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SPP EIS Overview WestConnect . February 24 th , 2011. Casey Cathey, P.E. [email protected] · 501.614.3267. Outline. EIS Overview Market Dispatch and Regulation Deployment Wind Integration considerations Reserve Sharing Group Synchronization Congestion Management. Section 1. EIS Overview.

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Spp eis overview westconnect l.jpg

SPP EIS OverviewWestConnect

February 24th, 2011

Casey Cathey, [email protected] · 501.614.3267


Outline l.jpg

Outline

  • EIS Overview

  • Market Dispatch and Regulation Deployment

  • Wind Integration considerations

  • Reserve Sharing Group Synchronization

  • Congestion Management


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Section 1

EIS Overview


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SPP EIS Market Highlights

  • All Load and resources 10 MW or greater within the SPP Market footprint are subject to financial settlement of Imbalance Energy.

  • The financial impact on both resources and load is within the “control” of the participants through the use of energy schedules.

  • Hourly imbalance settlement for both load and resources are netted prior to invoicing.

  • Dispatch is regional and is calculated using a security constrained, offer-based economic dispatch (SCED) every 5 minutes.


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SPP EIS Market Highlights

  • Dispatch is regional and is calculated using a security constrained, offer-based economic dispatch (SCED) every 5 minutes.

    • If a resource is Self-dispatched, it is still subject to imbalance settlement if actual output does not match scheduled output.

    • Any resource that is offered for SPP dispatch has the entire asset subject to dispatch (within the "Dispatchable Range").


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What is the “SPP Energy Imbalance Service” Market?

  • The SPP EIS Market provides asset owners the infrastructure necessary to offer their resources into the marketplace for use in providing Energy Imbalance.

  • In the EIS marketplace, SPP owns the responsibility of accounting for and financially settling all EIS amounts.

    • SPP will remain revenue neutral


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What is the “SPP Energy Imbalance Service” Market?

  • The SPP EIS market does not supersede any MP’s obligations with respect to any other capacity or ancillary service obligations.

    • Balancing Authorities (BA) and asset owners will continue to use the same procedures used today to manage capacity adequacy, reserves, and other reliability-based concerns.

  • All MPs with load and/or resources within the SPP Market footprint will be subject to EIS under this market.

  • All asset owners must register with the SPP EIS market.


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What is “Imbalance Energy”?

  • Imbalance energy (Energy Imbalance, or EI) is the difference between what actually happens for each generator and load location, and what they prearranged through schedules.

    • Generators produce amounts different than they schedule

    • Loads consume amounts different than they schedule

      Energy Imbalance = Actual Production or Usage – Scheduled Production or Usage

  • The amount of increase or decrease in generation is paid for by the asset owner needing the energy.

EI = A - S


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What is the “Energy Imbalance Service”?

  • EIS is the dollar amount associated with the imbalance energy.

  • EIS is calculated by taking the amount of EI and multiplying it by the price at a specific point on the energy grid (LIP).

    Energy Imbalance Service = Imbalance Energy x Locational Imbalance Price (LIP)

EIS = EI x LIP


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Pricing

A resource that is not free to change output to move along its offer curve in response to SPP’s dispatch will not set price

  • Resource status that does set LIP price

    • Available

  • Resource status that does not set LIP price

    • Self Dispatched

    • Manual

    • Unavailable

    • Supplemental


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Pricing Imbalance Energy in an Unconstrained & Constrained System

  • Imbalance energy is priced depending on which resources are deployed to meet the load requirements. This is known as Locational Imbalance Pricing or LIP.

    • An unconstrained system will have a single system wide price, or a System Marginal Price (SMP).

  • LIP recognizes that cost may vary at different times and locations based on real-time system conditions.

    • Constraints on the system can cause price divergence among the various nodes due to the out-of-order dispatch needed to prevent operating limit violations.

  • With LIP, asset owners know the price per MWh of electricity at various intersections on the system (nodes).


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Locational Imbalance Price (Unconstrained)

  • Here’s an example…

    Generator A offers 10 MW@ $15/MWh

    Generator B offers 10 MW@ $20/MWh

    Generator C offers 10 MW@ $30/MWh

  • To supply 15 MWh of energy to a load in an unconstrained system, the market selects the most economical generation within current reliability standards. In this case, Generators A and B.

    Generator A10 MW@ $15/MWh

    Generator B5 MW@ $20/MWh (sets price as providing the “next” increment of energy)

  • In this case, Generators A and B would both get paid $20/MWh for their participation in serving the 15 MW load

SMP


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Post-Market Energy Imbalance Process

  • But what if it is impossible to deliver power economically within current reliability standards?

  • Binding constraints (preventing a limit violation) usually result in:

    • Generation being dispatched out of economic order

    • Different prices for energy at different points in the system (or price divergence)

  • When there are constraint violations, action must be taken to maintain reliability standards.


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Demand

(Aggregated Load)

Price ($)

Quantity (MW)

17,000 MW

LIP: The “Demand” Curve

  • SPP’s forecasted market load for the entire footprint, adjusted for:

    • Self-dispatched generation (subtraction).

    • Net Market footprint interchange.

  • Demand is assumed to be completely independent of price.

    Example:

FML = 20,000MW – 2,000MW – 1,500MW + 2,500MW

Forecasted Market Load = Forecasted load - Self-dispatch – Imports + Exports


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Supply and Demand Put Together

  • Demand (aggregated load) intersects with supply (aggregated offer curves) to derive the market clearing price.

  • This assumes an unconstrained system.

Aggregated Supply Curve

Quick Quiz Question

$60.00

Demand

(Aggregated Load)

Aggregate

$50.00

Supply

(Aggregated Offer Curves)

How much aggregated load could be served with this aggregated supply without exceeding $30 per MW?

$40.00

$/MW

$30.00

$20.00

Market Clearing Price (LIP)

$10.00

$0.00

1

4

7

10

13

16

19

22

25

28

31

34

37

40

(1,000)

MW


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Operating Day Market Activities

Applications &

Applications &

Input

Input

Output

Output

Post

Operating

Day

Activities

Validations

Validations

Hour Ahead and Operating Hour Market Activities

Post Operating Hour Market Activities

Post

Day Prior to Operating

Day Activities

Day Prior to Operating Day

Operating

Day

Activities

Settlement

Capacity Analysis

EIS

Calculations

Resource Plans

State

A/S Plans

Estimator

SCADA

Offer Curves

EI NSI

EMS

Meter

RTO_SS

RTO_SS

Data

Combined

NSI

to CA

EIS Settlements

COS

MOS

LIP

MTLF

URD

Load and

Dispatch

STLF

Capability

Instructions

to MP

Reports

Legend:

SPP Systems Interaction


Load forecast l.jpg

Load Forecast

  • Purpose of the Load Forecast

    • Determine amount of resources necessary for the Market

    • Provide a Market flow estimate on flowgates

    • Determine supply adequacy (sufficiency)

    • Use in the SFT (Simultaneous Feasibility Test)

How much Generation is needed?

