Dr G. C. Ejebe, Fellow IEEE

University of Minnesota

Graduate Power Seminar

University of Minnesota

Graduate Power Seminar

The Two Settlement System and Virtual Bidding in Electricity Markets &Financial Transmission Rights

The Two Settlement System and Virtual Bidding in Electricity Markets &Financial Transmission Rights

2-Settlement & Virtual Bidding : Presentation Outline

Two Energy Market basics• Day-Ahead Market• Real-Time Market • Day-Ahead and Real-Time Market interactionsVirtual Bidding • Increment offers (incs) and decrement bids (decs)• Roles of incs and decsVirtual Bidding ExamplesFinancial Transmission Rights in Energy Markets

FERC Requires Energy Markets

Federal Energy Regulatory Commission (FERC) developed Standard Market Design initiative

requiring:Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) to implement two markets:— a day-ahead (DA) market and — a real-time (RT) balancing

PJM, NYISO, ISONE, MISOCAISO (2009) ERCOT(2010)

Independent System Operators (ISOs) and Regional Transmission Operators(RTOs)

CAISO 57,124 MW 25,526 miles Tx 30mISO-NE 33,700 8,130 14mMidwest ISO 144,132 55,090 43mNYISO 40,685 10,893 19mPJM 164,895 56,499 51mSPP 66,175 50,575 15mERCOT 72,712 40,000 22m

ISO/RTO Functions

Coordinate Movement of Wholesale Electricity in footprintEnsure Grid ReliabilityEfficient Grid Dispatch with Price TransparencyMarket Monitoring & Market FlexibilityLiquidity in the MarketplaceDemand Response DevelopmentEase of Entry and Private InvestmentGreen Power Added to GridLong term regional transmission planning

Two Energy Markets

Day-Ahead Energy Market– Develop day-ahead schedule using least-cost security constrained unit commitment and dispatch– Calculate hourly LMPs for next operating day using generation offers, demand bids and bilateral transaction schedules– Objective is to develop set of financial schedules that are physically feasibleReal-Time Energy Market– Calculate hourly LMPs based on actual systemoperating conditions

Locational Marginal Prices (LMPs)

LMPs are determined by a linear programming OPFMinimizes total energy costs subject to a set of constraints reflecting physical limitations of the power system. There are three components of LMPs: LMP ($/MW) = Energy component + Loss component + Congestion component The energy component is the same for all locations. The loss component reflects the marginal cost of system losses specific to each location, The congestion component represents the individual location’s marginal transmission congestion cost. The energy component is the cost of providing an additional MW of energy to the distributed market reference bus, assuming optimally dispatched generation

Day Ahead Energy Market

A Day-ahead hourly forward market for energyProvides the option to obtain increased certainty:– Purchase of MW at Day-ahead prices– Sale of MW at Day-ahead prices– Day-ahead congestion Inputs to DA Market— Price-sensitive demand— Increment offers— Decrement bids— Capacity Resources must submit offers in DA— Participation by load is optional

Reserve Adequacy Assessment

Designed to ensure adequate generating resources to meet forecast actual load in real time Additional generating resources scheduled after day-ahead market clearsBased on RTO load forecast, physical generation assets,— actual transaction schedules (net tie schedules)— RTO operating reserve requirements

Virtual bids and offers not includedAny additional unit commitment is based on minimizing cost to provide additional reserves (minimize startup and no-load costs)RAA performed after DA Market run

Two Energy Market Settlement

Day-Ahead Market Settlement

– Based on scheduled hourly MW quantities and day ahead LMPs

Real-Time (Balancing) Market Settlement

– Based on hourly MW quantity deviations between

real-time and day-ahead MW quantity deviations

– Settled at real-time LMPs

Day-Ahead Market Implications

Day-ahead schedules are financially binding Demand scheduled day-ahead– Pays day-ahead LMP for day-ahead MW scheduled– Pays real-time LMP for actual MW above scheduled– Paid real-time LMP for actual MW below scheduledGeneration scheduled day-ahead– Paid day-ahead LMP for day-ahead MW scheduled– Paid real-time LMP for actual MW above scheduled– Pays real-time LMP for actual MW below scheduled

Virtual Bidding

Virtual Bidding is a market mechanism that allows Market Participants to purchase (or sell) power in the Day Ahead Market with the explicit requirement that they sell (or buy back) same amount of power in the Real Time MarketPurely financialOriginal intent is to pressure the convergence of DA and RT prices

Virtual Bidding

Incremental Offers & Decrement Bids Available to all Market ParticipantsDo not require physical generation or load Consist of:– MW offer or bid– Price of offer or bid (may be negative) Submitted at any hub, transmission zone,aggregate, or single bus for which LMP iscalculatedSupported in Day-ahead market only

– Deviation in Real-time market Operating Reserve Implications

• Minimal charges for VB

Increment Offers & Decrement Bids

Increment Offers— Looks like a spot sale or dispatchable resource

“If the price goes above X, then MP will sell to the RTO day-ahead market”Decrement Bids

