Integrated Marketplace Commission Staff Education March 26, 2012

Integrated Marketplace

Commission StaffEducation

March 26, 2012

ACP - Auction Clearing Price

AO - Asset Owner

ARR - Auction Revenue Rights

BA – Balancing Authority

CBA - Consolidated Balancing Authority

CBT – Computer Based Training

DA - Day-Ahead

EIS – Energy Imbalance Service

EMS - Energy Management System

FERC – Federal Energy Regulatory Commission

ISO - Independent System Operator

LMP - Locational Marginal Price

LMS – SPP Learning Center

LSE – Load Serving Entity

MCC - Marginal Congestion Component

MLC - Marginal Loss Component

MEC – Marginal Energy Component

MCP - Market Clearing Price

MP - Market Participants

NERC – North American Electric Reliability Corporation

NITS - Network Integrated Transmission Service

OATT – Open Access Transmission Tariff

OD – Operating Day

OR - Operating Reserve

RTBM - Real-Time Balancing Market

RTO - Regional Transmission Organization

RUC - Reliability Unit Commitment

SCED - Security-Constrained Economic Dispatch

SCUC - Security-Constrained Unit Commitment

SPP - Southwest Power Pool

TCR - Transmission Congestion Rights

VER – Variable Energy Resource

Common Acronyms

3

Agenda

Morning

• Introduction

• Integrated Marketplace Overview

• Pre Day-Ahead Market Activities

• Day-Ahead Market Activities

Afternoon

• Operating Day Market Activities

• Auction Revenue Rights (ARRs) and Transmission Congestion Rights (TCRs)

• Post Real-Time Market Activities

4

INTRODUCTIONSection 1

5

Map of ISOs and RTOs

6

6 ISOs in North America: CAISO, NYISO, ERCOT, AEISO, IESO, NBSO4 RTOs in North America: PJM, MISO, SPP, ISO-NE

Integrated Marketplace Net Benefits

• Projected savings around $45-$100 Million/Year

• Reduce total energy costs through centralized unit commitment while maintaining reliable operations

• Day-Ahead Market allows additional price assurance capability prior to real-time

• Includes new markets for Operating Reserve to support implementation of Consolidated Balancing Authority (CBA) and facilitate reserve sharing

7

8

Today versus Tomorrow’s Market

EIS MarketIntegrated Marketplace

• Transmission Reservations

• Energy Bilaterals Real-Time

Balancing Market

• Transmission Scheduling (Internal /

External) – All Reservations

• Operating Reserve Regulation and Reserves

– Self –Designated

• Settlements Duration – Hourly Pricing – LIP

• Unit Commitment Self-Commitment

• Balancing Authority 16 Individual BAs

• Transmission Auction Revenue Rights (ARRs) Transmission Congestion Rights

(TCRs)

• Energy Day-Ahead Market Virtual Transactions Scheduling

(Import/Export/Through)

• Operating Reserve Regulation and Reserves -

Market

• Settlements Duration – Hourly (DA); 5

Minutes (RTBM) Pricing – LMP, MCP, and ACP

• Unit Commitment Centralized Commitment

• Balancing Authority 1 SPP BA

INTEGRATED MARKETPLACE OVERVIEW

Section 2

9

Topics Covered

• SPP Roles and Responsibilities

• Market Participant Roles and Responsibilities

• System Models Configuration

• Roles and responsibilities of Market Monitoring

• Integrated Marketplace Processes and Products

• Market Pricing

10

INTEGRATED MARKETPLACE OVERVIEW:

EVOLUTION OF SPP AND THE INTEGRATED MARKETPLACE

11

Southwest Power Pool

12

• Who is SPP?

• Independent, non-profit, Regional Transmission Organization

• ~500 employees

• Membership in 9 states• Arkansas, Kansas, Louisiana,

Mississippi, Missouri, Nebraska, New Mexico, Oklahoma, and Texas

• Manages reliability from Little Rock, Arkansas

• 24 x 7 operations

• Full redundancy and backup site

• Facilitation• Reliability Coordination• Transmission Service/

Tariff Administration• Market Operation

• Standards Setting• Compliance Enforcement• Transmission Planning• Training

Our Major Services

Regional IndependentCost-effectiveFocus on reliability

13

SPP History and Major Milestones

14

1941 1968

1991

1994

1997

1998

2001

2004

2007

2010

2014

SPP Formed

Founding Member of NERC Regional Council

Implemented Operating

Reserve Sharing

Incorporated as a Non-Profit

Implemented Reliability

Coordination

Implemented Tariff

Administration

Implemented Regional

SchedulingBecame FERC-approved RTO

EIS Market Launched;

Became NERC Regional Entity


Approved


Goes-LiveMarch 1, 2014

SPP Roles and Responsibilities

• Post implementation of the Integrated Marketplace, SPP is responsible for:

• Providing all market services for Energy, Operating Reserve, and Transmission Service in accordance with the Open Access Transmission Tariff (OATT) and Market Protocols

• Managing and administering the Tariff

• Acting as the centralized SPP Balancing Authority

• Providing reliable operation of the transmission system

• Administering the Day-Ahead, Real-Time, Operating Reserve, and Transmission Congestion Rights Markets

15

16

• With the Integrated Marketplace, SPP will assume the role of the Balancing Authority (BA)

• Balancing Authority is the responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection Frequency in Real-Time

Balancing Authority

14

15

1311

16

Balancing Authorities (as it exists today)

SPP – BA(as it exists tomorrow)

SPP

12

10

8

9

547

6

1

2

3

Interactions with the SPP Market

17

18

Interactions with the SPP Market (cont’d)

SPPBoard of Directors

Regional State

Committee

RegionalEntity

TrusteesMembership

Market and OperationsPolicy Committee

Regional Tariff WG

Change WG System Protection & Control WG

Critical Infrastructure Protection WG Generation WG

Operations Training WG

Operating Reliability WG

Seams Steering Committee Transmission WG

Consolidated Balancing Authority Steering Committee Model Development WG

Business Practices WG

Market WG

Economic Studies WG

• Market Participants will be informed and can encourage changes by getting involved with Committees and Working Groups.

Interactions with the SPP Market (cont’d)

• Market Participants who wish to participate in the Integrated Marketplace must:

• Register as a Market Participant with SPP

• Review and submit required signed legal documents

• Confirm asset modeling

• Clear credit requirements (cash collateral, letter of credit, etc.)

• Participate in Market Trials to ensure connectivity and confirm functionality

19

Types of Market Participants

20

Key Participants Function

Generation Owners An entity that owns or leases facilities for generation that are used to supply energy in SPP’s footprint

Transmission Owners An SPP member that owns or leases transmission

Load Serving Entity (LSE) An entity that provides electric energy for end use customers load located within or attached to the transmission system

Power Marketer An entity that may or may not own assets, who buys and sells generation or participates in the Transmission Congestion Rights (TCR) market

Market Participant Roles and Responsibilities

• Market Participants are responsible for:

• Submitting Resource Offers (Energy, Operating Reserves, and Virtual), Demand Bids, Interchange Schedules, and Bilateral Settlement Schedules

• Own or bid to buy Transmission Congestion Rights (TCRs)

• Settle transactions through SPP

21


MARKET MONITORING

22

Market Monitoring

Objective - Ensure the integrity of the SPP markets

Two Primary Responsibilities

1. Monitoring and prevention abusive practices by Market Participants• Market power abuse

• Market manipulation and gaming

2. Monitoring and improving market efficiency• Identify market design flaws and recommend changes

• Monitor system operators to identify and correct inefficient processes or procedures

23

Monitoring Reports

• Annual / Monthly reports– Required under SPP Tariff– Provides overview of market activities and highlights

any major developments

• Special Studies– Demand Response Assessment– External Generation Access Assessment

• FERC weekly pricing updates– Pricing changes– Congestion updates

24


SYSTEM MODELS

25

Network Model

• Physical representation of the Transmission System Network Model where electrical equipment components (e.g. generators, loads, transmission lines, and transformers) connect

26

Commercial Model• Represents the financial market relationships of the Market Participants

and the Asset Owners (AO), and the commercial relationships among the elements of the Network Model

27

Market Participant: Entity that is financially obligated to SPP for market settlements

Asset Owner: Typically, but not necessarily, represents a company. Asset Owners can own any combination of generation, load, ARR and/or TCR assets within the SPP region

Settlement Locations: Energy supply and demand is financially settled at the Settlement Locations

Aggregated Pricing Node: Represents an aggregation of two or more PNodes using weighting factors

Pricing Node: Finest level of granularity in the Commercial Model and have a one-to-one relationship with a Node

Node: Represents Electrical Nodes (Enode) within the Network Model

Market Participant

Market Participant

Asset OwnerAsset Owner

Settlement Locations

Settlement Locations

Aggregated Pricing Node (APNode)

Aggregated Pricing Node (APNode)

Node (ENode)Node

(ENode)

Pricing Node (PNode)

Pricing Node (PNode)

Network Model

Com

mer

cial

Mod

el

Model Updates• Reliability-related model changes occur monthly

• Market Registration related model changes• Existing Market Participants: occurs every other month

• New Market Participants: occurs every 4 months (April, August, December)

• Model change is required for:• Addition, deletion, or change of electric power system components

• Asset registration changes, additions, or deletions

• Changes to Pricing Nodes

• Changes in Market Participant registration

• Model update cycle details are available in Appendix E of the Integrated Marketplace Protocols

28


MARKETPLACE PROCESSES, PRODUCTS AND TIMELINE

29

30

• The design relationship between the market processes is illustrated below

Integrated Marketplace: Processes

Day-Ahead Market

(DA Market)

Real-Time Balancing

Market(RTBM)

Reliability Unit Commitment

(RUC)

DA Market & Net RTBM Settlements

DA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve

Requirements

DA Market Commitment, Cleared Energy and Operating

Reserve (MW and Price) (hourly)

Resource and Load

Meter Data

Dispatch Instruction, cleared Operating Reserve

(MW) (5 minute)

DA Market Commitment

RUC Commitment

EMS

RTBM Offers, Load Forecast, Operating

Reserve Requirements

TCR Markets




(MW and Price) (5 minute)

Day-Ahead Market

(DA Market)

Real-Time Balancing

Market(RTBM)

Reliability Unit Commitment

(RUC)

DA Market & Net RTBM Settlements

DA Market Offers (Energy and Operating Reserve), Bids, Operating Reserve

Requirements

DA Market Commitment, Cleared Energy and Operating

Reserve (MW and Price) (hourly)

Resource and Load

Meter Data


(MW) (5 minute)

DA Market Commitment

RUC Commitment

EMS



TCR Markets




(MW and Price) (5 minute)