And how much flow will exist?

Does the RP support this?

Will this Gen/Load combination create constraints?


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Introduction to Load Forecasting

  • SPP generates its own independent load forecast consisting of:

    • Mid-Term Load Forecasts (MTLF) - used for reliability analysis

    • Short-Term Load Forecasts (STLF) - used to determine SPP’s total energy needs

Hourly for 7 days

5 minute increments for 60 minutes


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Introduction to Load Forecasting

Similar Day Load Patterns


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Hourly MP-Level Load Forecast

  • Used along with the Resource Plan and Ancillary Service Capacity Plan to indicate capacity deficiencies and available energy.

  • Supports Resource Over/Under Commitment Calculations

  • Submission Timing - May be submitted up to seven days prior to the Operating Day (OD)

  • Update Timing - Up to 45 Minutes Prior to the top of the Operating Hour (OH)


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  • MTLF (Mid Term Load Forecast)

    • Hourly, looking ahead 7 days

    • Compared against the BA Settlement Area forecasts

  • STLF (Short Term Load Forecast)

    • 5 minute increments looking ahead 60 minutes

SPP

Used for

Dispatch

Day

1

Day

3

Day

4

Day

5

Day

6

Day

7

Day

2

5 10 15 20 25 30 35 40 45 50 55 0

Submitted by 1100 hour Day Ahead

Compared against the MP and SPP Settlement Area load forecast

Used in the case of failed SPP forecast

Submitted by 1100 hour Day Ahead up to OH-45 minutes

Multiple MP forecasts are aggregated to compare against the BA Settlement Area and SPP Settlement Area forecast as well as their RP capacity

MP

BA


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Resource Plans

  • Resource Status

    • Manual

      • Not capable of following dispatch instruction by virtue of:

        • Testing

        • Intermittent resources

        • Start up or shut down mode

      • Zero ramp rate (dispatched to last observed output)

    • Available

      • Online and available for SPP Market Deployment


Resource plans24 l.jpg

Resource Plans

  • Resource Status

    • Self-dispatched

      • Online, but unavailable for SPP Market Deployment.

      • SPP will send self-dispatched resources a dispatch signal that matches the sum of their schedules

    • Unavailable

      • Offline and unavailable for SPP Deployment

      • SPP Dispatch will take an online resource to zero output via Resource Plan ramp rate

    • Supplemental

      • Offline but capable of satisfying Supplemental reserve requirements. Will not be dispatched by the MOS


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Introduction to Ancillary Service (A/S) Capacity Plans

  • The Ancillary Capacity Plan (also referred to as the A/S Plan) is submitted by each MP to enable the SPP Market Operations System (MOS) the ability to confirm each MP is satisfying its ancillary service obligations.

  • The A/S Capacity Plan notifies the SPP MOS which units will carry what amount of regulation and contingency reserves

  • The A/S capacity plan indicates transfers of obligations between MPs and, when self-arranged, which resources are providing these services.

  • A/S capacity plans will be used by MOS to ensure that EIS deployment does not consume unloaded capacity being utilized for other A/S.


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Ancillary Service Plans

  • Contents of the AS plan

    • Time period (Operating Day and Hour)

    • Counter Party

      • Scheduled from / to

    • Counter Party type (MP, PLT, GEN, CLD, RTO)

    • A/S schedules (resource and obligation)

    • MW

    • BA

    • Regulation type (Up/Down)

    • Operating Reserve (spinning and supplemental)


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Ancillary Service Plans

  • External Generation

    • No Ancillary Service Plan will be submitted nor accepted by an External Resource


Dispatchable range l.jpg

MinDisp MW

MinMW

MinEmer MW

MinEcon MW

SPIN/SUPP

DRS

URS

Dispatchable

Range

MaxDisp MW

MaxMW

MaxEmer MW

MinEmer MW

MaxEcon MW

Dispatchable Range

  • Dispatchable Range based upon data from:

    • Offer curves

    • RPs

    • AS Plans

    • State Estimator

Information from

A/S Plan

Planned MW

Ramp Rate

Information from Resource Plan


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Introduction to Deployment

  • SPP shall determine the least costly means of obtaining energy to serve the next increment (MW) of load at each settlement location, while maintaining reliability.

    • This is SCED (Security Constrained Economic Dispatch)

  • In performing these calculations, SPP will use the EIS offers that can serve the load at a bus at the lowest cost.

  • This deployment determines the dispatch instructions for resources that have offered to provide EIS (Available status).

Increasing load


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The mathematical computation (a.k.a. SCED) produces two primary outputs:

Deployment instructions

Deployment instructions are generated for EVERY resource regardless of whether it’s offered to SPP

Prices for every node in the system

Every load bus and every generator bus gets a price

Load bus prices “roll up” into larger load prices used in settlements

Introduction to Deployments

30


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Deployments are the result of a mathematical computation that utilizes certain inputs:

Actual SCADA for each resource (10 minutes prior to the end of the interval being calculated)

State estimator information for resources with bad SCADA

A load forecast for the market footprint (for the end of the interval being calculated)

Market data

Resource plans

Offer curves

Ancillary service capacity plans

Introduction to Deployments

31


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Introduction to Deployment

  • Resources that have elected to be dispatched by SPP will have their entire MW capability under SPP dispatch control.

  • Deployment values sent to all MP resources regardless of status.


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SCED must predict what generation outside of its control will do in the next 15 minutes:

“Unavailable” resources will move toward (or stay at) zero.

“Self scheduled” resources will move toward (or run at) scheduled levels

“Supplemental” and “Manual” resources will not move

SCED must predict what load will do in the next 10 minutes

Performed on a BA by BA basis and rolled up to a market total

Adjusted for imports and exports into the market

SCED then uses “available” generation to make up the slack between resources (generators) and obligations (load)

Determining Dispatch

33


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*

ICCP Link information

Deployment Information

  • Dispatch (Deployment) instructions include:

    • Resource Name

    • Market Date

    • Interval Ending (5 minute intervals)

    • Dispatch Type (EIS, OOME)

    • MW Set-Point

    • Locational Imbalance Price (LIP) ($/MWh)

    • Approval Time

  • The dispatch instruction is a set-point for the end of the deployment interval, and is a the value that the resource is expect to be at when that interval has ended

*

*


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Deployment process

  • Dispatch instructions are calculated every 5 minutes.

  • The process of calculating deployment begins 10 minutes prior to the end of that deployment interval.

  • Ramp rate used in the dispatch instruction comes from the resource plan.

  • The ramping is for the last 5 minutes of the 10 minute deployment interval.

  • NSI is calculated every four seconds and includes the ramped impact of the deployment instructions.


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Deployment process

  • The dispatch instructions are communicated (via XML) approximately 5 minutes prior to the end of the deployment interval, which is 5 minutes prior to the time the MP is expected to begin moving the resource.

