1. The Two Settlement System and Virtual Bidding in Electricity Markets &
Financial Transmission Rights
Dr G. C. Ejebe, Fellow IEEE
University of Minnesota
Graduate Power Seminar 1

2. 2-Settlement & Virtual Bidding : Presentation Outline
Two Energy Market basics
• Day-Ahead Market
• Real-Time Market
• Day-Ahead and Real-Time Market interactions
Virtual Bidding
• Increment offers (incs) and decrement bids (decs)
• Roles of incs and decs
Virtual Bidding Examples
Financial Transmission Rights in Energy Markets

3. 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, MISO
CAISO (2009) ERCOT(2010)

4. Independent System Operators (ISOs) and Regional Transmission Operators(RTOs)
CAISO ,124 MW 25,526 miles Tx 30m
ISO-NE , , m
Midwest ISO 144, , m
NYISO , , m
PJM , , m
SPP , , m
ERCOT , , m

5. ISO/RTO Functions
Coordinate Movement of Wholesale Electricity in footprint
Ensure Grid Reliability
Efficient Grid Dispatch with Price Transparency
Market Monitoring & Market Flexibility
Liquidity in the Marketplace
Demand Response Development
Ease of Entry and Private Investment
Green Power Added to Grid
Long term regional transmission planning

6. 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 feasible
Real-Time Energy Market
– Calculate hourly LMPs based on actual system
operating conditions

7. Locational Marginal Prices (LMPs)
LMPs are determined by a linear programming OPF
Minimizes 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

8. Day Ahead Energy Market
A Day-ahead hourly forward market for energy
Provides 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

9. 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 clears
Based on RTO load forecast, physical generation assets,
actual transaction schedules (net tie schedules)
RTO operating reserve requirements
Virtual bids and offers not included
Any additional unit commitment is based on minimizing cost to provide additional reserves (minimize startup and no-load costs)
RAA performed after DA Market run 5

10. 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

11. 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 scheduled
Generation 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

12. 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 Market
Purely financial
Original intent is to pressure the convergence of DA and RT prices

13. Virtual Bidding Incremental Offers & Decrement Bids
Available to all Market Participants
Do 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 is
calculated
Supported in Day-ahead market only
– Deviation in Real-time market
Operating Reserve Implications
Minimal charges for VB

14. Increment Offers & Decrement Bids
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 the
RTO day-ahead market”

15. 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

16. Numerical Example #1 Decrement Bid
Day-ahead
Market 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 $25
Day Ahead Market clears at $36
Day-ahead position is therefore 100 MW
If Real-time Market Clears at $52
Market Participant makes a profit of ($52-$36)*100= $1600
If Real-time Market Clears at $32
Market Participant’s loss is ($32-$36)*100= -$400

17. Numerical Example #2 Increment Offer
Day-ahead
Market 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 $90
Day Ahead Market clears at $78
Day-ahead position is therefore 50
If Real-time Market Clears at $56
Market Participant makes a profit of ($78-$56)*50= $1100
If Real-time Market Clears at $82
Market Participant’s loss is ($78-$82)*50= -$200 6

18. Numerical Example #3 Hedging a Generator Offer
Day-ahead
Market Participant bids scheduled Generation of 100 $50.
Also Dec bids 10 $65 (virtual)
Assume Day Ahead Market clears at $60
Both bids $60
Day-ahead position is therefore -commitment of and
10 MW virtual length
REAL TIME – Scenario 1 Higher RT Price
If Real-time Market Clears at $70
And Generator produces full output of 100MW
Market Participant gets a credit of $60*100= $6000 from DA Gen settle
Also a credit 0f ($70-$60)* 10= $100 from the virtual bid
Market Participant’s Net = $6100 8

19. Numerical Example #3 Hedging a Generator Offer(Continued)
REAL TIME – Scenario 2 Lower RT Price
If Real-time Market Clears at $50
And Generator produces full output of 100MW
Market Participant gets a credit of $60*100= $6000 from DA Gen settle
Also a credit 0f ($50-$60)* 10= -$100 from the virtual bid
Market Participant’s Net = $5900 9

20. Numerical Example #3 Hedging a Generator Offer(Continued)
REAL TIME – Scenario 3 Higher RT Price
If Real-time Market Clears at $70
And Generator produces reduced output of 90MW due to minor mech problems
Market Participant gets a credit of $60*100= $6000 from DA Gen settle
Also a credit 0f ($70-$60)* 10= $100 from the virtual bid of 10 MW
A charge for under delivery of 10 MW in RTMarket = -10*$70 = -$700
Market Participant’s Net = $6000+$ $700=$5400 9

21. Numerical Example #3 Hedging a Generator Offer(Continued)
REAL TIME – Scenario 4 Lower RT Price
If 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 settle
A charge 0f ($50-$60)* 10= -$100 from the virtual bid of 10MW
A charge for under delivery of 10 MW in RTMarket = -10*$50 = -$500
Market Participant’s Net = $6000-$100-$500 = $5400
Hedging with VB allows MP to contract in DA for RT price 9