31

– Day-Ahead Market• Clears for the next Operating Day • Financially binding market whose purpose is to match the set of market supply and

market demand made available

– Reliability Unit Commitment (RUC) Process• Exists for the same time period as Day-Ahead Market (Day-Ahead RUC)• Exists for the balance of the day (Intra-Day RUC)• Operationally binding process whose purpose is to ensure that the supply capacity

cleared in the Day-Ahead Market (or for the current Operating for Intra-Day RUC) satisfactorily covers the RTO load and reliability requirement forecasts

– Real-Time Balancing Market (RTBM)• Clears for the next 5-minute period• Financially and Operationally binding market whose purpose is to ensure that market

resources committed through Day-Ahead Market or lastly approved RUC process are dispatched according to Real-Time load forecast

Integrated Marketplace: Processes (cont’d)

32

– Reserve Market• Integrated within the Day-Ahead Market, RUC process and the Real-Time Balancing

Market through co-optimization• Main purpose is to ensure that enough reserve capacity is procured so that the

system can smoothly respond to contingencies

– Auction Revenue Rights Process / Transmission Revenue Rights Market• Performed / Clears annually and monthly• Provides market participants with a mechanism to be pro-active and hedge against

the anticipated Day-Ahead market congestion, or increase their financial benefits

– Settlement Process• Performed on a 5-minute basis• Provides market participants with a measure of the financial benefits associated with

their participation in the Day-Ahead and Real-Time Balancing Markets

Integrated Marketplace: Processes (cont’d)

Integrated Marketplace: Products• There are five market products, which can be grouped in two categories:

• Energy - An amount of electricity that is Bid or Offered, produced, consumed, sold or transmitted over a period of time, which is measured or calculated in megawatt hours (MWh).

• Operating Reserve

• Regulating Up Reserve – Reserve capacity that is available for the purpose of providing Regulation Deployment in the up direction.

• Regulating Down Reserve - Reserve capacity that is available for the purpose of providing Regulation Deployment in the down direction.

• Spinning Reserve – From Resources that are synchronized to the system and fully available to serve load within the Contingency Reserve Deployment Period following a contingency event.

• Supplemental Reserve – Typically from off-line Resources that are capable of being synchronized to the system and available to serve load within the Contingency Reserve Deployment Period following a contingency event. Could also be provided by online synchronized resources.

33

Applies to: Day-Ahead, RUC, RTBM, ARR/TCR, Settlement

Applies to: Day-Ahead, RUC, RTBM, Settlement

Regulation Reserve

Contingency Reserve

Integrated Marketplace: Products Characteristics

34

Energy

Spinning Reserves

Regulation UP

Reserves

Energy capable of being synchronized and deployed in abnormal conditions

Energy synchronized and on-line ready to serve load in abnormal conditions

Manages the instantaneous difference between net actual and scheduled interchange

On-Line; deployed as dispatched —Regulation-UpRegulation-Down

On-Line; can respond in 10 minutes

Off-Line / On-Line;Can respond in 10 minutes

Regulation Down

Reserves

Supplemental Reserve

Integrated Marketplace Timeline

35

Pre Day-Ahead Market Activities

OD -7Day-Ahead

OD -1Day-Ahead

ODReal-Time

OD 1 – OD 167Post Process

Outage Outage SubmittalSubmittal

Multi-Day Multi-Day Reliability Reliability

AssessmentAssessment

ARR / TCRARR / TCR

RegistrationRegistration

Settlement Settlement StatementsStatements

DisputesDisputes

InvoicesInvoices

MeteringMetering

Demand Demand BidsBids

Interchange Interchange TransactionsTransactions

Resource Resource OffersOffers

Market Market Results and Results and

PricesPrices

Day-Ahead Day-Ahead RUC RUC

CommitmenCommitment Periodt Period

Virtual Bids Virtual Bids and Offersand Offers

Interchange Interchange TransactionsTransactions

Market Market Results and Results and

PricesPrices

Unit Unit DispatchDispatch

Supply OffersSupply Offers


MARKET PRICING

36

Market PricingDefinition• Locational Marginal Price (LMP)

• The LMP at pricing location is defined as the cost to serve the next increment of load at that location

• (Energy) pricing locations are known as Settlement Locations

• LMP = Marginal Energy Component(MEC) + Marginal Congestion Component(MCC) + Marginal Loss Component (MLC)

• Market Clearing Price (MCP)• The MCP for an Operating Reserve product at a Reserve Zone is defined as

the cost to provide the next capacity increment of that Operating Reserve product at that specific Reserve Zone

• Auction Clearing Price (ACP)• The prices generated at each source and sink Settlement Location in each

round of the Annual TCR Auction and Monthly TCR Auction based upon the submitted TCR Offers and Bids

37

Market PricingLMP – Key Concepts• Locational Marginal Price (LMP)

• Applies to Energy product only

• Can be impacted by both Energy and Operating Reserve offers

• Hourly LMPs are posted for the Day-Ahead Market

• 5-Minute LMPs are posted for each Settlement Location for the Real-Time Balancing Market

• Congestion and Loss factors cause price separation

38

Market PricingMCP – Key Concepts• Market Clearing Price (MCP)

• Applies to Operating Reserve product only

• Can be impacted by both Energy and Operating Reserve offers

• Hourly MCPs posted for the Day-Ahead Market

• 5-Minute MCPs posted for the Real-Time Balancing Market

• One MCP per Operating Reserve by Reserve Zone

39

Market PricingMCP – Reserve Zone Example

40

Market PricingACP – Key Concepts• Auction Clearing Price (ACP)

• Prices generated at each source and sink Settlement Location in each round of the Annual TCR Auction and Monthly TCR Auction based upon the TCR Offers and Bids submitted

• The key principle of Auction Clearing algorithm is to maximize the total auction value while holding the flows on the constrained transmission lines to their limit

• Bids are awarded from highest to lowest and Offers are awarded from lowest to highest until the TCR availability is consumed

• The auction value is calculated for each TCR based on its clearing price on the path

41

PRE DAY-AHEAD MARKET ACTIVITIESSection 3

42

Topics Covered

• Market registration

• Outage Notification

• ARRs/TCRs Purposes

• Multi-Day Reliability Assessment

43

PRE DAY-AHEAD MARKET ACTIVITIES:

MARKET REGISTRATION

44

Market Registration• In order to do business with SPP,

you must be a registered Market Participant or be represented by one.

• Market Participants must register their assets (loads and resources) prior to any market participation:

• Behind the meter generation less than 10MWs are excluded.

• Registration data represents a Market Participants physical and financial responsibility.

45

Meter Agent

Market RegistrationResource Types

• Resources that are required to register in order to participate in the Integrated Marketplace:

• Generating Unit

• Plant

• Dispatchable Demand Response

• Block Demand Response

• Combined Cycle

• Jointly Owned Unit

• Dispatchable Variable Energy

• Non-Dispatchable Variable Energy

46

Market RegistrationCharacteristics

• Resource characteristics required for asset registration:

• Location of Physical Resource

• Legal Owner

• Resource Type

• Non-Price Related Operating Parameters

• Settlement Location ID

• Resource Settlement Area ID

• Real-Time Settlement Meter Data

47

Market RegistrationUpcoming Registration Activity Timeline

• Initial registration will include the following activities:

48

DateRegistration Activity

SPP Market ParticipantFebruary 1, 2012 Provide MPs with a blank

registration packetReview registration packet, understand the data required, and assess legal agreements

April 1, 2012 Provide MPs with a draft of a partially completed registration packet

Review registration packet, verify existing data, provide any additional information

June 1, 2012 Review and process completed registration packets

Return completed registration packets and legal documents to SPP

October 1, 2012 Notify MPs of systematic model change completion

Test model changes and report any defects


OUTAGE NOTIFICATION

49

Outage Notification

• Market Participants will need to notify SPP when a generation and/or transmission asset needs to deviate from its normal operations

• Notifications are in the form of an outage submittal through the Outage Scheduler

• Types of outages include:

• Unplanned (Deration, Emergency, Forced)

• Planned (Maintenance, Construction)

50


AUCTION REVENUE RIGHTS / TRANSMISSION CONGESTION RIGHTS (ARR / TCR)

51

Pre Day-Ahead Market ActivitiesARRs / TCRs• ARRs and TCRs are Congestion Hedging instruments Market

Participants use to manage the anticipated Day-Ahead congestion.

• The allocation of ARRs occurs annually and incrementally (i.e. not systematic every month) , shortly before the TCR auction for the same planning period.

• The auction of TCRs occurs annually and monthly, in advance of the target Operating Day.

• Further discussion in the ARRs/TCRs section52


MULTI-DAY RELIABILITY ASSESSMENT

53

Pre Day-Ahead Market ActivitiesMulti-Day Reliability Assessment• Process that is performed prior to the Operating Day to

assess capacity adequacy for the Operating Day (at least three days prior to the Operating Day)

• Resources with long lead times (“Long-Lead-Time Resource”) that cannot be considered as part of the Day-Ahead Market or Day-Ahead RUC will be considered

• SPP will issue a commitment order to affected Market Participants

• Resources committed during the Multi-Day Reliability Assessment process are subject to Day-Ahead Make-Whole Payment given that they meet the eligibility criteria

54

Pre Day-Ahead Market ActivitiesMulti-Day Reliability Assessment (cont’d)• Inputs to Multi-Day Reliability

Assessment Process are• RTBM Resource Offers

• Fixed Import and Export Interchange Transactions

• SPP Operating Reserve Requirements

• SPP Forecasts (Load and Wind)

• Transmission System Topology

• Resource Outages

• SPP performs analysis and selects Resources for commitment in merit order (least cost Resource based upon the

commitment cost) until sufficient capacity is committed

55

RTBM Resource

Offers

Fixed Interchange Schedules

Operating Reserve

Requirements

SPP Forecasts (Load and

Wind)

Transmission System

Topology

Resource Outage

Notifications

DAY-AHEAD MARKET ACTIVITIESSection 4

56

Topics Covered• Day-Ahead Market: Definition and Objective, Resources

Offers

• Day-Ahead Market Clearing

• Day-Ahead Make-Whole Payment

• Day-Ahead Market Timeline

• Day-Ahead RUC: Definition and Objective

• Day-Ahead RUC Execution

• Day-Ahead RUC Timeline

57

Day-Ahead MarketWhat is the Day-Ahead Market?• Forward Market that provides Market Participants with the ability

to submit:

• offers to sell Energy and Operating Reserve

• bids to purchase Energy

• Simultaneously co-optimizes Energy and Operating Reserve using SCUC and SCED algorithms

• Ensures that resources are scheduled to be online to meet bid-in load demands and operating reserve obligations for the next Operating Day

• Financially binding market. Based on clearing market prices:

• Injection or supply transactions receive credit

• Withdrawal or demand transactions receive charge 58

59

• The Day-Ahead Market outcome is a schedule that minimizes SPP total [production offer costs minus demand bid revenues], as determined based on Market Participants Offers and Bids

Day-Ahead MarketWhat is the Day-Ahead Market?