  • Instructions are sent via ICCP exactly 5 minutes prior to the end of the interval (at the beginning of ramp time)

  • Dispatch instruction for a self-dispatched unit is equal to the sum of its schedules for the end of the interval.

  • At the end of each deployment interval, SPP takes a snapshot of each resource to determine if its output matches the instructed level.


The operating hour l.jpg

The Operating Hour

A deployment interval is 5 minutes, and each OH has 12 deployment intervals (DI).

  • Each operating hour contains twelve 5-minute deployment intervals.

  • During each of these deployment intervals:

  • MPs are ramping to achieve deployment, and

  • SPP is calculating NSI every four seconds and sending modified NSI to control areas via ICCP

  • While the operating hour events are occurring in real-time, the MP and SPP are preparing in the hour ahead for the next operating hour.

  • So there is overlap of the hour-ahead and operating hour events.

0600

0500

0555

0505

0510

0550

0545

0515

0540

0520

0535

0525

0530


Deployment l.jpg

Deployment

Example of deployment for a resource that has a schedule and is offered into the Market

Regulation “ripple”


Deployment and reserve sharing system rss schedules l.jpg

Deployment and Reserve Sharing System (RSS) Schedules

  • The Market Operating System (MOS) will automatically recognize a unit contingency and maintain the pre-contingency deployment until any RSS schedules come in.

  • A qualifying unit contingency is identified as having:

    • greater than 50 MW max – as defined in Resource Plan - and one or both of the following:

      • value change of greater than 50% from previous interval

      • breaker status change to “Open”

  • The pre-contingency deployment will be maintained for 3 intervals or until the RSS schedules come in – whichever comes first.

  • SPP Market Operations has the ability to manually override (“turn off”) implementation of this logic at any time if needed for a given unit or situation. For example, combined cycle reconfiguration.


  • Slide42 l.jpg

    1850 MW – 1500 MW = 350 MW

    Single BA gen – Single BA LF = Single BA MOS NSI

    350 MW – 0 MW = 350 MW

    BA MOS NSI – BA RTO_SS NSI = BA EI NSI

    50

    50

    50

    5000

    6200

    3000

    2000

    2000

    2000

    1500

    1850

    1000

    1500

    800

    1200

    50

    50

    Determining EI NSI

    • Total SPP (footprint) RTO_SS NSI = + 50 MW (+150 – 100 = 50)

    • Sum of all BA load forecasts = 14000 (SPP calculated value)

    • Total SPP NSI + SBA forecasts = Economic Dispatch for each resource to supply its share of the total 14050 MW required for the SPP footprint

    • Single BA generation – single BA load forecast = single BA Market NSI

    • BA Market NSI – BA RTO_SS NSI = BA EI NSI


    Slide43 l.jpg

    NSI Summary

    MOS (Total) NSI is the net of:

    Schedules

    NLS

    RSS Events

    Losses

    Remove Dynamic Schedules

    EI Economic

    Re-Dispatch from MOS

    RTOSS NSI (Schedules)

    Pre-market

    EI Interchange (Imbalance)

    Post-market

    The sum of all Interchange Schedules across a Balancing Authority’s boundary for a given period.

    The sum of all Imbalance Service across a Balancing Authority’s boundary for a given period.

    Total NSI (Schedules + Imbalance)

    Post-market


    Self dispatch and nsi l.jpg

    Self-Dispatch and NSI

    • It is important for BAs to control to the NSI they receive from SPP first and foremost and then drive their units to the base point as best they can. 


    Sced walkthrough l.jpg

    SCED walkthrough


    Market dispatch and regulation deployment l.jpg

    Section 2

    Market dispatch and regulation deployment


    Regulation deployment l.jpg

    Regulation deployment

    • All Balancing Authorities with Market footprint must adhere to NERC standards as well as SPP EIS Market Protocols

    • BAs place regulation on various regulation qualified resources within their fleet.

    • Dispatch signal from SPP does not consider regulation

    • BA’s AGC system must regulate on top of dispatch instruction


    Regulation deployment example l.jpg

    Regulation deployment example

    • Resource has:

      • 100MW stability minimum

      • 400MW maximum capability

      • 20MW URS

      • 20MW DRS

    • Dispatch is 300MW for next Interval

      • The BA’s individual ACE is low, so the BA regulates using the Resources ‘held back’ URS

      • Upon the next 5 minute interval, the SCED captures new output


    Wind integration considerations l.jpg

    Section 3

    Wind integration considerations


    Current footprint l.jpg

    Current Footprint


    Unique aspects of spp footprint l.jpg

    Unique aspects of SPP footprint

    • 6 HVDC including all ties with ERCOT

    • Southwest portion of the Eastern Interconnection

    • High potential for wind generation with areas of lower loading

    • Generation and Load is spread amongst 9 states geographically with long EHV lines connecting grid

    • More economic generation in North induces North to South power flows


    Wind integration l.jpg

    Wind Integration


    Wind integration53 l.jpg

    Wind Integration

    • SPP currently has 3500MW installed wind capacity

    • According to the approved Generation Interconnection queue, SPP Operations is preparing for up to 8GW installed wind capacity, with at least 40GW more in queue


    Operational issues with wind generation l.jpg

    Operational issues with Wind Generation

    • Wind is naturally uncontrollable in the up-direction

    • Ramping events can lead to over speed generation tripping

    • Generally generates at night and drops off during load pick-up

    • Trip of multiple wind turbines in an area can become the largest single contingency in the footprint


    Current solutions to operate with higher wind penetration l.jpg

    Current solutions to operate with higher wind penetration

    • Dedicated Wind Forecast system

    • EIS Market

      • Current EIS Market Security-Constrained Economic Solution repositions resources every 5 minutes to obtain the optimal economic and reliable solution

        • An added benefit is the solution counteracts volatility in resource output & load forecasting errors

      • Block VRLs

      • Excess wind resource output is shared amongst 15 Balancing Authorities through induced Market Flow

      • PRR 211 (Curtailment of Non-Dispatchable Resources)

      • TRR 024 (GIA Wind Requirements)


    Reserve sharing group synchronization l.jpg

    Section 4

    Reserve sharing group synchronization


    Current rss synchronization logic l.jpg

    Current RSS Synchronization Logic

    • The Current EIS Market logic considers RSS events in the Real-time Balancing Market engine

      • This logic is called Pre-RSS

        • Logic detects a trip of a resource if SCADA MW output drops by 50% and is larger than 50MW

        • Pre-RSS holds SCADA at the resource previous MW until the first RSS assistance schedules are seen by the Market System


    Current rss schedule creation l.jpg

    Current RSS Schedule Creation

    • 1) A schedule (contingency schedule) from a designated Load Settlement Location of the contingent Balancing Authority Area to the Settlement Location of the reported Generation Resource that suffered the contingency (contingent resource),

    • 2) Schedules sourced from designated Load Settlement Locations of the assisting Balancing Authorities to the designated Load Settlement Location of the contingent Balancing Authority, when assistance is needed, and

    • 3) Schedules, internal to the assisting Balancing Authority Areas, from the specific Resources expected to be deployed in response to an RSS event, to the designated Load Settlement Location of each assisting Balancing Authority Area required to respond to the event.


