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

3. What 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.

4. 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

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

6. 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

7. 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

8. Monitoring Real Time loading of flowgates
Real Time loading flowgate

9. 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)

10. Interchange Distribution Calculator

11. History of NERC and NERC Standards
IRO Reliability Coordination — Transmission Loading Relief
IDC Background
IDC Inputs
TLR Levels
IDC Factors

12. 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.

13. NERC Links NERC’s Website NERC Reliability Standards
NERC Reliability Standards
FERC Approved Standards

14. 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.

15. 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

16. 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 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

17. 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.

18. 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.

19. 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 RC’s.
The IDCWG reports to the Operating Reliability Subcommittee (ORS)

20. 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

21. 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

22. 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

23. 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

24. 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.

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

26. 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.

27. 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

28. Transfer 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?”

29. 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)

30. Generation Shift Factors
Generation Shift Factors (GSF) describe a generator’s 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
GSFk→m= GSFk→swing–GSFm→swing

31. 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 generator’s 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)

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

33. 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)

34. Generation-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 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.

35. 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.

36. 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 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

37. 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

38. 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.

39. 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 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 SDX
TDF = 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 )

40. 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):
TDFBA1 –BA2= TDFBA1–TDFBA2
The TDF of a tag is the TDF between the source and sink Control Areas
TDFTag= TDFSourceBA–SinkBA= TDFSourceBA–TDFSinkBA
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:TDFSourceBA–TP1= TDFSourceBA–TDFTP1
Segment 2:TDFTP1–TP2= TDFTP1–TDFTP2
Last Segment:TDFTPn–SinkBA= TDFTPn–TDFSinkBA
TDFTag= TDFSourceBA–TDFTP1+ TDFTP1–TDFTP2+ TDFTP2–TDFTP3+ …+ TDFTPn–TDFSinkBA= TDFSourceBA–TDFSinkBA

41. 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:
Tag 1 –segmented through DC/phase shifter: TDFTag1= TDFBA1 –P1+ TDFP2–TDFBA2
Tag 2 –AC tag between BA-1 and BA-2: TDFTag2= TDFBA1–TDFBA2
TDFTag1≠TDFTag2
See diagram on the following slide

42. 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

43. Con’t
IDC Curtails on a pro-rata basis starting with the lowest service priority
Non Firm Service levels 0-6
Firm Service level 7

44. 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

45. Example TLR 5
Tags MW TDF% Total Schedule Impact on FG A B C D
Total
Gen MW GLDF% Total NNL Impact on FG A B C D
Total

46. Example TLR 5
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 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 will
see 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) = 6.5
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

48. Therefore, 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.

49. 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

50. SPP Congestion Management Tools

51. 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.

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. SPP Market Flow Calculator

54. 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.

55. 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

56. SPP Market Flow Calculator

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

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

59. MARKET FLOW Total flowgate loading Flowgate loading (MW)
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

60. 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.

61. Schedule Feasibility & Revenue Neutrality Uplift (RNU)

62. 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.

63. 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

64. 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

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

66. 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

67. 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

68. Types of RNU Uninstructed deviation charges Over/under scheduling
If a generator is unable to meet its dispatch instruction within an allowable tolerance
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

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

70. 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 can’t pay generators
RESULT – SPP must pay generators and “tax” all participants (as shown by positive RNU)

71. 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) (.6) (-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

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

73. 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) (.6) (-0.4) = 160 ~
Unit 1
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 ~
Unit 2

74. Settlement Under Infeasible State – No Curtailments
Unit 1
EI = (Schedule – Actual) *LIP = ( )*$100 = -$4,000
Net Revenue = -$4,000 (Credit)
Units 2 & 3
EI = (Schedule – Actual) *LIP = ( )*$20 = $400
Net Revenue = $400 * 2 units = $800 (Charge)

75. Settlement Under Infeasible State – No Curtailments
Aggregate Load
EI = (Schedule – Actual) *LIP = ( )*$60 = $0
Total Revenue = -$4,000 + $800 = -$3,200 (Credit)
Results in EIS RNU of $3,200

76. Congestion with Schedules Curtailed
Unit 3 ~
Aggregate Load 1
Actual = 500
Schedule = 434
LDF = -0.2
LIP = $60
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) (.6) (-0.4) = 160
Dispatch Impact = 180 (.6) (.6) (-0.4) = 160 ~
Unit 1
Schedule = 167 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

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

78. 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

79. 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

80. 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

81. SPP Curtailment Adjustment Tool
(CAT)

82. The 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 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.

83. Schedules: IDC vs. CAT curtailables.
SPP Market Footprint WR
Tag 6
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

84. 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

85. Interaction of Congestion Management Tools; CME in black line trace2
Tag Curtailments
ETAGGING
NLS
Target
Market Flow
to SPP CAT
SPP
CAT
every 15 min 3
RTOSS
scheduling
Adjusted
Schedules 1
RC Issues TLR
Or CME 2
NERC IDC 6
Effective Limit
of Constraint
Sent to MOS 2
Target
Market Flow
to SPP Constraint
Manager 8 5
SPP
Constraint
Manager
SPP MOS SCED
SFT Topper / SPD
Runs every 5 min
Market Flow sent
To NERC IDC every 15 minutes 4
SPP RC accepts TLR
Market Flow
Calculator 7
Dispatch Instructions and NSI values

86. 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 )

87. 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 )

88. 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.

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

90. CAT’s Priority of Curtailments/Adjustments
TLR 3
Non Firm CME
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 5
Firm CME
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)