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Meg

awat

ts Generation cleared in DA Market

Bid in Load and Operating Reserves cleared in DA Market

Hour

Self Committed Resources(Day Ahead Input)

Day-Ahead MarketResource Offers• A Resource Offer is a comprehensive set of information

that will allow a Market Participant to sell generation into the SPP Integrated Marketplace

• A Resource Offer consists of the following:

• Resource Limits

• Resource Parameters (start-up, no-load)

• Resource Offer curves

• Market Participant’s Day-Ahead Resource Offers must offer enough capacity to cover their bid-in loads and Operating Reserve requirements

60

Day-Ahead MarketResource Offer – Limits and Parameters• What are Resource Limits and Parameters?

• Resource limits and parameters are Resource operational constraints submitted by Market Participants

• They are taken into consideration by SPP when the Resource is evaluated for commitment and dispatch

• They can be changed, many of them hourly

61

Resource Limits Resource ParametersEconomic Min / MaxNormal Min / MaxEmergency Min / MaxRegulation Min / MaxRamp Rates

Min / Max Run TimeMinimum Down TimeMax Daily / Weekly StartsStart-Up TimesStart-Up CostsNo-Load Costs

Day-Ahead MarketResource Offer – Resource Limits

• Resource Limits

• Emergency

• Economic

• Regulation

62Off-Line

Maximum Emergency Capacity Operating Limit

Minimum Emergency Capacity Operating Limit

Minimum Economic Capacity Operating Limit

Minimum Regulation Capacity Operating Limit

Maximum Economic Capacity Operating LimitMaximum Regulation Capacity Operating Limit

VALIDATION RULES

Min. Economic ≥ Min. Emergency

Min. Regulation ≥ Min. Economic

Max. Regulation ≥ Min. Regulation

Max. Economic ≥ Max. Regulation

Min. Emergency ≥ Max. Economic

Day-Ahead MarketResource Offer – Resource Limits (cont’d)• Ramp Rates

• How fast a Resource can increase or decrease production

• Submitted as a curve in MW / Minutes for:

• Energy• Regulation• Contingency Reserve

63

MW MW/Min50 5

100 8150 15200 23250 29300 33350 36

0

5

10

15

20

25

30

35

40

0 50 100 150 200 250 300 350 400

MW

/Min

utes

Megawatts

Ramp Rate

Day-Ahead MarketResource Offer - Commitment Status• Commitment status indicates to SPP how the Resource should

be considered for unit commitment

• Commitment Status may be specified separately for use in the Day-Ahead Market, RUC or Real-Time Balancing Market

• Market – Resource is available for SPP economic commitment

• Self – Market Participant is committing the Resource

• Reliability – Resource is off-line and is only available for commitment by SPP if there is an anticipated reliability issue

• Outage – Resource is unavailable due to a planned, forced, maintenance or other approved outage

• Not Participating – The Resource is otherwise available but has elected not to participate in the Day Ahead Market.

64

Day-Ahead MarketResource Offer - Dispatch Status• Dispatch Status indicates to SPP how the Resource should be

considered for dispatch once it is committed

• Dispatch Status is submitted for each product (Energy, Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve)

65

Product Dispatch Status Description

Energy Market Available for economic dispatch if committed

Not Qualified Not qualified to provide Energy

Operating Reserve (OR) Market Available to clear the Operating Reserve product based on submitted OR Offers

Fixed MP is fixing the OR product clearing at the specified MW level

Not Qualified Not qualified to supply ORs because of physical restrictions

Day-Ahead MarketResource Offer – Resource Parameters

• Start-Up Costs• Cost to bring a resource on-line

and to its Minimum Economic Capacity Operating Limit

• Start-up costs of the resource is based on the unit status (cold, intermediate or hot) and the commitment start time

• No-Load Costs• Cost to operate a resource at

zero MW output66

$$$

$$

$

Day-Ahead MarketResource Offer – Resource Parameters (cont’d)

• An Resource Offer Curve represents an offer to provide Energy from a Resource

• Two types of Curves – Slope or Block

• Monotonically non-decreasing

• Submission can begin seven days prior to the Operating Day and updated up to 1100 CPT Day-Ahead

• Offers can vary hourly

• Can submit up to 10 price/quantity pairs

• Submitted Resource Offers roll forward hour to hour until changed within each respective market

67

Day-Ahead MarketResource Offer – Resource Parameters (cont’d)• Run and Start Times

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Resource Parameter Description

Maximum Daily Starts Maximum number of times a Resource can be started within a 24-hour period.

Maximum Weekly Starts Maximum number of times a Resource can be started within a rolling 7-day period.

Maximum Daily Energy Maximum amount of Energy, in MWh, that is available to be produced in an Operating Day from a particular Resource.

Minimum Run Time Minimum number of hours a Resource must run from the time the Resource is put online to the time the Resource is shut down.

Maximum Run Time Maximum number of hours a Resource must run from the time the Resource is synchronized to the time the Resource is off-line.

Minimum Down Time Minimum number of hours required following desynchronization that a Resource must remain off-line prior to a subsequent synchronization.

Day-Ahead MarketResource Offer – Resource Parameters (cont’d)• Start Times

• Maximum Weekly Starts is the maximum number of times a unit can be started within a rolling 7-day period

• Maximum Daily Starts is the maximum number of times that a unit can be started in a 24-hour period

• Maximum Daily Starts Maximum Weekly Starts

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Mon Tues Wed Thurs Fri Sat Sun0500 Start Start

0600 Start Start

1000 Stop Stop

1600 Start

1700 Start

2200 Stop

2300 Stop Stop Stop

Total Daily 1 2 1 2Total Weekly 1 3 4 6

# of Starts

Max Daily 2

Max Weekly 6

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• Consider the following Market Participant’s Resource:

• Assuming the Market Participant decides to offer this Resource at cost except for the energy cost curve being offered 20% above cost between 80 MW and 120 MW:– formulate its 3-part offer.

Resource Type 120 MW Gas Unit

Fuel Gas

Fuel Cost ($/MMBTU) 7

Incremental Heat Rate (MMBTU/MWh) 10

No-Load Heat (MMBTU/Hr) 100

Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500

Min Econ. Capacity Limit (MW) 25

Max Econ. Capacity Limit (MW) 120

Day-Ahead MarketResource Offer – Example

71

• Consider the following Market Participant Resource:

Resource Type 120 MW Gas Unit

Fuel Gas

Fuel Cost ($/MMBTU) 7

Incremental Heat Rate (MMBTU/MWh) 10

No-Load Heat (MMBTU/Hr) 100

Startup Fuel Requirement (MMBTU) Hot=1000;Warm=2000;Cold=2500

Min Econ. Capacity Limit (MW) 25

Max Econ. Capacity Limit (MW) 120

Hot Warm Cold

7,000 14,000 17,500

MW $/MWh

25 70

80 84

120 84700

Startup Offer ($/start):No Load Offer ($/h):

Energy Offer Curve (Block)


Day-Ahead MarketResource Offer – Resource Parameters (cont’d)

• Run Times• Minimum Run Time is the

minimum consecutive number of hours a Resource should remain online from the time it was synchronized, before being considered for shutdown.

• Maximum Run Time is the maximum number of consecutive hours a Resource should remain online from the time it was synchronized.

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HE 0700Online

HE 0200Available for commitment

HE 2300Offline

HE 2300Available for shutdown

Min Run (Hrs) 16

3Min Down (Hrs)

Max Run (Hrs) 144

Day 1

Day 2

Day 3

Day 4

Day 5

Day 6

Day 7

0001Online

2400Off-Line

Resource Offer Types (cont’d)Jointly Owned Units (JOUs)

• A unit with multiple owners that can elect whether to submit individual or combined resource options

Individual Resource Option

Combined Resource Option

Each ownership share is committed independently for commitment and dispatch status

Each ownership share is committed separately for dispatch status only

Each ownership share ≥ Minimum physical capacity operating limit

All ownership shares must be committed or none at all

73

Resource Offers (cont’d)Combined Cycle Resource• Consists of combustion turbines and steam

turbines

• The exhaust of one heat engine is used as a heat source for the other

• 3 Options for submitting Combined Cycle Resource Offers:

Option Configuration Implementation

Single Aggregate Combustion and Steam Turbines

Committed, dispatched, and settled as any other resource

Separate Component All Combustion or all Steam Turbines

Committed and dispatched independently; settled as anyother resource

Pseudo CombinedCycle Resource

1 Combustion turbine and a portion of the steam turbine

Committed and dispatched independently; settled as any other resource

74

Resource Offers (cont’d)Demand Response (DDR) Resource• Dispatchable Demand Response (DDR) Resource

• A Resource created to model demand reduction associated with controllable load and/or a behind-the-meter generator that is dispatchable on a 5-minute basis

• Reporting Options for actual DDR Resource Output:

• Block Demand Response Resource

• A Resource created to model demand reduction that is not dispatchable on a 5-minute basis but can be committed and dispatched in hourly blocks

• Uses Calculated Response Production Option to determine the amount of Real-Time resource production and actual resource production

Submitted ResourceProduction Option

Calculated Resource Production Option

MPs submit amount of response provided via ICCP and will represent the Real-Time resource production

SPP calculates the Real-Time resource output for operational dispatch and actual resource output for settlements

75


76

• MP1 submits the DA Incremental Offer Curve below for resource Gen1 for hour 1100. Assuming Gen1 is online and that DA Market LMP clears at $40/MWh, determine Gen1’s expected:

•DA Energy award•DA Energy credit / charge

DA Energy Award = 65 MWh

MW $/MWh

25 10

50 25

75 50

120 60

Gen1 DA Energy Offer Curve

MP1

Gen1 Load1

DA Energy Credit/Charge = - DA Award * DA LMP = -65 x 40 = -$2600 (credit)

Day-Ahead MarketDemand Bids• A demand bid is a proposal to purchase Energy at a specified

location and period of time in the Day-Ahead Market• Only Market Participants with registered load may submit demand

bids at the registered load settlement location

• Load may submit fixed and/or price-sensitive demand bids

• Demand bids have same timeline as supply offers

• Can vary hourly by location

• Bid submittal other than for a fixed Export Interchange Transaction Bid does not apply to any of the RUC processes or RTBM

• Submitted Bids do not roll forward hour to hour

• Bid submittal for use in the Day-Ahead Market is voluntary

77

Day-Ahead MarketDemand Bids – Fixed Demand Bids• A fixed demand bid is a

bid to buy generation in the Day-Ahead market, regardless of price (price-taker)