    Current rss synchronization logic example l.jpg

    Current RSS Synchronization Logic Example

    • A 200MW resource trips offline

      • 200MW loss is seen by MOS as being at least 50MW and 100% loss, which is greater than 50% of output

      • 3 types of assistant schedules are created by RSS

    Schedule type 2

    Schedule type 1

    Schedule type 3

    Tripped Resource

    Schedule type 2

    Schedule type 3


    Example pre rss logic prevents ace overshoot l.jpg

    Example: Pre-RSS logic prevents ACE overshoot

    Resource Trips

    No ACE overshoot


    Current rss synchronization issues l.jpg

    Current RSS synchronization issues

    • Assistance schedules are not delivered to MOS in one batch due to performance in creation and timing lag

      • The EIS Market is powerful and backfills the loss of generation if the RSS schedules are not recognized by MOS. This leads to ACE overshoot.

      • As soon as the assistance schedules are in the Market solution, ACE regulates to pre-contingent state

    • If the timing of the trip is after the snap of SCADA MW for a SCED run, MOS does not detect until the following interval


    Example pre rss logic does not prevent ace overshoot l.jpg

    Example: Pre-RSS logic does not prevent ACE overshoot

    • a

    ACE overshoot

    Resource Trips


    Potential fixes l.jpg

    Potential Fixes

    • SPP is treating this as high priority and upon favorable analysis will pursue implementation of one (or combination) of the following:

      • Have the Reserve Sharing System send the Inter-BA schedules (Schedule type 2) first

      • Extend the Pre-RSS logic to hold previous SCADA one extra interval

        • This would allow all RSS assistance schedules to enter MOS, but may have adverse affects to the SCED solution in the interim

      • Have RSS logic sum initial schedules that arrive in next RTB and subtract amount from previous SCADA


    Congestion management l.jpg

    Section 5

    Congestion management


    Congestion management overview l.jpg

    Congestion Management Overview

    • What is causing loading on transmission System

    • What is a flowgate

    • What is Transmission Loading Relief (TLR)

    • SPP Congestion Management process (CM)

    • Characteristics of the SPP Energy Imbalance Market (EIS)

    • Real Time Balancing Solutions (RTB)

    • What is Market Flow (MF)


    Slide66 l.jpg

    Reliability Coordination covers Generation and Transmission

    Distribution

    Generation

    Transmission

    34kV

    Voltage

    345kV

    138kV

    24kV

    345kV

    138kV

    Gen

    A

    69kV

    High voltage Transmission

    Fuel

    Generator/Plant

    Substation


    What is causing flow on system l.jpg

    What is causing flow on system?

    • Generators Serving Load of Balancing Authority

    • Scheduled flow on Transmission System between 2 different Balancing Authorities

    • Market Flow on Transmission System between Balancing Authorities that participate in Market


    Slide68 l.jpg

    Balancing Authority (BA) Area A

    Balancing Authority (BA) Area B

    Load MW

    Gen Max

    Load MW

    200

    300

    100

    A

    B

    Gen Max

    Gen MW

    Load A

    300

    Gen

    A

    200

    Load B

    Gen

    B

    Gen MW

    300

    Line A – B

    R1 + j X1

    66.7 MW

    67

    67

    67

    133

    Line A – C

    R1 + j X1

    66.7 MW

    Line B – C

    R1 + j X1

    133.3 MW

    Generation of BA Area B

    Supplying Load of BA Area C.

    Part of the 200 MW flow crosses

    Transmission System of BA A

    C

    133

    67

    Gen Max

    300

    Load C

    Gen

    C

    Gen MW

    Load MW

    100

    300

    Balancing Authority (BA) Area C


    What is creating flow on the system l.jpg

    What is creating flow on the System

    WPL

    Balancing

    Authorities

    IESC

    WEC

    DPC

    SIPC

    NSP

    WAPA

    LES

    IPW

    CWL

    SPP Market

    15 BA’s

    NI

    IP

    OPPD

    NPPD

    KACY

    MEC

    tag

    CIL

    INDN

    WR/MIDW

    SECI/WPEK

    MPS

    AMRN

    EEI

    KCPL

    tag

    DOE

    OKGE/OMPA

    LAMAR

    EDE

    GRDA

    AECI

    TVA

    WFEC

    BLKW

    tag

    EES

    SPA

    CSWS/AECC

    tag

    SPS

    SOUC

    CAJN

    EDDY

    SMEP

    ERCOTN

    ERCOTE

    CLEC

    LAFA

    LEPA

    Market Flow

    Tagged flow between 2 BA’s


    Typical events during the day l.jpg

    Typical events during the day

    • Customers “buy” Transmission rights (Reservations / TSR’s) on System, using the OASIS System of Transmission Service Providers.

    • Customers Tag (schedule) the Transmission rights.

    • Transmission lines, transformers, resources are taken out of service for scheduled maintenance during the day.Scheduled maintenance outage can be short outage of a few hours or an outage lasting several days in a row.

    • Transmission lines, transformers and resources trip unscheduled because of failures of equipment or bad weather causing damage to transmission lines and substations.

    • SPP Market is trying to economically dispatch resources within the SPP Market footprint to supply the load of the SPP Market. Economic dispatch can load up a flowgate to the SOL limit. (maximum usage of best economic generation)


    Slide71 l.jpg

    Example Loading increase flowgate LAKALAIATSTR (NERC ID 6145) after scheduled outage 345 kV line

    345 kV line St.Joe-Hawthorn out for 3 hours (scheduled maintenance)

    Yellow line means

    SPP Market System “stepped on brakes”

    to control loading of flowgate.

    SPP Market System re-dispatched

    to control loading of flowgate.

    flowgate “violated”

    2 intervals in RTB solutions.


    What is a flowgate l.jpg

    What is a flowgate

    • A flowgate is a constraint on the transmission system that will get overloaded first in case of a “high” flow in that direction on system.

    • flowgates typically represent N-1 situations, meaning one line (contingency element) can still trip before the other line (monitored element) gets overloaded. This type of flowgates is called OTDF. If flowgate consist of 1 or more lines without a contingency, the flowgate is called PTDF. Most of our flowgates have a contingency element. (OTDF)

    • flowgate flow = Flow of Monitored element plus LODF times Flow of Contingency element.

    • LODF = Load 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.


    Overview number of flowgates managed by spp rc l.jpg

    OVERVIEW Number of flowgates managed by SPP RC

    • Number of flowgates defined in SPP Congestion Management Tools (339):

      • SPP flowgates (SPP is RC and calls TLR): 222

      • Entergy flowgates (Entergy ICT calls TLR: 40

      • AECI flowgates (TVA calls TLR) 22

      • MISO/MAPP (MISO calls TLR) 42

      • PJM (PJM calls TLR) 13

    TLR is Transmission Loading Relief issued by Reliability Coordinator on NERC IDC

    If a flowgate is overloaded (or close to overloaded) and Tag Curtailments are required

    and Market relief to lower the flow of Constraint, the RC issues TLR event on NERC IDC.