• Looks like spot purchase or price sensitive demand “If price goes below X then MP will buy from theRTO day-ahead market”

Reasons for Using Virtual Bidding

Price Arbitrage for profit maximization— Arbitrage Day-ahead to Real-time pricing— Use an increment offer if DA > RT— Use decrement bid if DA < RT

Physical Hedging— Hedge Day-ahead Demand bid— Hedge a Day-ahead generation offer

• Hedge against real-time price spikes in case of forced outage

Numerical Example #1 Decrement Bid

Day-aheadMarket Participant believes DA will be lower than RT and Dec Bids for HE 10 as follows :50 MW at $45 : 50 MW at $38 : 50 MW at $30: 50 MW at $25Day Ahead Market clears at $36Day-ahead position is therefore 100 MWIf Real-time Market Clears at $52Market Participant makes a profit of ($52-$36)*100= $1600If Real-time Market Clears at $32Market Participant’s loss is ($32-$36)*100= -$400

Day-aheadMarket Participant believes DA will be higher than RT and Inc Offers for HE15 as follows :25 MW at $65 : 25 MW at $75 : 25 MW at $80: 25 MW at $90Day Ahead Market clears at $78Day-ahead position is therefore 50 MW@$78If Real-time Market Clears at $56Market Participant makes a profit of ($78-$56)*50= $1100If Real-time Market Clears at $82Market Participant’s loss is ($78-$82)*50= -$200

Numerical Example #2 Increment Offer

Numerical Example #3 Hedging a Generator Offer

Day-aheadMarket Participant bids scheduled Generation of 100 MW @ $50.Also Dec bids 10 MW @ $65 (virtual)Assume Day Ahead Market clears at $60Both bids clear @ $60Day-ahead position is therefore -commitment of 100MW @$60 and10 MW virtual lengthREAL TIME – Scenario 1 Higher RT PriceIf Real-time Market Clears at $70And Generator produces full output of 100MWMarket Participant gets a credit of $60*100= $6000 from DA Gen settleAlso a credit 0f ($70-$60)* 10= $100 from the virtual bidMarket Participant’s Net = $6100

Numerical Example #3 Hedging a Generator Offer(Continued)

REAL TIME – Scenario 2 Lower RT PriceIf Real-time Market Clears at $50And Generator produces full output of 100MWMarket Participant gets a credit of $60*100= $6000 from DA Gen settleAlso a credit 0f ($50-$60)* 10= -$100 from the virtual bidMarket Participant’s Net = $5900

Numerical Example #3 Hedging a Generator Offer(Continued)

REAL TIME – Scenario 3 Higher RT PriceIf Real-time Market Clears at $70And Generator produces reduced output of 90MW due to minor mech problemsMarket Participant gets a credit of $60*100= $6000 from DA Gen settleAlso a credit 0f ($70-$60)* 10= $100 from the virtual bid of 10 MWA charge for under delivery of 10 MW in RTMarket = -10*$70 = -$700Market Participant’s Net = $6000+$100-

$700=$5400

Numerical Example #3 Hedging a Generator Offer(Continued)

REAL TIME – Scenario 4 Lower RT PriceIf Real-time Market Clears at $50

And Generator produces reduced output of 90MW due to minor mech problems

• Market Participant gets a credit of $60*100= $6000 from DA Gen settleA charge 0f ($50-$60)* 10= -$100 from the virtual bid of 10MWA charge for under delivery of 10 MW in RTMarket = -10*$50 = -$500Market Participant’s Net = $6000-$100-$500 = $5400Hedging with VB allows MP to contract in DA for RT price

Summary: 2-Settlement in Electricity Markets

RTOs required to implement two marketsDay Ahead and Real Time MarketsA Day-ahead hourly forward market for energy produces hourly Clearing pricesReal Time Market produces Hourly prices based on actual system conditionsLMPs used to clear both markets

Summary: Virtual Bidding in Day Ahead Markets

VB allows purely financial energy transactions without physical generation or loadIncrement Offers and Decrement BidsIncrement Bids— If the price goes above X, then MP will sell to the day-ahead market

Decrement Bids— If price goes below X then MP will buy from the day-ahead market

Price Arbitrage for ProfitPhysical HedgingCurrently working in US Energy Markets – PJM, NYISO, ISO-New England, MISO and ERCOT (December 2010)Starting in CaISO in February 2011

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Financial Transmission Rights (FTRs)

…

Understand the concepts and principles of FTRsFTRs - PJM, ISONE, MISOCongestion Revenue Rights (CRRs)- CAISO, ERCOTTransmission Congestion Contracts(TCCs)- NYISO

Explain how FTRs are acquired in RTOs

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Why Do We Need FTRs?

Challenge: — LMP exposes Market Participants to price uncertainty for

congestion cost charges— During constrained conditions, the RTO collects more

from loads than it pays generators

Solution:— Provides ability to have price certainty— FTRs provide hedging mechanism that can be traded

separately from transmission service

???