• Bids must specify

• MW Quantity

• Settlement Load location

• Hour (s)

78

Day-Ahead MarketDemand Bids – Price Sensitive Demand Bids• A price sensitive demand

bid is a bid to buy more generation as the price decreases

• Bids must specify• MW Quantity (up to 10

price/quantity pairs, slope or block option)

• Settlement Load location

• Hour (s)

79

Day-Ahead MarketDemand Bids – Example

80

• Assume MP1 submits the DA Price Sensitive Demand Bid Curve below for resource Load1 for hour 1100. If DA Market LMP clears at $40/MW, determine Load1’s expected:

•DA Energy award•DA Energy credit / charge

DA Energy Award = 65 MWh

MW $/MWh

25 80

50 55

75 30

100 25

Load1 DA Energy Bid Curve

MP1

Gen1 Load1

DA Energy Credit/Charge = DA Award * DA LMP = 65 x 40 = $2,600 (charge)

Day-Ahead MarketInterchange Schedules• Contract for transfer of Energy between seller and buyer

• Interchange Schedules (Physical)• Transactions that crosses the boundary of the SPP Balancing

Authority Area and transfers physical energy• Classified as Import, Export, or Through transactions

81

Day-Ahead MarketInterchange Schedules • Three types of Interchange

Schedules

• Import Interchange Schedule Offer - MPs offer to purchase Energy for delivery into the SPP Balancing Authority

• Export Interchange Schedule Bids - MPs offer to purchase Energy for delivery outside the SPP Balancing Authority

• Through Interchange Schedules - MP schedule submitted between two external interfaces for moving Energy through the SPP Balancing Authority

82

Import

Export

Through Interchange Schedule

SPP

Day-Ahead MarketVirtual Transactions • Virtual Transactions are Day-Ahead Energy market instruments

• A Virtual Transaction can either be:

• Virtual Energy Offer: a proposal by a Market Participant to sell Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Resource.

• Virtual Energy Bid: a proposal by a Market Participant to purchase Energy at a specified price, Settlement Location and period of time in the Day-Ahead Market that is not associated with a physical Load.

• When cleared by the Day-Ahead Market, a Virtual transaction will be settled at the price difference between the Day-Ahead LMP and the Real-Time LMP

83

84

• In general, the net effect of Virtual Transactions is to cause the Day-Ahead LMPs and RTBM LMPs to converge:– If a Settlement Location is expected to be priced higher in day-ahead than in

real-time, market participants may be incented to submit Virtual offers until, overtime, the two markets equalize in price

• Mechanics of a Virtual Offer– Offer Quantity/Price into DA

Market– If DA LMP >= Offer Price, then

transaction clears DA Market– If cleared, market participant

must buy Energy back at real-time LMP:

• Profit if DA LMP >= RTBM LMP,• Loss otherwise

• Mechanics of a Virtual Bid– Bid Quantity/Price into DA

Market– If DA LMP <= Bid Price, then

transaction clears DA Market– If cleared, market participant

must sell Energy back at real-time LMP:

• Profit if DA LMP <= RTBM LMP,• Loss otherwise

Day-Ahead MarketVirtual Transactions

Day-Ahead MarketVirtual Transaction - Rules• Virtual Energy Offers and Bids are subject to a transaction fee

• Virtual Energy Offers and Bids can be submitted by a Market Participant at any Settlement Location, subject to meeting credit requirements

• A Market Participant may submit a single Virtual Energy Bid and a single Virtual Energy Offer for each Asset Owners at any Settlement Location for a particular Hour

• Each Virtual Energy Offer and Bid must specify a start and stop Hour within the applicable Operating Day

85

86

• MP1 submits a Virtual Energy Offer at Load1 settlement location for hour 1100 in Day-Ahead. Assuming the DA LMP and RTBM LMPs at Load1’s settlement location are $ 40/MWH and $55/MWH respectively, determine the transaction’s hourly:– Expected DA Energy award and Net Energy Settlement

MW $/MWh

25 10

50 25

75 60

120 65

Virtual DA Energy Offer Curve

MP1

Gen1 Load1

• DA Energy Award= 60 MW • Net Energy Settlement = - DA Award * (DA LMP –

RTBM LMP) = -60 x (40 – 55) = $900 (charge)

Day-Ahead MarketVirtual Transactions - Example

Day-Ahead MarketBilateral Settlement Schedules

87

88

Day-Ahead MarketBilateral Settlement Schedule - Example

MP1 MP2

Gen1 Load2

DA Market Clearing (Supply)Energy Award(MW): 100

DA LMP ($/MWH): 40

DA Market Clearing (Load)Energy Award (MW): 100

DA LMP ($/MWH): 50

Assume the Day-Ahead Market clears as shown above. MP2 purchases 100 MW from MP1 at 45 $/MWH by entering into an Energy financial schedule. The parties agree to submit an 100 MW Energy Bilateral Settlement Schedule that is settled at MP1 Settlement Location. Determine MP1 and MP2 hourly DA impacts if:

- Both Market Participants confirm the financial schedule with SPP

89


MP1 MP2

Gen1 Load2

DA Market Clearing (Supply)Energy Award (MW): 100

DA LMP ($/MWH): 40


DA LMP ($/MWH): 50

MP1 SPP SettlementGen1 DA Settlement = -DA Award x DA LMP = -100 x 40 = -$4,000 (credit)

DA Bilateral Schedule Settlement = Sched x DA LMP = 100 x 40 = $4,000 (charge)DA Net Settlement =- 4,000 + 4,000 = $0

MP1 Books (this transaction occurs outside SPP)MP1 gets paid by MP2 an amount equal to $4,500 (=100 x 45)

In total, the impact on MP1 is a total credit of $4,500 since the Bilateral Schedule was confirmed with SPP

90


MP1 MP2

Gen1 Load2

DA Market Clearing (Supply)Energy Award (MW): 100

DA LMP ($/MWH): 40


DA LMP ($/MWH): 50

MP2 SPP SettlementLoad2 DA Settlement = DA Award x DA LMP = 100 x 50 = $5,000 (charge)

DA Bilateral Schedule Settlement = -Sched x DA LMP = -100 x 40 = $4,000 (credit)DA Net Settlement = 5,000 – 4,000 = $1,000 (charge)

MP2 Books (this transaction occurs outside SPP)MP2 pays MP1 an amount equal to $4,500 ( = 100 x 45)

In total, the impact on MP2 is a total charge of $5,500 since the Bilateral Schedule was confirmed with SPP

DAY-AHEAD MARKET ACTIVITIES:

DAY-AHEAD MARKET CLEARING

91

Day-Ahead Market ActivitiesDay-Ahead Market Clearing and Results• SPP clears the Day-Ahead Market between 1100 and 1600 Day-Ahead

for the entire next Operating Day

• Day-Ahead Market Clearing requires the following algorithms:• Security-Constrained Unit Commitment (SCUC)

• Security-Constrained Economic Dispatch (SCED)

• Simultaneous Feasibility Test (SFT)

• Results of the Day-Ahead Market include hourly:• Market product awards for each market instrument

• LMP for each Settlement Location

• MCP for each Operating Reserve product per Reserve Zone

92

93

Day-Ahead Market Activities: Clearing

Cleared Energy & OR Offers

Cleared Energy Bids: Virtuals &

Demand

Cleared Import, Export &

Interchange Transactions

Co-optimizedSCUC and

SCED

DA Market Demand Bids

DA Market Resource Offers: Energy and OR

DA Market Import, Export & Interchange Transactions

Resource Outage Notifications

SPP Operating Reserve Requirements

Virtual Energy Offers and Bids

94

• By 7:00AM: SPP publishes load and wind Forecast, provides Market Participants with their Operating Reserve Requirement

• By 11:00AM: Market Participants submit their Day-Ahead Demand bids, Resource Offers and outage notification, Virtual, Bilateral and Physical Transactions information to SPP

• Between 11:00AM and 4:00PM: SPP clears Day-Ahead Market

• By 4:00PM: SPP publishes the results of Day-Ahead Market

Day-Ahead Market ActivitiesTimeline

95

• Resources committed by the Day-Ahead Market should be financially made whole. The Make-Whole Payment guarantees that they receive enough revenues to cover their 3-part offer and Operating Reserve offer, for the Operating Day

Daily Energy Cost

Daily No-Load Cost

Daily Startup Cost

Daily Market Revenues

Make-Whole Payment

Daily Op. Reserve Cost

• Generation resources that self-commit or self-schedule into the market are not eligible for:– Startup cost recovery if the

resource self-commits– No-load cost if the resource self-

commit or self-schedules– Energy cost for the self-schedule

amount– Operating Reserve cost for the

self-schedule amount

Day-Ahead Market ActivitiesMake-Whole Payment

96

MW $/MWh

25 10

50 25

75 50

120 60


MP1

Gen1 Load1

Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500

No-Load ($/hr) 700

Day-Ahead Market ActivitiesMake-Whole Payment – Example 1

97

• Consider Market participant MP1– Gen1 is initially off-line– Gen1 commitment status is Market for the entire day

Day-Ahead – ISO awards Gen1 65MW for each hour Day-Ahead– LMP at Gen1 pricing location is 40 $/MWH for all hours

Day-Ahead

• Is Gen1 eligible for Make-Whole payment?

• DA Revenues = Sum of hourly [DA LMP x DA Energy Award] = (40 x 65) x 24 = $62,400

• DA Costs = Startup Cost + Sum of hourly [DA energy Cost + DA No-Load cost] = 17,500 + (1,175 + 700) x 24 = $62,500

• DA Make-Whole Payment = Min [ 0 ; DA Revenues – DA Costs] = -$100 (credit)

MW $/MWh

25 10

50 25

75 50

120 60


MP1

Gen1 Load1

Gen 1Oper. Cap. Max(MW): 120Startup Offer ($/start) 17,500

No-Load ($/hr) 700

Day-Ahead Market ActivitiesMake-Whole Payment – Example 2

98

Day-Ahead MarketCo-optimization - Example

MP2

Gen MP1Econ. Oper. Cap. Min (MW): 50Econ. Oper. Cap. Max (MW): 120Energy Offer Cost ($/MWH): 30

Spin Cap. Max (MW): 15Spin Offer Cost ($/MW): 5

Load MP1Energy Fixed Bid (MW): 100




Balancing Authority 1

MP1

Balancing Authority 2

Balancing AuthoritySpin Requirement (MW): 10

Balancing AuthoritySpin Requirement (MW): 10

Consider 2 Market Participants MP1 and MP2 above, each with generation resources (assume these resources have 1.5 MW/Min Energy and CR ramp rates, no startup or no-load cost, and operate in a lossless network), load to serve and reliability requirement in the form of Spinning Reserve. Note how part of MP1’s load is in MP2’s service territory.

