overview idc – interchange distribution calculator market flow calculator revenue uplift /...

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• Overview

• IDC – Interchange Distribution Calculator

• Market Flow Calculator

• Revenue Uplift / Schedule Infeasibility

• CAT – Curtailment Adjustment Tool

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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?

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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

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PTDF Flowgate Example

• A collection of Transmission system elements grouped together and controlled to a collective rating• Flowgate examples: SPPSPSTIES, SPSSPPTIES,

GENTLMREDWIL

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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

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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

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Monitoring Real Time loading of flowgates

Real Time loading flowgate

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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)

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Interchange Distribution Calculator

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• History of NERC and NERC Standards• IRO-006-4 Reliability Coordination —

Transmission Loading Relief• IDC Background• IDC Inputs• TLR Levels• IDC Factors

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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.

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NERC Links

• NERC’s 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

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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.

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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

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• 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

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• 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.

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• 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.

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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)

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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

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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

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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

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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

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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.

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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) NN6Voluntarily 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

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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.

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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

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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?”

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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)

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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

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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)

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Load Shift Factors

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

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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)

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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.

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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.

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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

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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

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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.

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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 )

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• 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

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• 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: TDFTag1= TDFBA1 –P1+ TDFP2–

TDFBA2

2. Tag 2 –AC tag between BA-1 and BA-2: TDFTag2= TDFBA1–TDFBA2

3. TDFTag1≠TDFTag2

• See diagram on the following slide

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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

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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

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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

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• Tags MW TDF% Total Schedule Impact on FG• A 100 10 10• B 100 20 20• C 150 5 7.5• D 50 15 7.5• Total 400 45• Gen MW GLDF% Total NNL Impact on FG• A 1500 8 120• B 500 15 75• C 400 5 20• D 800 10 80• Total 3200 295

Example TLR 5

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• 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.

Example TLR 5

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([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

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• 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.

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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

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SPP Congestion Management Tools

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• 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.

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• 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.

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SPP Market Flow Calculator

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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.

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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

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SPLITTING UP MARKET FLOW IN PRIORITIES

MarketFlowForward

NH2

NN6

F7

RCF Flow gate

F7

NN6

CF Flow gate

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Market Flow split up CF flow gates

FirmNN6

Filling buckets from left to right with Market Flow

(1) (2)

unlimitedFirm NNL Limit

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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

UnscheduledMarket 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 fromMarket dispatched Resources

MARKET FLOW

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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.

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Schedule Feasibility

&

Revenue Neutrality Uplift (RNU)

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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.

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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

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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

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Example of Negative EIS (Schedule Infeasibility)

BA ALoad 1500 MW

BA BLoad 1500 MW

Market dispatched unitSelf dispatched unit

600 500

600400 400

500

CAT Schedule 400 MW

Flowgate

Market Flow 200 MW

EIS = Market Flow – CAT Scheduled Impact

-200 = 200 - 400

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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

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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

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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

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Types of RNU

3.Energy Imbalance Service• Over- or Under- collections due to various causes

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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)

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~

~

~

Unit 1

Unit 2

Unit 3

Aggregate Load 1

Schedule Feasibility Example – Congestion with no EIS

Actual = 500Schedule = 500LDF = -0.2LIP = $60

Schedule= 100 MWDI = 100 MWLIP = $100GSF = -0.6GLDF = -0.6 – (-0.2) = -0.4

Schedule = 200 MWDI = 200LIP = $20GSF = 0.4GLDF = 0.4 – (-0.2) = 0.6

Schedule = 200 MWDI = 200LIP = $20GSF = 0.4 MWGLDF = 0.4 – (-0.2) = 0.6

Flowgate Operating Limit = 200 MW

Impact of all schedules = 200 (.6) + 200 (.6) + 100 (-0.4) = 200

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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

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Unit 1

Unit 2

Unit 3

Aggregate Load 1

Congestion with Redispatch but No Curtailments


Schedule= 100 MWDI = 140 MW LIP = $100GSF = -0.6GLDF = -0.6 – (-0.2) = -0.4


Schedule = 200 MWDI = 180LIP = $20GSF = 0.4 MWGLDF = 0.4 – (-0.2) = 0.6 Flowgate Operating Limit = 160 MW

Schedule Impact = 200Impact from market dispatch = 180 (.6) + 180 (.6) + 140 (-0.4) =

160

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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)

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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

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Unit 1

Unit 2

Unit 3Aggregate Load 1

Congestion with Schedules Curtailed


Schedule= 100 MWDI = 140 MW LIP = $100GSF = -0.6GLDF = -0.6 – (-0.2) = -0.4


Schedule = 167 MWDI = 180LIP = $20GSF = 0.4 MWGLDF = 0.4 – (-0.2) = 0.6 Flowgate Operating Limit = 160 MW

Schedule Impact = 167 (.6) + 167 (.6) + 100 (-0.4) = 160Dispatch Impact = 180 (.6) + 180 (.6) + 140 (-0.4) = 160

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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)

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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

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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

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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

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SPP Curtailment Adjustment Tool

(CAT)

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• 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

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EES

Self-dispatched

1

Offered into SPP Market

Schedule 1*

AEP

WR

KCPLMISO

Tag 5Tag 4

Tag 3

Tag 1*

Tag 6

OKGE

Tag 7*Schedule 2*

Pirkey

Welsh

HECJEC

HSL

Lacygne

Tag 2

Tag/Schedule Source GCA LCA Sink

Schedule Type

Curtailment Tool

Tag 1 Pirkey AEP KCPL KCPL Market SPP CAT Tag 2 Welsh AEP EES EES Market NERC IDC Tag 3 JEC WR KCPL KCPL Physical NERC IDC Tag 4 JEC WR AEP AEP Physical NERC IDC Tag 5 MISO MISO AEP AEP Physical NERC IDC Tag 6 LaCygne KCPL MISO MISO.CIN Physical NERC IDC Tag 7 HSL OKGE AEP AEP Market SPP CAT Schedule 1 HEC NA NA WR Physical SPP CAT Schedule 2 HSL NA NA OKGE Market SPP CAT

SPP Market Footprint

Schedules: IDC vs. CAT curtailables.

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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

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Interaction of Congestion Management Tools; CME in black line trace

NERC IDCRC Issues TLROr CME

SPPCATevery 15 min

SPPConstraintManager

SPP MOS SCEDSFT Topper / SPD Runs every 5 min

RTOSSscheduling

TargetMarket Flowto SPP CAT Adjusted

Schedules

Effective Limitof ConstraintSent to MOS

TargetMarket Flowto SPP ConstraintManager

Tag Curtailments

1

2

2

5

3

6

7Dispatch Instructions and NSI values

SPP RC accepts TLR

4

Market FlowCalculator

Market Flow sentTo NERC IDC every 15 minutes

8

2

ETAGGING NLS

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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 )

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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 )

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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.

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CAT LOGIC

CAT gets Market FlowTarget from IDC (Net)

Market FlowTargetNERC IDC>0%

RequiredReductionCAT 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 adjustPos EIS andCAT schedulesto accomplishrequired reduction

200 MW

CAT Flow = pos EIS+ scheduled impactCAT schedules

“CAT Scheduled Flow”

345 MW

Market System (SCED)keeps total flow below 320 MW and pushes Market Flowdown to Target

CAT Curtailments

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CAT’s 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 3Non Firm CME

TLR 5Firm CME

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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)

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overview idc – interchange distribution calculator market flow calculator revenue uplift /...

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