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What Are FTRs?(CRRs,TCCs)

Financial Transmission Rights are …

a financial contract that entitles the holder to a stream of revenues (or charges) based on the hourly energy price differences across the path(between source/sink)

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Why Use FTRs?

To create a financial hedge that provides price certainty to Market Participants when delivering energy across the RTO systemTo provide firm transmission service without congestion costTo provide methodology toallocate congestion charges to those who pay the fixed cost of the RTO transmission system

W HY?

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Obtaining FTRs

Network service- Allocation by RTO— based on annual peak load— designated from resources to aggregate loads

Firm point-to-point service— may be requested with transmission reservation— designated from source to sink

Secondary market -- bilateral trading— FTRs that exist are bought or sold

FTR Auction -- centralized market— purchase “left over” capability

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What are FTRs Worth?

Economic value determined by hourly LMPs Benefit (Credit)— same direction as congested flow— If sink LMP congestion component>source LMP cong

Liability (Charge)— opposite direction as

congested flow

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FTRs & Congestion Charges

Point-to-Point FTR Credit— MW * (Day-ahead Sink LMP - Day-ahead Source LMP)— MW * (Day-ahead Sink Congestion Component of LMP - Day-ahead

Source Congestion Component of LMP)

Network Service FTR Credit— MW * (Day-ahead Aggregate Load LMP - Day-ahead Generation Bus

LMPs)

Congestion Charge = MWh*(Day-ahead Sink LMP - Day-ahead Source LMP)

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Energy Delivery Consistent with FTR

Thermal Limit

FTR = 100 MW

Congestion Charge = 100 MWh * ($30-$15) = $1500

FTR Credit = 100 MW * ($30-$15) = $1500

LMP = $30LMP = $15

Source (Sending End)

Sink (Receiving End)

Bus BBus A Energy Delivery = 100 MWh

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Energy Delivery Not Consistent with FTR (I)

FTR Credit = 100 MW * ($30-$10) = $2000

Congestion Charge = 100 MWh * ($30-$15) = $1500

Bus A

LMP = $10

Bus C

LMP = $15

LMP = $30

Bus B

Energy Delivery = 100 MWh

FTR = 100 MW

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Energy Delivery Not Consistent with FTR (II)

FTR Credit = 100 MW * ($30-$20) = $1000

Congestion Charge = 100 MWh * ($30-$15) = $1500

Bus A

LMP = $20

Bus C

LMP = $15

LMP = $30

Bus B

Energy Delivery = 100 MWh

FTR = 100 MW

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Characteristics of FTRs

Defined from source to sinkMW level based on transmission reservationFinancially bindingFinancial entitlement, not physical rightIndependent of energy delivery

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Acquiring FTRs from Auctions

The RTO conducts periodic auctions -annually and monthly— to allow eligible FTR Account Holders to acquire FTRs.— to allow FTR Owners to sell FTRs that they hold.

The RTO auctions the two basic types of FTRs:(a) Point to Point (PTP) Options(b) Point to Point (PTP) Obligations

OPTIONS or OBLIGATIONS

PTP Options are evaluated hourly in each FTR Auction as the positive power flows on directional network elements created by the injection and withdrawal at the specified source and sink points in the quantity represented by the FTR bid or offer (MW),excluding all negative flows on all directional network elements. PTP Obligations are evaluated hourly in each FTR Auction as the positive and negative power flows on all directional network elements created by the injection and withdrawal at the specified source and sink points of the quantity represented by the FTR bid or offer (MW).

FTR Packaged as Peak & Off Peak

FTRs are auctioned in the following blocks:(a) 5x16 blocks for hours ending 0800-2300, Monday through Friday (excluding NERC holidays), in one-month strips;(b) 2x16 blocks for hours ending 0800-2300, Saturday and Sunday, and NERC holidays in one-month strips; and(c) 7x8 blocks for hours ending 0100-0700 and hours ending 2400 Sunday through Saturday, in one-month strips; and(d) 7x24 blocks (combinatorial by specifying the previous three types of blocks), in one-month strips.

FTR Network Model

The FTR Network Model is based on the Network Operational Model. The FTR Network Model normally includes the same topology, contingencies, and operating procedures as used in the Network Operational Model as reasonably expected to be in place for the applicable auction term (two years, one year, or one month, as applicable). The expected network topology for any month should include any planned outages of any transmission element known to be 16 hours or longer in that month. The FTR Network Model uses the peak Load conditions of the month being modeled.

FTR Simultaneous Feasibility Test

SFT is performed to ensure that all FTRs are feasible and deliverable within the control area reliability criteria on an annual basis for each planning period. SFT is a power flow with FTRs modeled as injections at the source node and withdrawals at the sinks, Objective is to ensure that all subscribed Transmission rights are within the capability of the existing Transmission System. SFT is designed to ensure that the RTO Energy Market will be revenue adequate under normal system conditions.Problems with FTR Short Pay in Some RTOs.