How will these Market Participants benefit most from SPP future market operations?

Load MP1@2Energy Fixed Bid (MW): 10

99


MP2






In SPP future market operations, there will be only one Consolidated Balancing Authority, responsible for establishing reliability requirements throughout SPP network footprint.

In the following case studies, we assume that:

Both Market Participants belong to the same Reserve Zone and offer their generation at cost,

The network has no congestion and no losses.

Reserve ZoneSpin Requirement (MW): 20

Consolidated Balancing Authority

MP1Load MP2

Energy Fixed Bid (MW): 90


100


MP2



Fixed Spin (MW): 11




Fixed Spin (MW): 9

Let’s determine for the Hour:

Each Market Participant awards (Energy and Spin), operational cost and LMP,

The Spinning Reserve Zone MCP,

SPP DA total production cost


MP1

Market Participants self-schedule their participation in the market (Fixed Spin: 11 MW for MP1 and 9 MW for MP2)



101


MP2

Gen MP1Energy Award (MW): 109

Spin Award (MW): 11

Load MP1Energy Award (MW): 100


Spin Award (MW): 9

MP1 Gen. Award (MW)

Operational Cost ($)

Margin Analysis ($/MW)

Energy 109 3,270 20

Spin 11 55 5

Total - 3,325 -

MP2 Gen. Award (MW)

Operational Cost

($)


Energy 91 4,550 0

Spin 9 90 0

Total - 4,640 -

LMP = 50 $/MWH LMP = 50 $/MWH

DA Total System Operational Cost = $ 7,965

Spin MCP = 10 $/MW


MP110 MW >>


Load MP1@2Energy Award (MW): 10

Market Participants self-schedule their participation in the market (Fixed Spin: 11 MW for MP1 and 9 MW for MP2)

102


MP2






Let’s now determine for the Hour:


The Reserve Zone Spin MCP,

SPP total production cost


Consolidated Balancing Authority

MP1

Market Participants let SPP fully co-optimize the market



103


MP2


Spin Award (MW): 5



Spin Award (MW): 15

MP1 Gen. Award (MW)



Energy 115 3,450 20

Spin 5 25 20

Total - 3,475 -

MP2 Gen. Award (MW)



Energy 85 4,250 0

Spin 15 150 15

Total - 4,400 -



15 MW >>

Spin MCP = 25 $/MW

(vs. $ 7,965 previously)



MP1Load MP2

Energy Award (MW): 90


104


MP2


Spin Award (MW): 5



Spin Award (MW): 15


15 MW >>

Spin MCP = 25 $/MW



MP1Load MP2



Explaining Spin MCP

By definition, the Spinning Reserve MCP represents the cost of procuring an additional increment of Spinning Reserve from the Reserve Zone. That value could be extracted through sensitivity analysis.

105


MP2


Spin Award (MW): 5



Spin Award (MW): 15


15 MW >>

Base Case Reserve ZoneSpin Requirement (MW): 20

MP1Load MP2



MP2

Gen MP1Energy Award (MW): 114.9

Spin Award (MW): 5.1



Spin Award (MW): 15

DA Total System Operational Cost = $ 7,877.5

14.9 MW >>

Sensitivity analysis: Adding 0.1 MW of Spin Requirement Reserve Zone

Spin Requirement (MW): 20.1

MP1Load MP2



106



Explaining Spin MCP

Given the base solution, the most economical way to provide an additional increment of Spinning Reserve requires:

- Decreasing Gen MP1 Energy award by 0.1 MW (from 115 to 114.9)

- Increasing Gen MP2 Energy award by 0.1 MW (from 85 to 85.1)

- Increasing Gen MP1 Spinning Reserve Award by 0.1 MW (from 5 to 5.1)

Production Cost Impact = (7,877.5 – 7,875) / 0.1 = 25 $/MW

MP2


Spin Award (MW): 5.1



Spin Award (MW): 15

DA Total System Operational Cost = $ 7,877.5

14.9 MW >>

Reserve ZoneSpin Requirement (MW): 20.1

MP1Load MP2



Sensitivity analysis: Adding 0.1 MW of Spin Requirement

DAY-AHEAD ACTIVITIES:

RUC COMMITMENT PERIOD

107

Day-Ahead ActivitiesReliability Unit Commitment (RUC)• The Reliability Unit Commitment (RUC) process is a market mechanism

that ensures there is enough capacity committed in order to cover the system load and Operating Reserve requirement forecasts, as determined by the RTO.

• Purpose of running a Day-Ahead RUC process is to ensure a reliable operating plan for the next Operating Day.

• The Day-Ahead RUC is executed shortly after the Day-Ahead Market completes.

• The clearing in the RUC process is performed via a Security-Constrained Unit Commitment (SCUC) algorithm.

108

109

• The Day-Ahead RUC process outcome is a schedule that minimizes SPP total commitment costs, as determined based on generation resources (real-time) offers and system load and Operating Reserve requirement forecasts.

Day-Ahead ActivitiesReliability Unit Commitment (RUC): Objective

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Meg

awat

ts

Generation cleared in DA Market

Bid in Load and Operating Reserve cleared in DA Market

Self Committed Resources

Generation committed in RUC

Generation de-committed in RUC

SPP Load Forecast and Operating Reserve Requirements (RUC Input)

110

Resource Commit / De-commit

Schedules

Resource Commitment/

Regulation Notifications

Fixed Interchange Transaction Curtailment

Notification

Co-optimized SCUC

DA Confirmed Import, Export & Interchange Transactions

RTBM Resource Offers

DA Resource Commit Schedules

Resource Outage Notifications

SPP Operating Reserve Requirements

SPP Forecasts (Load & Wind)

Day-Ahead ActivitiesReliability Unit Commitment (RUC) - Execution

Day-Ahead ActivitiesReliability Unit Commitment (RUC) (cont’d)• All Market Participants need to submit (Real-Time) offers for all their

registered resources that are not on planned, forced or otherwise approved outage

• The RUC process will take into consideration the cleared resource commitment schedules from the Day-Ahead Market and updated Current Operating Plan (which could have been modified as a result of a previously cleared RUC process)

• Resources committed by any RUC (Day-Ahead or Intra-Day) or Reliability Assessment processes are subject to Make-Whole Payment given that they meet the eligibility criterion

111

112

Day-Ahead Market vs. Day-Ahead RUCDifferences• Day-Ahead Market:

• Uses Day-Ahead Offer data• MPs must offer enough capacity to cover load• Clears by matching Resource Offers to Load Bids• Accepts Virtual Bids and Offers

• Day-Ahead RUC:• Uses Real-Time Offer data• MPs must submit offers for ALL resources not on outage• Uses SPP Load Forecast to make commitment decisions• Does NOT evaluate Virtual Bids and Offers

113

• Between 4:00 PM and 5:00PM: Market Participants can update RTBM Resources Offers and outage notification, including Resources that were not selected by Day-Ahead Market

• Between 5:00PM and 8:00PM: SPP execute Day-Ahead RUC

• By 8:00PM: SPP notifies Market Participants affected by Day-Ahead RUC results

Day-Ahead ActivitiesReliability Unit Commitment (RUC) - Timeline

OPERATING DAY MARKET ACTIVITIES:

INTRA-DAY RELIABILITY UNIT COMMITMENT (INTRA-DAY RUC)

114

Section 5

Topics Covered• Intra-Day RUC: Definition and Timeline

• RTBM: Definition and Objective, Resource Offers

• RTBM Clearing

115

Operating Day Market ActivitiesIntra-Day Reliability Unit Commitment (Intra-Day RUC)

• Purpose of running the Intra-Day RUC process is to ensure Resource and Operating Reserve adequacy for the Operating Day

• Process performed by SPP at least every four hours throughout the Operating Day, for the balance of the day

• All Market Participants need to submit (Real-Time) offers for all their registered resources that are not on planned, forced or otherwise approved outage

• Affected Market Participants are notified by SPP

• Resources committed by RUC or Reliability Assessment processes are subject to Make-Whole Payment given that they meet the eligibility criteria.

116

OPERATING DAY MARKET ACTIVITIES:

REAL-TIME BALANCING MARKET (RTBM)

117

118

• The Real-Time Balancing Market (RTBM) is the financially driven mechanism by which SPP balances real-time load and generation committed by the Day-Ahead Market and RUC processes.

• Its objective is to minimize the total RTO production cost based on the online resources Real-Time Offers and statuses, short-term load forecast and Operating Reserve requirements.

Real-Time Balancing Market (RTBM)What is the RTBM?

Generation Load

119

• The RTBM is executed every 5-minutes for the next Dispatch Interval

• Resources receive dispatch amount for Energy and Operating Reserve every 5-minutes

• Setpoint Instructions are issued every 4-seconds to represent the sum of Energy and Operating Reserve deployment for a Resource

• Deviations from Setpoint Instructions result in additional charges

Operating Day ActivitiesReal-Time Balancing Market (RTBM)

120

• SPP may issue a reliability directive in the form of a Manual Dispatch to resolve emergency condition (Referred to as OOME, Out-of-Merit

Energy)

• The clearing of Energy and Operating Reserves is co-optimized using a SCED algorithm

• The difference in Day-Ahead cleared and RTBM dispatch amounts are settled based on RTBM prices

• Prices are posted every 5-minutes

Operating Day ActivitiesReal-Time Balancing Market (RTBM)

• A Resource Offer is a comprehensive set of information that will allow a Market Participant to sell generation into the SPP Integrated Marketplace

• All Market Participants must submit RTBM offers for all their registered Resources that are not on planned, forced or otherwise approved outage

• Market Participants are required to keep their Resource Offer operating parameters up-to-date during the Operating Day

121

Real-Time Balancing Market (RTBM)Resource Offers

• Commitment Status• “Not Participating” status is not available for RTBM Offers

• Dispatch Status• Resource Limits

• Economic Min/ Max

• Emergency Min/ Max

• Ramp Rates

• Energy Offer Curve

• Operating Reserve Offer122

Real-Time Balancing Market (RTBM)Resource Offers – RTBM

123

• Up until 20min prior to Operating Hour: Market Participants can update the RTBM Resource Offers to be considered for the next Operating Hour

• For each of twelve 5-min intervals of the Operating Hour:– At the beginning of each interval: SPP will clear RTBM based on short-

term load forecast and Operating reserve requirement, and known Market Participants online resources statuses and offers

– At the end of each interval: SPP will publish the results of the RTBM and send Market Participants resources their dispatch instructions

Real-Time Balancing Market: Timeline

124

• MP1 clears DA as shown earlier and then submits the following Incremental Offer Curve for Resource Gen1 for hour 1100 in Real-Time. Assuming Gen1 is online and that RT Market LMP is $40/MWh, Gen1’s dispatch instruction is 60MW for each interval of the hour.