    Elements of a flowgate l.jpg

    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


    Ptdf flowgate example l.jpg

    PTDF Flowgate Example

    • A collection of Transmission system elements grouped together and controlled to a collective rating

      • Flowgate examples: SPPSPSTIES, SPSSPPTIES, GENTLMREDWIL


    Otdf flowgate example l.jpg

    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


    Types of flowgate ratings l.jpg

    Types of Flowgate Ratings

    • Ratings are in MW and are outlined in SPP Criteria Section 12

      • Typical rating methodologies include Thermal, Angular, & Voltage limitations for facilities 69kV and above


    Sol irols l.jpg

    SOL & IROLs

    • System Operating Limit

      • Most of the SPP flowgates fall in this category

    • Interconnection Reliability Operating Limit (IROL): SPP currently has 9

      • TOP -007-0 R2: Following a Contingency or other event that results in an IROL violation, the Transmission Operator shall return its transmission system to within IROL as soon as possible, but not longer than 30 minutes.


    Permanent temporary flowgates l.jpg

    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


    Reciprocal and coordinated flowgates l.jpg

    Reciprocal and Coordinated Flowgates

    • Reciprocally Coordinated Flowgates (RCF) are constrained paths that are loaded due to multiple entities, i.e. MISO & SPP markets together load the constraint

    • Example: Cooper_S


    Reciprocal and coordinated flowgates81 l.jpg

    Reciprocal and Coordinated Flowgates

    • Coordinated Flowgates (CFG) are constrained paths that are loaded due in large part by a single entity combined with IDC impacting schedules

      • More common in SPP, due to location of footprint in the Eastern Interconnect

      • CREKILWICWOO


    Monitoring real time loading of flowgates l.jpg

    Monitoring Real Time loading of flowgates

    Real Time loading flowgate


    Hppvalpitval 5203 l.jpg

    HPPVALPITVAL (5203)

    Hugo Power Plant – Valliant 138kV ftlo Pittsburg – Valliant 345kV Emergency Monitored Element Rating: 315MW


    Transmission loading relief tlr l.jpg

    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.


    Summary of nerc idc logic l.jpg

    Summary 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


    Tlr hours 2009 2008 2007 corporate metrics l.jpg

    TLR Hours 2009, 2008, 2007 Corporate Metrics


    Slide88 l.jpg

    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) NN6Voluntarily 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


    Congestion management process typical sequence of events l.jpg

    Congestion Management Process Typical Sequence of Events

    • Flow approaches or exceeds flowgate limit

    • Reliability Coordinator calls TLR and requests relief from IDC

    • NERC IDC prescribes Tag, Network and Native Load (NNL), and/or Market Flow curtailments as appropriate

    • Constraint Manager and CAT receive Target Market Flow from IDC

    • SPP RC accepts TLR event in Constraint Manager and verifies that the effective limit is appropriate

    • SPP CAT will calculate appropriate schedule adjustments for those schedules not curtailed by IDC and send to RTOSS

    • Flowgate is activated in next Security Constrained Economic Dispatch (SCED)

    • Market System will run SCED, attempting to keep flowgate flow below effective limit

    • RC continues to monitor flowgate flow and ask for additional relief as necessary


    Transmission loading relief event tlr l.jpg

    Transmission Loading relief event (TLR)

    2

    Tag Curtailments

    ETAGGING

    NLS

    Target

    Market Flow

    to SPP CAT

    SPP

    CAT

    every 15 min

    3

    RTOSS

    scheduling

    Adjusted

    Schedules

    1

    RC Issues TLR

    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


    Overview congestion management tools l.jpg

    Overview Congestion Management Tools

    • Interchange Distribution Calculator (NERC IDC)

      • NERC tool used by Eastern Interconnection RCs to manage parallel flows

      • Calculates impact of tagged transactions and Network/Native Load (NNL) on flowgates

      • Prescribes equitable curtailment of tags, NNL, and market flow

    • Curtailment/Adjustment Tool (CAT)

      • SPP tool used to administer curtailments and/or adjustments of schedules not curtailed by the IDC when market flow reduction is required

      • “Curtailments” describes reductions of schedules from self-dispatched resources

      • “Adjustments” describes reductions of schedules from market-offered resources

    • Constraint Manager

      • SPP tool used by the Reliability Coordinator as an interface to MOS and IDC

      • Displays pertinent constraint data and allows for data input necessary to facilitate constraint management

    • Market Operations System (MOS/SFT-TOPPER/SPD)

      • Employs Security Constrained Economic Dispatch (SCED) logic to calculate a dispatch solution that maintains flow at or below the effective limit of any activated constraints

    • Market Flow Calculator (MFC)

      • SPP tool used to calculate impacts of SPP market dispatched generation and native load schedules on flowgates

      • Market flow in appropriate priorities are calculated for current hour and next hour and submitted to IDC every 15 minutes


    Slide92 l.jpg

    flowgate binding in RTB solutions

    Effective limit

    SOL limit

    flowgate violated

    1 or 2 intervals

    in RTB solutions

    TLR effective

    in RTB solutions

    Market “steps on brakes”


    Time schedule tlr level 3a next hour l.jpg

    Time schedule TLR Level 3A (Next Hour)

    Flow

    Limit

    Status

    1425

    1365

    Monitor

    1425

    1365

    Monitor

    1385

    1365

    Violate

    1300

    1250

    Violate

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    06:00

    05:30

    05:35

    05:40

    05:45

    05:50

    05:55

    06:05

    06:10

    06:15

    06:20

    06:25

    TLR Level 3 Effective 06:00 – 07:00 in NERC IDC

    TLR 3A

    Called

    05:25

    We will see relief by Market (“STEP ON BRAKES”)

    and by Tag curtailments starting at 06:00


    Time schedule tlr level 3b l.jpg

    Time schedule TLR Level 3B

    Flow

    Limit

    Status

    1425

    1365

    Monitor

    1385

    1365

    Violate

    1300

    1250

    Violate

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    1250

    1250

    Binding

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    RTB

    06:00

    06:05

    06:10

    06:15

    06:20

    06:25

    06:30

    06:35

    06:40

    06:45

    06:50

    TLR Level 3B Effective 06:15 – 08:00 in NERC IDC

    15 minutes

    later

    We will see relief by Market (“STEP ON BRAKES”)

    and by Tag curtailments starting 06:20

    TLR 3B

    Called

    06:05


    Characteristics spp energy imbalance market l.jpg

    Characteristics SPP Energy Imbalance Market

    • SPP Market consists of 15 Balancing Authorities.

