SPP Market Schedule 1* AEP WR KCPL MISO Tag 5 Tag 4 Tag 3 Tag 1* Tag 6 OKGE Tag 7* Schedule 2* Pirkey Welsh HEC JEC HSL Lacygne Tag 2 SPP Market Footprint Schedules: IDC vs. CAT curtailables. 83

84 www.spp.org CAT - 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 flow Impact of all CAT < Real Time Flowgate Flow 84

85 www.spp.org Interaction of Congestion Management Tools; CME in black line trace NERC IDC RC Issues TLR Or CME SPP CAT every 15 min SPP Constraint Manager SPP MOS SCED SFT Topper / SPD Runs every 5 min RTOSS scheduling Target Market Flow to SPP CAT Adjusted Schedules Effective Limit of Constraint Sent to MOS Target Market Flow to SPP Constraint Manager Tag Curtailments 1 2 2 5 3 6 7 Dispatch Instructions and NSI values SPP RC accepts TLR 4 Market Flow Calculator Market Flow sent To NERC IDC every 15 minutes 8 2 ETAGGINGNLS 85

86 www.spp.org CAT 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 RTOSS SPP 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 ) 86

87 www.spp.org CAT Response to CME SPP CAT receives the status of the flowgate in the Market Operating System. SPP CAT receives Current Net Market Flow from MFC and Schedules from RTOSS SPP 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 ) 87

88 www.spp.org ***Confidential*** www.spp.org CAT 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 gate The 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. 88

89 www.spp.org ***Confidential*** www.spp.org CAT LOGIC CAT gets Market Flow Target from IDC (Net) Market Flow Target NERC IDC >0% Required Reduction CAT Flow 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 (+30) Sched Priority 6 (-10) EIS-7 (-125) Sched Priority 7 (325) CAT will adjust Pos EIS and CAT schedules to accomplish required reduction 200 MW CAT Flow = pos EIS + scheduled impact CAT schedules CAT Scheduled Flow 345 MW Market System (SCED) keeps total flow below 320 MW and pushes Market Flow down to Target CAT Curtailments 145 89

90 www.spp.org ***Confidential*** www.spp.org CATs Priority of Curtailments/Adjustments CAT priority order is as follows: Sched Priority 0 Sched 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 3 Non Firm CME TLR 5 Firm CME 90 While 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)

91 www.spp.org


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