•What will be settlement for this scenario?

RT Energy Actual= 60MWh

MW $/MWh

25 10

50 25

75 60

120 65

Gen1 RT Energy Offer Curve

MP1

Gen1 Load1

RT Energy Settlement = (DA Award - RT Actual ) x RT LMP = (65-60) x 40 = $200.00 (charge)

Real-Time Balancing Market (RTBM)Resource Offers – Example

AUCTION REVENUE RIGHTS (ARRS) AND TRANSMISSION CONGESTION RIGHTS (TCRS)

Section 6

125

Topics Covered• Understanding Congestion

• ARRs/TCRs Processes Interaction: Overview and Timeline

• ARRs: Definition and Allocation Objective

• ARR Allocation: Process

• TCRs: Definition and Auction Objective

• TCR Auction: Process

• TCRs Secondary Market

• ARRs and TCRs Settlement Valuation

126

Understanding CongestionAbout Congestion

• Congestion occurs when the desired amount of electricity is unable to flow due to limitations on the transmission grid

• The transmission grid limitations could be intrinsic to the grid itself or further exacerbated by planned (e.g. transmission line maintenance) or unforeseen events (e.g. transmission line damage caused by extreme weather)

• However, one can hedge to manage the uncertainty of congestion– Electricity Congestion – ARRs/TCRs

127

128

Understanding CongestionDay-Ahead - Example

MP2







Considering the Day-Ahead co-optimization example presented earlier, let’s determine how a flowgate constraint of 12 MW on the interconnection affects:


The Reserve Zone Spin MCP,

SPP Day-Ahead total production cost


Flowgate Limit = 12 MW

MP1



129


MP2


Spin Award (MW): 8



Spin Award (MW): 12


MP1 Gen. Award (MW)



Energy 112 3,360 5

Spin 8 40 20

Total - 3,400 -

MP2 Gen. Award (MW)



Energy 88 4,400 0

Spin 12 120 15

Total - 4,520 -



12 MW >>

Spin MCP = 25 $/MW



MP1


130


MP2


Spin Award (MW): 8



Spin Award (MW): 12



12 MW >>

Spin MCP = 25 $/MW



MP1


MP1 is net Energy provider in the system since its total cleared Energy generation (112 MW) is greater than its total cleared Energy demand (110 MW).

However, part of MP1 load (Load MP1@2) is charged at a much higher LMP than is credited the Market Participant’s generation. As such, one can conclude that:

Day-Ahead Hourly Congestion Exposure for MP1 = 10 x (50 – 35) = $ 150

To the extent it is possible, MP1 will likely try to hedge that congestion exposure.

• TCRs replace the use of Energy Schedules and Native Load Schedules as congestion hedges.

• Pre-DA activity – Congestion hedging process occurs prior to Real-Time and Day-Ahead operations.

• Financial Players – External participants and those without assets in market footprint can participate.

Understanding CongestionDifferences from SPP’s current EIS Market

131

ARR/TCR Process Overview

MPs Submit Bids to

Buy TCRs

VerificationAnnual TCR

AuctionAnnual ARR

Awards

TCR MarketSettlements

TCs identify and confirm NITS and

Firm PTP

TCsNominate

Annual ARRs

IncrementalARR

Awards

TCsNominate

Incremental ARRs

Monthly TCR Auction

MPs Submit Bids to Buy TCRs and Offers to Sell

TCRs

Receive Annual and

Monthly Auction Revenue

Receive Monthly Auction

Revenue

Cleared Bids PayCleared Offers are Paid

DA MarketSettlements

Annual ARR Award MW

Cleared Bids PayCleared Offers are Paid

Incremental ARR Award

MW

132

ARR/TCR PROCESS:

TIMELINE: ANNUAL AND MONTHLY

133

Timeline: Annual ARR Allocation/TCR Auction

134

X – 2/13

Prepare for ARR Nominations Annual ARR Allocation Process Annual TCR Auction

2/14 – 3/15 4/5 – 4/23 5/3 – 5/23

Analyze Historical Data

Transmission Service

Verification

Submit Nominations

Perform SFT

Award Annual ARRs

(Round 1)

Assign Candidate ARRs

Submit Bid to Purchase and Self-Convert

Run Annual TCR Auction

Clear Annual TCR Auction / Perform SFT

Post TCR Awards

Check Auction Results

Submit Nominations

Perform SFT

Award Annual ARRs

(Round 3)

Submit Nominations

Perform SFT

Award Annual ARRs

(Round 2)

Annual TCR in effect June - May

MP Activity

SPP Staff Activity

Incremental ARR Allocation / Monthly TCR Auction Process

135

• The Monthly TCR Auction process is the mechanism through which MPs may:

• Purchase TCRs over and above those obtained in the Annual TCR Auction process

• Offer for sale any TCRs awarded in the Annual TCR Auction process

• Self-Convert available Incremental ARRs to TCRs• The Monthly TCR Auction has

• Single round for the months of July, August, and September

• Two rounds for the months of October-May (all the months in the Season periods)

MP Activity

SPP Staff Activity

Monthly TCR Auction

Submit TCR Bids, Offers and

Self-Converts

Run Monthly TCR Auction

Clear Monthly TCR Auction / Perform SFT

Post Monthly TCR Awards

Check Auction Results

Analyze Historical Data

Verify Incremental Transmission

Service

Assign Incremental

Candidate ARRs

Request Incremental Transmission

Service (optional)

ARR/TCR PROCESS:

AUCTION REVENUE RIGHTS (ARRS) OVERVIEW

136

Understanding Auction Revenue Rights• Transmission service customers typically pay the embedded cost of the

transmission system

• Transmission service customers (i.e. with firm transmission service) can request and expect contract path rights on the transmission system. These path rights are nominated by:

– MW amount

– Point of Receipt

– Point of Delivery

• Once awarded (allocated), such path right becomes a financial right entitling the owner to either:

– A portion of auction revenues or,

– Possibly turning it into financial instrument to use towards Day-Ahead congestion exposure hedging

137

ARRs: Definition• In Integrated Marketplace, such path right is known as Auction Revenue Right

(ARR) and defined as:

A financial right, awarded during the annual/incremental ARR allocation process, that entitles the holder to a share of the auction revenues generated in the applicable TCR auction(s) and/or entitles the holder to self-convert the ARRs into TCRs

–Nomination Parameters: MW Amount

Source Settlement Location

Sink Settlement Location

Could be Network Type or PTP type

Time of Use (Period, On/Off-Peak)

–Candidate nominated ARRs are subject to a cap, which is a function of: Historical peak load or, Incremental candidate ARR allocation

–Financial Obligation Will be either a credit or a liability to Market Participant in TCR auction settlement

Valuation based on the full MW allocation

138

ARRs: Definition• In Integrated Marketplace, candidate ARRs do not have to be necessarily

submitted in the ARR Allocation process

• Possible use of candidate ARR:

– Do nothing or,

– Nominate for ARR Allocation Process and:

Self-convert Allocated ARR to TCR Bid, or

Retain Allocated ARR for settlement based on the TCR Auction

• The ARR allocation process is conducted:

– Annually

– Incrementally (i.e. monthly if there is new transmission service reservation for that month or existing reservation that could not be accounted for in the annual process)

139

ARR Allocation: Objective• The objective of the ARR Allocation Process is to grant as much ARR

MWs as possible (or minimize the total curtailment amount, if needed) , while ensuring that the transmission network security is maintained: that allocation algorithm is referred to as ARR Simultaneous Feasibility Test (ARR SFT)

• The results of the ARR Allocation Process will include:– The awarded (allocated) MW amount for each nominated candidate ARR

– The total system awarded ARR MW amount

140

Auction Revenue RightsHow are Candidate ARRs allocated? • Based on following Confirmed Firm Transmission Rights

– Network Integrated Transmission Service Agreement

– Point to Point Firm Transmission Service Request

– Grandfathered Agreements

• Nominate Candidate ARRs to become ARRs

• Allocated Annually - Period and Class– June, July, August, September (On/Off Peak)

– Fall, Winter, Spring (On/Off Peak)

– Allocated in three rounds

• Allocated Monthly - Class– Monthly single round (On/Off Peak) – as needed basis

141

ARR Allocation: Process• In Integrated Marketplace, the ARR Allocation process is structured through 2

sequential timeline processes:– The Annual ARR Allocation Process

Is triggered once a year, in April

Covers a planning horizon of 1 year

The planning horizon is further segmented in the following periods:

Will be divided in 2 process runs for each period: an Off-Peak process run and an On-Peak process run

142

Period Months Covered

1 June

2 July

3 August

4 September

5 October - November

6 December - January - February - March

7 April - May

Season: FallSeason: WinterSeason: Spring

ARR Allocation: Process– The Annual ARR Allocation Process (continued)

Each process run will be executed in 3 sequential rounds, to allow Market Participants to adjust their strategy

143

Round Additional Considerations System Transmission Cumulative Capacity Availability

1 a) Parallel flows 100%

2a) Parallel flowsb) ARRs awarded in Round 1 of ARR

Annual allocation100%

3

a) Parallel flowsb) ARRs awarded in Round 1 of ARR

Annual allocationc) ARRs awarded in Round 2 of ARR

Annual allocation

100%

ARR Allocation: Process– The Incremental (Monthly) ARR Allocation Process

Is triggered once a month

Covers a planning horizon of 1 Month

The following Incremental ARR periods are proposed:

Will be divided in 2 process runs for each process: an Off-Peak process run and an On-Peak process run

Acknowledges the allocation from any previous ARR processes for the covered planning horizon

144

Period Month Covered

June July

July August

August September

September October

October November

November December


December January

January February

February March

March April

April May

ARR Allocation: Process– The Incremental (monthly) ARR Allocation Process (continued)

Each process run will be executed in 1 round

145

Round Additional ConsiderationsSystem Transmission Cumulative Capacity

Availability

1

a) Parallel flowsb) TCRs awarded from TCR

Annual auctionc) Non-settled ARRs from

TCR Annual auction

100%

Auction Revenue Rights (ARR) Characteristics: Summary

146

Economic value based on ACPs from the TCR Auctions SPP issues obligation type ARRs to MPs Defined from source to sink

Source point – Settlement Location where a ARR originates Sink point – Settlement Location where a ARR ends

Defined by MW Quantity, ARR Period (month/season), and ARR Class (on/off-peak)

Financial entitlement, not physical right

100 MWs

A B

Source Sink

Annual ARR Allocation ProcessSFT – Example with no curtailment

147

A B100 MW line limit

Feasible as Bid

• If all the nominated candidate ARRs are confirmed feasible, all nominated candidate ARRs are awarded