    • The 15 Balancing Authorities are getting an NSI based on all schedules and an NSI based on Energy Imbalance (NSI EIS) from SPP. (NSI = Net Scheduled Interchange)

    • The 15 Balancing Authorities are controlling their Actual Interchange to the sum of the NSI schedules and NSI EIS.

    • SPP has full coverage of the Market footprint Load with schedules. This is part of the SPP EIS Market design.

    • BA’s are required to submit Native Load Schedules that cover the Load of the BA, for that part that is not covered with import schedules.


    Spp has full coverage of the market footprint load with schedules types of schedules cat nerc idc l.jpg

    SPP has full coverage of the Market footprint Load with schedules. Types of schedules (CAT – NERC IDC)

    Market Control Area 1 (BA1)

    Market Control Area 2 (BA2)

    400

    (100)

    C

    900

    (300)

    A

    (500)

    CAT

    YES

    100

    NO

    (100)

    NO

    700

    (300)

    Outside

    Market

    B

    D

    (500)

    NO

    (100)

    YES

    (200)

    NERC IDC

    (100)

    BA2

    NSI sched = -400

    NSI EIS = -100

    NSI Sum =-500

    BA1

    NSI sched = +500

    NSI EIS = +100

    NSI Sum = +600

    LOAD CA2

    1000 MW

    NERC IDC

    LOAD CA1

    1000 MW

    900

    Market dispatched unit with Available Status (900 MW generation)

    Self dispatched unit not available for Market for dispatch (700 MW output)

    700

    Schedule from Resource to the Load of Control Area (200 MW)

    (200)

    NO

    Curtailed by CAT, no physical relief of flow of a flowgate

    YES

    Curtailed by CAT, will result in physical relief of flow of a flowgate

    Only CAT Curtailment of NLS Schedules from Self dispatched resources serving Load

    of same Balancing Authority Area will result in physical relief


    Idc cat curtailment adjustment responsibilities l.jpg

    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)


    What is energy imbalance l.jpg

    What is Energy Imbalance

    • For Resources and Load participating in SPP EIS Market:

      • Energy Imbalance = Actual MW – Scheduled MW

    • For flowgates:

      • Energy Imbalance = Net Impact of Market Flow – Net Impact of CAT Schedules

      • Energy Imbalance = Total physical Flow of flowgate – Net Impact of all Schedules


    What is energy imbalance99 l.jpg

    What is Energy Imbalance

    Market Control Area 1 (BA1)

    Market Control Area 2 (BA2)

    400

    (100)

    C

    900

    A

    (500)

    100

    (300)

    (300)

    (100)

    700

    Outside

    Market

    B

    D

    (500)

    (100)

    (200)

    (100)

    BA2

    NSI sched = -400

    NSI EIS = -100

    NSI Sum =-500

    LOAD CA1

    1000 MW

    BA1

    NSI sched = +500

    NSI EIS = +100

    NSI Sum = +600

    LOAD CA2

    1000 MW

    flowgate (limit 600 MW, actual flow = 600 MW)

    900

    Market dispatched unit with Available Status (900 MW generation)

    Self dispatched unit not available for Market for dispatch (700 MW output)

    700

    Schedule from Resource to the Load of Control Area (200 MW)

    (200)

    ENERGY IMBALANCE OF UNIT A: Actual output – Scheduled output = 900 – (500 + 300) = +100 MW

    ENERGY IMBALANCE OF UNIT B: Actual output – Scheduled output = 700 – (500 + 200) = +0 MW

    ENERGY IMBALANCE OF UNIT C: Actual output – Scheduled output = 400 – (300 + 100) = +0 MW

    ENERGY IMBALANCE OF UNIT D: Actual output – Scheduled output = 100 – (100 + 100) = -100 MW

    ENERGY IMBALANCE FLOWGATE: Actual flow – scheduled flow = 600 – 500 = +100 MW

    ENERGY IMBALANCE LOAD Control Area 2: Actual Load – schedules = 1000 – (200+300+300+100+100) = 0 MW


    Spp energy imbalance market schedules l.jpg

    SPP Energy Imbalance Market / Schedules

    • Native Load schedules (NLS) are Firm schedules from DR’s that serve the Load of the same BA. They have an hourly profile and are typically submitted day ahead and updated during the day if necessary.

    • Native Load Schedules are fully based on Network Integrated Service.

    • Market participants can schedule Intra Market transactions from Market dispatched units. Those schedules are included in Market Flow. SPP EIS Market can dispatch Market dispatched units different than the schedule value. That creates Energy Imbalance.

    • Market participants can schedule Intra Market transactions from Self dispatched units. Those schedules are not included in Market Flow, they are subject to NERC IDC Curtailment.

    • All schedules that leave or enter SPP Market footprint are not included in Market Flow they are subject to NERC IDC Curtailment.


    Summary spp energy imbalance market l.jpg

    Summary SPP Energy Imbalance Market

    • Market Participants submit availability of resources, min/max of resources, ramp rates and price curves of Resources (hourly submission)

    • SPP Market System runs a constraint economic dispatch every 5 minutes that results in an Energy Imbalance (EIS Flow) within SPP Market footprint.

    • Market Participants following dispatch instructions of SPP Market and controlling Net Interchange to sum of NSI schedules and NSI EIS, is resulting in Market Flow (EIS Flow) on System.

    Note: Energy Imbalance (EIS) is the difference between Actual Flow and the Scheduled Flow.


    Spp energy imbalance market eis l.jpg

    SPP Energy Imbalance Market (EIS)

    • End result of SCED (Secure Constraint Economic Dispatch) is:

      • All BAs of Market footprint are getting an NSI based on schedules and NSI based on EIS (= Energy Imbalance Flow)(NSI = Net Scheduled Interchange)

      • All Resources in Market footprint are getting dispatch instructions (5 min targets)

      • All BAs need to control ACE to 0 using NSI schedules + NSI EIS as Target NSI(ACE = Actual Interchange – Scheduled Interchange)


    Security constraint economic dispatch run sced every 5 minutes at time t for interval ending t 10 l.jpg

    Security-Constraint economic dispatch run (SCED) every 5 minutes at time T for Interval Ending T+10

    IE T+10

    SCED RUN of time T

    Calculates dispatch (MW Target)

    and NSI EIS of Interval Ending (IE) T+10

    SCED

    RUN

    SCED

    RUN

    SCED

    RUN

    SCED

    RUN

    SCED

    RUN

    SCED

    RUN

    SCED

    RUN

    T-5

    T

    T+5

    T+10

    T+15

    T+20

    T+25

    Time (Minutes)

    OUTPUT

    INPUT

    SCED RUN Time T:

    Topology EMS last State Estimator run

    Actual MW resources from ICCP

    Schedules from RTOSS

    Resource plans from Market Participants

    Load Forecast IE T+10 from EMS (STLF)

    Dispatch Target of all Resources for IE T+10

    and NSI EIS of all Market BA’s for IE T+10

    Send out via ICCP and XML to Market Participants

    between T+05 and T+10


    Possible states of flowgate in spp tools l.jpg

    Possible States of Flowgate in SPP Tools

    • Activated, but not binding or violated.