Annual ARR Allocation ProcessSFT – Curtailment Example

148


• If the nominated candidate ARRs are not feasible, the amount to be awarded will be reduced using a weighted least squares method

• The SFT will assign a higher percentage ARR reduction for those nominations having the greatest impact on constraints

• ARR nominations with an equal impact on constraints will have an equal reduction

ARR/TCR PROCESS:

TRANSMISSION CONGESTION RIGHTS (TCRS) OVERVIEW

149

Understanding Transmission Congestion Rights• In addition to providing ARRs for Market Participants who are entitled to, there

is also the possibility of purchasing or selling (financial) transmission rights. Once granted, these rights are then used to mitigate the Market Participant congestion exposure to the Day-Ahead Market

• The MW amount of purchase or sale in these transmission rights is determined through an centralized auction process whose objective is to maximize the auction value

• These financial rights are submitted with the following characteristics:– MW amount

– Point of Receipt

– Point of Delivery

– Incremental Offer/Bid Price

150

TCRs: Definition• In Integrated Marketplace, such financial right is known as Transmission

Congestion Right (TCR) and defined as:

A financial right that entitles the holder to a share of the congestion revenue collected in the Day-Ahead Market

–Submittal Parameters: Max MW Amount

Incremental Offer/Bid Price

Source Settlement Location

Sink Settlement Location

Time of Use (Period, On/Off-Peak)

–Credit Check: MP TCR Bids/Offers can be limited or cancelled in case of inadequate MP Market Credit

–Financial Obligation: Will be either a credit or a liability in DA Settlement valuation

Valuation based on the full MW award

151

TCR Auction: Objective• The objective of the TCR Auction Process is to maximize the auction

value based on the TCR bids and offers, while ensuring that the transmission network security is maintained: that auction algorithm is known to as TCR Simultaneous Feasibility Test (TCR SFT)

• The results of the TCR Auction Process will include:– The awarded MW amount for each submitted TCR Bid/Offer

– The Auction Clearing Price (ACP) at each system Pricing Location

– The total auction value

152

TCRs: How can one obtain TCRs from SPP?

• Annual TCR auction– Multi-period (months/seasons)

– Multi-Class (On Peak/Off Peak)

– Based on reduced system capability

• Monthly TCR auction– Single or two rounds

– Multi-Class (On Peak/Off Peak)

– Based on residual capability that was not purchased

• TCR secondary market– Bilateral trading

153

TCR Auction: Process• In Integrated Marketplace, the TCR auction process is structured through 2

sequential timeline processes (similar to ARR Allocation process):– The Annual TCR Auction Process (subsequent to ARR Annual Allocation)

Is triggered once a year, in May

Covers a planning horizon of 1 Year

The planning horizon is further segmented in the following periods:

Will be divided in 2 process runs for each period: an Off-Peak process run and an On-Peak process run

Acknowledges the allocation from the Annual ARR process for the covered planning horizon

154

Period Months Covered

1 June

2 July

3 August

4 September

5 October - November

6 December - January - February - March

7 April - May

Season: FallSeason: WinterSeason: Spring

TCR Auction: Process– The Annual TCR Allocation Process (continued)

Each process run will be executed in 1 round

System Transmission Capacity Made Available

155

Round Additional Considerations

1 a) Parallel flows

Period Months CoveredSystem Transmission Cumulative Capacity

Availability

1 June 100%

2 July 90%

3 August 90%

4 September 90%

5 October - November 60%

6 December - January - February - March 60%

7 April - May 60%

TCR Auction: Process– The monthly TCR Auction Process (subsequent to ARR Monthly Allocation)

Is triggered once a month

Covers a planning horizon of 1 month

The following monthly TCR periods are proposed:

Will be divided in 2 process runs for each process: an Off-Peak process run and an On-Peak process run

Acknowledges the allocation from any previous ARR/TCR processes for the covered planning horizon

156


June July

July August

August September

September October

October November

November December


December January

January February

February March

March April

April May

TCR Auction: Process– The monthly TCR Auction Process (subsequent to ARR Monthly Allocation)

Each process run will be executed in up to 2 rounds, depending on the covered month

157

Covered Month: July, August or September

Covered Month: October, November, December, January, February, March, April or May


1a) Parallel flowsb) TCRs awarded in Round 1 of

TCR Annual allocation

100%


1a) Parallel flowsb) TCRs awarded in Round 1 of

TCR Annual allocation

80%

2

a) Parallel flowsb) TCRs awarded in Round 1 of

TCR Annual allocationc) TCRs awarded in Round 1 of

TCR Monthly allocation

100%

Annual TCR Auction Process

158

• The mechanism through which MPs may obtain TCRs through the submission of bid to purchase TCRs and/or through self-conversion of ARRs into TCRs

• Different percentages of the grid capacity are made available during the TCR periods included in the Annual TCR Auction

• TCRs in the annual auction are auctioned in a single round process for all months and seasons

Annual TCR Auction

Submit Bid to Purchase and Self-Convert

Run Annual TCR Auction

Clear Annual TCR Auction / Perform SFT

Post TCR Awards

Check Auction ResultsMP Activity

SPP Staff Activity

Annual TCR Auction ProcessAuction Bidding – Self-Convert

159

• Self-Convert• If an MP elects to purchase the TCR corresponding to an ARR he

holds, he will submit the ARR as a “self-convert” bid type during the Annual TCR Auction

• Only MPs holding ARRs may submit a Self-Convert TCR bid

• The Self-Convert bid must contain the same source and sink as the associated ARR

• The Self-Convert MW must be less than or equal to the associated ARR MW

• The MP will technically pay for the TCR, but as holder of the corresponding Auction Revenue Rights they will in effect be funding their own portion of the ARR fund, typically resulting in a net $0 transaction during ARR Settlements

Annual TCR Auction ProcessAuction Bidding – Bid to Purchase

160

Bid to purchase An MP may elect to submit bids to purchase TCRs instead of

or in addition to self-converting ARR MWs Sources and Sinks for TCR bids may be any valid Settlement

Location The number of TCR MW an MP may bid to purchase is

limited by the amount of credit they have established in the TCR System

Monthly TCR Auction Process Monthly Auction Bidding

161

The TCR offer and bid submittal process allows for the following submittal types:

Self-Convert: When a Market Participant elects to purchase the TCR corresponding to an ARR that it holds

Bids to Purchase: Sources and Sinks for bids to purchase TCRs may be any valid Settlement Location

Offers to Sell: In the Monthly TCR Auction an MP may also offer for sale any TCR that was acquired during the Annual TCR Auction.

Self-conversions, bids to purchase, and offers to sell TCRs in the Monthly TCR Auction process follow the same procedures and have the same restrictions as in the Annual TCR Auction

TCR Secondary Market

162

SPP will facilitate a secondary market for TCRs

Secondary TCR Market Details

• Bilateral trading of existing TCRs is facilitated through a bulletin board system

• TCRs may be broken down into small MW increments that total the original TCR

• TCRs may be traded daily, for On-Peak and/or Off-Peak periods

Secondary TCR restrictions• TCRs may not be reconfigured (path

remains the same)• TCRs must span a minimum of 1 day

and a maximum of the month for which they’re offered

TCR for sale!TC

R!

TCR

Buy 1 Get 1 Free!

Act now!

Lonely TCR seeks companion

TCR Secondary Market

163

• Market Participants contact each other directly to negotiate terms of sale

• The TCR purchaser pays TCR seller directly

• SPP accounts for transfer of TCR ownership

• Purchaser must meet applicable credit requirements

TCR Characteristics: Summary

164

Economic value based on Day-Ahead Congestion Prices TCRs are an instrument of obligation type Defined from source to sink

Source point – Pnode where a TCR originates Sink point – Pnode where a TCR ends

Financial entitlement, not physical right Independent of energy delivery MW Quantity TCR period: Season or Month TCR class: On-Peak or Off-Peak

100 MWs

A B

Source Sink

Annual TCR Auction ProcessAuction Clearing and SFT – Example

165


ARR/TCR PROCESS:

AUCTION REVENUE RIGHTS AND TRANSMISSION CONGESTION RIGHTS SETTLEMENT VALUATION

166

Auction Revenue Rights (ARR) Settlement Valuation

167

• The value of an ARR is determined based on the difference in TCR Auction Clearing Prices (ACP) between the source and the sink

• Auction Clearing Price (ACP) is based on the sum of the nodal clearing prices for each auction, over an Auction Period and Class (e.g. seasonal on-peak, monthly off-peak, etc)

• ARRs can be a benefit or a liability

ARR Value = (ARR MW) * (ACPARR Source – ACPARR Sink)

Transmission Congestion Rights (TCR) Settlement Valuation

168

• TCRs have a monetary value which will result in a credit or debit to be paid to (or owed by) the TCR holder

• TCR values are based on the difference between the Marginal Congestion Component (MCC) of the Day-Ahead LMP from the TCR source point to the TCR sink point

TCR Value = (TCR MW) * (Congestion Price TCR Source – Congestion Price TCR Sink)

LMP LMP = MEC + MCC + MLC

Marginal Loss Component (MLC)

Marginal Congestion

Component (MCC)

Marginal Energy Component (MEC)

169

ARR / TCRSettlement Valuation - Example

MP1 has 10 MW of Firm Transmission Service between its generation and MP2 service territory

Based on historical congestion analysis, MP1 has decided to participate in the ARR/TCR Process for the upcoming Off-Peak Period (assume 8 Hours/day, 30 days) as follows:

Nominate up to 10MW of transmission service into a candidate ARR (source: Gen MP1 Settlement Location, sink: LoadMP1@2 Settlement Location):

- The ARR Allocation process has resulted in MP1 receiving 8 MW worth of ARRs

With the 8MW of allocated ARRs:

- Self-convert 6MW for the TCR Auction: all were awarded

MP2








Flowgate Limit = 12 MW

MP1


170


MP2


Spin Award (MW): 8



Spin Award (MW): 12



12 MW >>

Spin MCP = 25 $/MW



MP1


TCR Auction Clearing Prices for that Off-Peak Period are:

ACP (Gen MP1 Settlement Location) = $Period/MW -800

ACP (Load MP1@2 Settlement Location) = $Period/MW 1600

Assuming that the Day-Ahead Market clears as illustrated above for each hour of that Off-Peak Period, let’s determine:

- The impact of these market instruments on MP1’s net congestion exposure

MEC ($/MWH): 42.5MCC ($/MWH): -7.5MLC ($/MWH): 0

MEC ($/MWH): 42.5MCC ($/MWH): 7.5MLC ($/MWH): 0

171


MP2


Spin Award (MW): 8



Spin Award (MW): 12



12 MW >>

Spin MCP = 25 $/MW



MP1


ARR Allocation:

ARR Value (based on TCR Process) = 8 x (- 800 – 1600) = $Period/MW -19,200 = $Day/MW -600 (credit)

TCR Auction:

ARR Self-Converting Value (from TCR Auction) = 6 x (1600 + 800) = $Period/MW 14,400 = $Day/ 480 (charge)

TCR Value (based on Day-Ahead Market) = 6 x (-7.5 – 7.5) = $/MWH -90 = - $Day/MW 720 (credit)



172


MP2


Spin Award (MW): 8



Spin Award (MW): 12



12 MW >>

Spin MCP = 25 $/MW



MP1


Without Congestion Hedging:

MP1 Day-Ahead Congestion Exposure = 10 x (50 – 35)

= $/MWH 150 = $Day/MW 1,200 (=150 x 8 Hours)

With Congestion Hedging:

MP1 Day-Ahead Congestion Exposure = 1200 (DA congestion)- 720 (TCR) + 480 (TCR conversion) – 600 (ARR revenue)

= $Day/MW 360 = $/MW 45 (= 360 /8 Hours)



173


MP2


Spin Award (MW): 8



Spin Award (MW): 12



12 MW >>

Spin MCP = 25 $/MW



MP1


MP1’s decision to participate in the ARRs/TCRs Process has indeed reduced its overall congestion exposure for the Off-Peak Period from $1,200 to $360 on a daily basis.



TCR Market: Financial Reconciliation

174

• TCRs are fully funded on a daily basis from the congestion revenue collected

• Any revenue deficiencies will be handled through the TCR Daily Uplift on a pro-rata share

• Monthly Payback will attempt to pay back deficiencies collected within that month

• Annual Payback will attempt to pay back deficiencies collected throughout the year

• To the extent that there is an excess amount of net charges collected for the year and all deficiencies have been fully reimbursed, the excess is distributed to ARR holders in proportion to their ARR Nomination Caps

POST REAL-TIME MARKET ACTIVITIESSection 7

175

Topics Covered

• Market Settlements: Definition

• Meter Data Submission Responsibilities

• Settlement Statements vs. Resettlement Statements

• Settlement Invoice: Content and Deadlines

• Charge Type: Definition

• Dispute Process

176

Post Real-Time Market ActivitiesMarket Settlements

• Market Settlements represent the financial settling of market activities between Market Participants in the SPP footprint

• SPP will issue an Initial and Final settlement statement for each Operating Day that will include:• Day-Ahead Market Activity

• Real-Time Market Activity

• Transmission Congestion Rights (TCR) Activity

• Settlement Statements will be issued at the Market Participant (MP) and Asset Owner (AO) level

• Meter Data will be used to settle Real-Time charges

177

Post Real-Time Market ActivitiesMeter Data

• Market Participant is responsible for the quality, accuracy and timeliness of meter data

• Market Participants must designate a Meter Agent for each of its Meter Data Submittal Location

• Market Participants (not Meter Agent) is responsible for any and all data submitted; SPP maintains relationship with the Market Participant (not Meter Agent)

• Settlement meter data must be submitted in either 5-minute or hourly intervals as indicated during market registration

• Can submit estimates if not available for Operating Day

• Must submit actual values when available, prior to the next scheduled settlement

• If not submitted, SPP will use State Estimator Data

178

Post Real-Time Market ActivitiesMetering / Settlement Relationship

179

Demand Response Load

MeterData

Submittal Locations

Settlement Locations(pricing /

settlement)

Gen

Settlement Areas(residual / calibration)

MDSL

Load Intf Hub

Reserve Zones

Gen Load

Common Bus

RZN

MDSL MDSLMDSL

GenGen Gen

SA

DRL

SA

MDSL MDSL MDSL MDSL MDSL

DDRBDR

MDSLMDSL

RZN

DRL

Tie Line

Tie Line

Node

Pnode Pnode PnodePnode

Node Node Node

Meter Settlement Locations

Network ModelLink –

Network Model

Commercial Model

Post Real-Time Market ActivitiesMeter Data Submittal Timelines

• Meter data values submitted by NOON on the previous business day will be included in the Settlement Statement(s) to be executed

• Day 5 calendar day for Initial Settlement Statement

• Day 45 calendar day for Final Settlement Statement• For meter data submittal after Day 44 at NOON, there must be an associated dispute

• Day 75 calendar day for Resettlement 1 Statement

• +30 calendar days for Resettlement 2-11 Statement

180

Meter Data Submittal Example for Initial Settlement StatementOperating Day Day 1 Day 2 Day 3 Day 4 Day 5 Day 6 Day 7

March 3, 2014 MP’s Meter Agent submits Meter Data by

NOON

SPP performs data validations and prepares Initial Settlement Statement

SPP publishesInitial Settlement

Statement

Post Real-Time Market ActivitiesSettlement Statements

• Settlement Statement is a detailing of the charges and credits by charge type and Operating Day • Generated for each Market Participant and associated Asset Owner

• Contains data for all of the Operating Days settled

• Available electronically through the Portal on Business Days

181

SPP

Market Participant

Asset Owner

Asset Asset Asset

Asset Owner

Asset Asset

Initial

Final

Resettlement

Initial

Final

Resettlement

Initial

Final

Resettlement

Initial

Final

Resettlement

Post Real-Time Market ActivitiesSettlement Statement - Timeline

• One Settlement Statement will be published for each Operating Day

• Initial Settlement Statement – 7 calendar days following the Operating Day

• Final Settlement Statement – 47 calendar days following the Operating Day

• If the publishing date is not a business day, Settlement Statements will be published no later than the next Business Day

182

OD OD+7 OD+47

47 calendar days

7 calendar days

March 1st

Operating Day *March 10th

Initial Settlement Statement

April 17th

Final Settlement Statement

*March 8th is not a business day

Post Real-Time Market ActivitiesResettlement Statement - Timeline

• Resettlement Statements will be produced using corrected settlement data due to resolution of disputes, or correction of data

• SPP will produce up to 12 Resettlement Statement (on an as needed basis)

• Resettlement 1 – 77 calendar days after the Operating Day**

• Resettlement 2 – 107 calendar days after the Operating Day*

• Resettlement 3 – 137 calendar days after the Operating Day**

• Resettlement 4 – 167 calendar days after the Operating Day*

• Resettlement 5 through 9 – incremental 30 days from last Resettlement date**

• Resettlement 10 through 12 – ad hoc (not scheduled for a specific date)

*Resettlement 2 and Resettlement 4 are produced as a result of dispute resolution

**Resettlement 1 and 3 will be produced and published if the financial change is greater than 25% for a single Market Participant

183

Post Real-Time Market ActivitiesSettlement / Resettlement Statement Publishing Schedule

OD OD+7 OD+47 OD+77 OD+107 OD+137 OD+167

7 CD

March 1st

Operating Day

*March 10th Initial Statement

47 calendar days

77 calendar days

107 calendar days

137 calendar days

167 calendar days

April 17th

Final StatementJune 16th

Resettlement Statement 2

August 15th

Resettlement Statement 4*May 19th

**Resettlement Statement 1

July 16th

**Resettlement Statement 3

184

*Non-business day**Produced ‘as required’

Post Real-Time Market ActivitiesCharge Types

• Charge Types represent the various market activities

• Each Charge Type uses different Billing Determinants and a different calculation formula

• There are a total of 51 Charge Types that represent the following:• Day-Ahead Market Settlement

• Real-Time Market Settlement

• ARR/TCR Auction Settlement

• Miscellaneous Amount

• Revenue Neutrality Uplift Distribution Amount

• The complete list of Charge Types and Billing Determinants can be found in the Market Protocols for SPP Integrated Marketplace

185

Post Real-Time Market ActivitiesCharge Type - Components

186

Charge Type is the end result of Settlement calculations which describes the type of activity being settled (e.g. “TCR Auction Charge”) Charge Type Settlement Formula is the equation that is used to settle the charge type

Billing Determinants are data inputs and intermediate calculations used to calculate the final result to be output on the settlement

Post Real-Time Market ActivitiesCharge Type – Sign Convention

187

Activity (+) (-)*Energy Transactions Withdrawal Injection

Bilateral Settlement Schedules Buyer Seller

Transmission Congestion Rights Charges Credits

Settlement Statements / Invoices Payment due SPP

Payment due MP

*Generation, Load, Imports, Exports, and Virtuals

Post Real-Time Market ActivitiesSettlement Invoices

• Settlement Invoice is a weekly summary of the net daily charges and credits by Market Participants and associated Asset Owner and Operating Day • Contains all data for all Operating Days settled during the invoice period

• Net amounts for each Operating Day contribute to invoice amounts

• Market Participant is the financially responsible entity

188

Post Real-Time Market ActivitiesSettlement Invoices (cont’d)

• Market Participants are responsible for paying invoices

• Payments due to SPP must be made in full (regardless of any billing dispute)

• Payments for market settlements flow through SPP

• Market Participants with a net credit balance will receive that balance - adjusted for balances not collected

Market Participants

Market Participants

189

Post Real-Time Market ActivitiesDisputes

• A dispute is a discrepancy Market Participants uncover when reviewing their Settlement Statement

• Market Participants may dispute items set forth in any Settlement Statement (initial, final, resettlement)

• NOTE: In case of a resettlement, only incremental differences can be disputed

• Dispute Submission Timeline

• Market Participants can begin submission immediately after the receipt of their initial settlement statement

• Market Participants have up to 90 calendar days after the final settlement statement to file a dispute for that Operating Day

• Any adjustments from a resolved dispute will be posted to a subsequent settlement statement

190

OD +7 OD+47 OD+77 OD+107 OD+137 OD+167

SPP publishes Initial Settlement Statement

SPP publishes FinalSettlement Statement

Resettlements R1 (OD+77) and R3 (OD+137) will be utilized if the dispute resolution results in at least a 25% financial change in a Market Participant’s Settlement Statement

Dispute Filing Period for Initial and Final Settlement Statements

Resettlements R2 (OD+107) and R4 (OD+167) require a dispute regardless of financial impact

Post Real-Time Market ActivitiesDisputes (cont’d)

191

Post Real-Time Market ActivitiesDisputes (cont’d)

• Disputes must be filed on the Request Management System using the Contents of Notice dispute form

• Each dispute is tracked throughout the process and assigned the following statuses:

• Open

• Closed

• Denied

• Granted

• Granted with Exceptions

• Withdrawn

192

Market Participant Milestones

193

TCR Market Trials Begins

Carrie SimpsonLead Analyst, Market [email protected]

Heather StarnesManager, Regulatory [email protected]

Debbie JamesManager, Market [email protected]

194

mailto:[email protected]



Documents

Integrated Marketplace Commission Staff Education March 26, 2012