      • Market System is able to dispatch economically with a resulting flowgate flow lower than its effective limit

      • No price separation exists

      • No different than a SCED run without flowgate activated

    • Binding, not violated

      • Market System redispatches keeping flowgate flow at its effective limit

      • Price separation exists

    • Violated

      • Market System is unable to keep flowgate flow at or below the effective limit (e.g., insufficient ramp rate, lack of sufficient adjustable generation impacting flowgate, etc.)

      • Price separation exists and can be significant

      • Negative LIP prices can exist on constraint side of flowgate as a result


    Slide105 l.jpg

    flowgate binding in RTB solutions

    Effective limit

    SOL limit

    flowgate violated

    1 or 2 intervals

    in RTB solutions

    TLR effective

    In RTB solutions

    “step on brakes”

    flowgate activated

    in RTB solutions.

    Not binding or violated.

    Economic dispatch.


    Slide106 l.jpg

    Saturday

    Friday

    TEMP22_16220

    Violated 1 interval

    Binding 8 intervals


    Slide107 l.jpg

    Saturday

    Sunday

    TEMP21_16216

    Violated 1 interval

    Binding 3 or 4 intervals

    SJHALKNAIASC

    Violated 2 interval

    Binding 9 intervals


    What is market flow l.jpg

    What is Market Flow

    • Impact of all Transmission System flow within SPP Market footprint that is not subject to curtailment by NERC IDC

    • Market Flow = Impact of all CAT Schedules + Impact of Energy Imbalance Flow

    Note: Energy Imbalance = Actual Flow/Output in MW – Scheduled Flow/Output in MW


    Why calculate market flow l.jpg

    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.


    What is market flow110 l.jpg

    What is Market Flow

    Market Control Area 1 (BA1)

    Market Control Area 2 (BA2)

    400

    (100)

    C

    900

    A

    (500)

    CAT

    100

    (300)

    (300)

    (100)

    700

    Outside

    Market

    B

    D

    (500)

    (100)

    (200)

    NERC IDC

    (100)

    BA2

    NSI sched = -400

    NSI EIS = -100

    NSI Sum =-500

    LOAD CA1

    1000 MW

    BA1

    NSI sched = +500

    NSI EIS = +100

    NSI Sum = +600

    LOAD CA2

    1000 MW

    flowgate (limit 600 MW, flow = 600 MW)

    900

    Market dispatched unit with Available Status (900 MW generation)

    700

    Self dispatched unit not available for Market for dispatch (700 MW output)

    (200)

    Schedule from Resource to the Load of Control Area (200 MW)

    Market Flow = Impact of CAT schedules + Energy Imbalance of flowgate = 400 MW

    300 MW BA1BA2 + (600 – 500) = 400 MW


    Market flow impact of all cat schedules impact of energy imbalance flow l.jpg

    Market Flow = Impact of all CAT Schedules + Impact of Energy Imbalance Flow

    • SPP has full coverage of the Market footprint Load with schedules. This is part of the SPP EIS Market design.

    • All “CAT” schedules are based on a Confirmed NITS or PtP Reservation that have priority level Firm, NN6 or Non-Firm.

    • The “CAT” schedules represent the priority “rights” of the Market Flow and determine the “bucket” size of Firm, NN6 and Non Firm Market Flow.

    • Energy Imbalance is considered Non-Firm and will end up in lowest priority bucket of Market Flow.


    Slide112 l.jpg

    Flowgate loading (MW)

    Impact of Parallel Flows

    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.

    Schedules from

    Market dispatched Resources

    Schedules from Self-dispatched Resources

    NERC IDC is responsible to assign curtailment amount to the Tags

    Tags for Physical & “external” Market Schedules

    Total flowgate loading

    MARKET FLOW


    Positive eis negative eis l.jpg

    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.


    The major congestion management differences between pre post eis market l.jpg

    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 is called at the same time as redispatch occuring to physically reduce the flow on the constraint, and then schedules are curtailed


    What causes congestion how to solve it l.jpg

    What causes congestion? How to solve it?

    • Congestion in SPP is generally caused by

      • Transmission elements on outage

      • Induced Market Flow

      • Bi-lateral transactions

      • Entities not following dispatch signals or NSI

      • Real-time contingencies

    • Majority of congestion is solved through redispatch of Market Offered ‘Available’ status resources

      • Resources that are on the constrained-side of the flowgate move up to provide ‘counter-flow’ on a constrained flowgate

      • Other options include schedule curtailments through IDC,


    Arizona ehv transmission systems observations l.jpg

    Craig

    Hayden

    TOUTAH

    TOUTAH

    TO COLORADO

    Navajo

    San Juan

    Glen Canyon

    Four Corners

    TONEVADA

    TONEWMEXICO

    Mohave

    Davis

    Cholla

    TOCALIFORNIA

    Coronado

    TONEWMEXICO

    Springerville

    Parker

    PaloVerde

    Kyrene

    TOPHOENIX AREA

    TONEWMEXICO

    TO TUCSONAREA

    North

    Arizona EHV Transmission Systems observations

    COLORADO

    NEVADA

    UTAH

    Shiprock

    Marketplace

    Mead

    Mc Cullough

    Moenkopi

    El Dorado

    Electrical Substations

    Coal Generation

    Hydro Generation

    New Gas Generation

    CALIFORNIA

    Westwing

    PinnaclePeak

    ToDevers

    Liberty

    Rudd

    Silver King

    Browning

    Hassayampa

    Greenlee

    ToMiguel

    North Gila

    Jojoba

    Saguaro

    Pinal West

    Vail

    South

    ARIZONA

    NEW MEXICO

    MEXICO


    Spp congestion management tools l.jpg

    SPP Congestion Management Tools

    • 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.

    • 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.


    Spp congestion management tools118 l.jpg

    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.

    118


    Spp congestion management tools119 l.jpg

    SPP Congestion Management Tools

    • Constraint Manager

      • Used by the Reliability Coordinator as an interface to MOS and IDC.

      • Displays pertinent constraint data and allows for data input necessary to facilitate constraint management.

    • Market Operations System (MOS)

      • Employs Security Constrained Economic Dispatch (SCED) logic to calculate a dispatch solution that attempts to maintain flow at or below the effective limit of any activated constraints.

      • Note: This is the main system that controls physical loading in the SPP EIS Market


    Interaction of congestion management tools cme in black line trace l.jpg

    Interaction of Congestion Management Tools; CME in black line trace

    Tag Curtailments

    2

    Target

    Market Flow

    to SPP CAT

    SPP

    CAT

    every 15 min

    3

    RTOSS

    Adjusted

    Schedules

    1

    RC Issues TLR

    Or CME

    NERC IDC

    2

    5

    Effective Limit

    of Constraint

    Sent to MOS

    Target

    Market Flow

    to SPP Constraint

    Manager

    4

    SPP MOS

    SCED Run

    every 5 min

    Market Flow sent

    To NERC IDC every 15 minutes

    Constraint

    Manager

    4

    7

    SPP RC accepts TLR

    6

    Market Flow

    Calculator

    Dispatch Instructions and NSI values


    Idc cat curtailment adjustment responsibilities121 l.jpg

    IDC/CAT Curtailment / Adjustment Responsibilities

    NERC IDC

    Tagged Interchange Transactions that leave or enter SPP Market footprint

    Tagged Interchange Transactions from Self-Dispatched units

    Other Tagged Transactions external to SPP

    Network and Native Load (NNL) external to SPP market footprint

    Market Flow

    121


    Idc cat curtailment adjustment responsibilities122 l.jpg

    IDC/CAT Curtailment / Adjustment Responsibilities

    • SPP CAT

      • Tagged Interchange Transactions from units that are not Self-Dispatched

      • Intra-BA Schedules from Market-Dispatched units (NLS or Tagged)

      • Intra-BA Schedules from Self-Dispatched units (NLS or Tagged)


    Slide123 l.jpg

    SPP Market Footprint

    Tag 6

    WR

    MISO

    KCPL

    Schedule 1*

    Lacygne

    1

    Tag 3

    HEC

    JEC

    Tag 1*

    Tag 5

    Tag 4

    EES

    Tag 2

    OKGE

    HSL

    Self-dispatched

    Tag 7*

    Pirkey

    Schedule 2*

    AEP

    Welsh

    Offered into SPP Market


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    What is Schedule Feasibility?

    124


    Summary of schedule feasibility l.jpg

    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


    Schedule feasibility l.jpg

    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


    Eis net market flow net impact cat schedules l.jpg

    EIS = Net Market Flow - Net Impact CAT Schedules

    Net Market

    Flow

    Net impact

    schedules

    EIS Counter Flow

    Net impact

    schedules

    Net Market

    Flow

    Forward

    Impact

    schedules

    Forward

    Market

    Flow

    Reverse

    Market

    Flow

    Reverse

    Impact

    schedules

    Impact CAT Schedules down to 0%

    Market Flow down to 0%

    127


    Example of negative eis schedule infeasibility l.jpg

    Example of Negative EIS (Schedule Infeasibility)

    BA A

    Load 1500 MW

    BA B

    Load 1500 MW

    CAT Schedule 400 MW

    600

    400

    400

    Flowgate

    600

    500

    500

    Market Flow 200 MW

    EIS = Market Flow – CAT Scheduled Impact

    -200 = 200 - 400

    Market dispatched unit

    Self dispatched unit


    Removing negative eis l.jpg

    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


    Pricing extremes and congestion l.jpg

    Pricing Extremes and Congestion

    • Uncongested (Flowgate Activated)

      • Market System dispatches economically with a resulting flowgate flow lower than effective limit

      • No price separation exists


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    Pricing Extremes and Congestion

    • “Normal” Congestion (Flowgate Binding)

      • Market System redispatches to keep the flowgate at effective limit.

      • Price separation exists


    Pricing extremes and congestion132 l.jpg

    Pricing Extremes and Congestion

    • Extreme Congestion (Flowgate Violated)

      • Market System is unable to keep the flowgate flow at or below its limit.

      • Price separation exists and can be significant.

      • Negative LIP prices can exist on constrained side of the flowgate.

    132


    Lip calculation l.jpg

    LIP Calculation

    • Locational Imbalance Price (LIP) at every load and resource within the SPP EIS Market Footprint and every load at 1st tier

      • LIP = System Marginal Price (SMP) + ∑(Shift Factor * Shadow Price)

        • System Marginal Price is the price of the next MW delivered by the Market solution

        • Shift Factor is the percentage of flow if resource injects or load withdraws 1MW in reference to the activate flowgate

        • Shadow Price is the decrease of total cost if constraint is relaxed by 1MW


    What is revenue neutrality uplift rnu l.jpg

    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


    Types of rnu l.jpg

    Types of RNU

    • Uninstructed deviation charges

      • 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 separationdifference 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

    • Energy Imbalance Service

      • Over- or Under- collections due to various causes


    Positive rnu occurs when l.jpg

    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)


    Relationship between rnu and infeasibility l.jpg

    Relationship between RNU and Infeasibility

    Negative

    EIS

    Positive

    RNU

    • Generally removing negative EIS lowers the RNU level, however

    • may not bring RNU to 0.

    0

    0

    0

    RNU scale

    Infeasibility = negative EIS scale


    Schedule feasibility example congestion with no eis l.jpg

    Schedule Feasibility Example – Congestion with no EIS

    Schedule = 200 MW

    DI = 200

    LIP = $20

    GSF = 0.4 MW

    GLDF = 0.4 – (-0.2) = 0.6

    ~

    Actual = 500

    Schedule = 500

    LDF = -0.2

    LIP = $60

    Aggregate Load 1

    Unit 3

    Flowgate Operating Limit = 200 MW

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

    ~

    Unit 1

    ~

    Schedule = 200 MW

    DI = 200

    LIP = $20

    GSF = 0.4

    GLDF = 0.4 – (-0.2) = 0.6

    Schedule= 100 MW

    DI = 100 MW

    LIP = $100

    GSF = -0.6

    GLDF = -0.6 – (-0.2) = -0.4

    Unit 2


    Settlement under feasible state with no eis l.jpg

    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


    Congestion with redispatch but no curtailments l.jpg

    Congestion with Redispatch but No Curtailments

    Aggregate Load 1

    ~

    Actual = 500

    Schedule = 500

    LDF = -0.2

    LIP = $60

    Schedule = 200 MW

    DI = 180

    LIP = $20

    GSF = 0.4 MW

    GLDF = 0.4 – (-0.2) = 0.6

    Unit 3

    Flowgate Operating Limit = 160 MW

    Schedule Impact = 200

    Impact from market dispatch = 180 (.6) + 180 (.6) + 140 (-0.4) = 160

    ~

    Unit 1

    Schedule = 200 MW

    DI = 180

    LIP = $20

    GSF = 0.4

    GLDF = 0.4 – (-0.2) = 0.6

    Schedule= 100 MW

    DI = 140 MW

    LIP = $100

    GSF = -0.6

    GLDF = -0.6 – (-0.2) = -0.4

    ~

    Unit 2


    Settlement under infeasible state no curtailments l.jpg

    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)


    Settlement under infeasible state no curtailments143 l.jpg

    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


    Congestion with schedules curtailed l.jpg

    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) + 167 (.6) + 100 (-0.4) = 160

    Dispatch Impact = 180 (.6) + 180 (.6) + 140 (-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


    Settlements during congestion with schedules curtailed to feasible state l.jpg

    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)


    Settlements during congestion with schedules curtailed to feasible state146 l.jpg

    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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