22. Summary: 2-Settlement in Electricity Markets
RTOs required to implement two markets
Day Ahead and Real Time Markets
A Day-ahead hourly forward market for energy produces hourly Clearing prices
Real Time Market produces Hourly prices based on actual system conditions
LMPs used to clear both markets 19

23. Summary: Virtual Bidding in Day Ahead Markets
VB allows purely financial energy transactions without physical generation or load
Increment Offers and Decrement Bids
Increment 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 Profit
Physical Hedging
Currently working in US Energy Markets – PJM, NYISO, ISO-New England, MISO and ERCOT (December 2010)
Starting in CaISO in February 2011 20

24. Financial Transmission Rights (FTRs)…
Understand the concepts and principles of FTRs
FTRs - PJM, ISONE, MISO
Congestion Revenue Rights (CRRs)- CAISO, ERCOT
Transmission Congestion Contracts(TCCs)- NYISO
Explain how FTRs are acquired in RTOs

25. ? Why Do We Need FTRs? Challenge: Solution:
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
Locational Marginal Pricing (or LMP) exposes Market Participants to potentially high or volatile congestion charges. Remember, congestion charges occur when the transmission system is congested and out-of-merit resources must be used to meet PJM demand.
During constrained operations, the RTO collects more from loads than it pays to generators. We need a fair method of allocating the excess funds we collect.
So we need a solution to the challenge which protects PJM Market Participants from the congestion price uncertainty and provides a fair method of allocating the leftover funds.
Financial Transmission Rights or FTRs are the solution to the challenges listed on the slide.
FTRs provide Market Participants with a hedging mechanism. For those of you not familiar with what a hedging mechanism is, a hedging mechanism is a method of mitigating possible loss, or in this case congestion charges, by counterbalancing the loss. In other words, FTRs allow Market Participants to purchase protection from congestion charges.

26. 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)
Read the definition of Financial Transmission Rights.
The purpose of an FTR is to protect the firm user from increased cost due to transmission congestion. So, FTRs are a purchased right that can hedge against congestion charges incurred on a specified transmission path.
Remember, congestion charges arise when the transmission system is congested and differences in LMPs result from the RTO redispatching generators out of merit order to relieve that congestion.
The number of FTRs granted to transmission customers by the RTO is limited by the capability of the RTO’s transmission system (i.e., transmission is a scarce resource).
FTRs are a financial right to receive rebates of congestion charges between two points on the RTO system.

27. Why Use FTRs?
To create a financial hedge that provides price certainty to Market Participants when delivering energy across the RTO system
To provide firm transmission service without congestion cost
To provide methodology to allocate congestion charges to those who pay the fixed cost of the RTO transmission system
These are some of the reasons why the RTO uses FTRs.
As mentioned earlier, the Market Participants need protection from volatile congestion charges.
The RTO also needed a mechanism to allocate the congestion charges that are collected from the firm transmission service customers during congested conditions. FTRs provide a mechanism for returning these excess revenues we collected and at the same time provides transmission customers with the opportunity to hedge changes in LMPs. Remember, we are need a “fair” method to allocate the revenue.

28. 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
Transmission service customers, who acquire Network or Firm Point-to-Point Transmission Service, pay the embedded cost of the RTO transmission system. In return for paying these fixed costs, these firm transmission service owners have the option to obtain FTRs, which can serve as a hedge against transmission congestion charges.
There are currently three ways to obtain FTRs:
Network Service -- On a annual basis, network service transmission customers are allocated FTRs up to their annual peak load. These FTRs are designated along paths from specific capacity resources (or generators) to their aggregated loads. The configuration of the FTRs can be adjusted annually or when capacity resources are added or retired.
Firm Point-to-Point Service -- Firm point-to-point transmission customers obtain FTRs for their associated firm reservations. The path of the FTR is the same as the path of the firm reservation from source to sink. All FTRs are allocated for the same duration as the reserved transmission service.
Secondary Market -- Market Participants other than Network Service customers and firm point-to-point holders may obtain FTRs on the Secondary Market, via a bulletin board on the RTO OASIS. All FTRs available for purchase, as well as all FTRs traded, are posted here. This trade can occur without reassigning the transmission capacity itself. Any Market Participant can become a holder of an FTR through secondary trading.
The RTO also administers montlhy/annual auctions that allow Market Participants to acquire and sell FTRs directly. The opportunity of FTR owners to sell FTRs into the auction rather than exclusively through bilateral transaction is important since the FTRs demanded by the Market Participants are significantly different than the FTRs available for sale. The FTR auction provides the mechanism .

29. 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
So you can now tell that the hourly value of an FTR is based on the FTR MW reservation and the difference between the hourly LMPs.
You can also see that an FTR can be a benefit or a liability.
It is benefit when the path designated in the FTR is in the same direction as the congestion flow.
An FTR is a liability when the designate path is in the opposite direction to the congested flow.
An FTR has no value when the system is unconstrained.

30. FTRs & Congestion Charges
MWh*(Day-ahead Sink LMP - Day-ahead Source LMP)
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)

31. Energy Delivery Consistent with FTR
Thermal Limit
FTR = 100 MW
Source
(Sending End)
Sink
(Receiving End)
Bus B
Bus A
Energy Delivery = 100 MWh
Let’s look at some examples of consistency and inconsistency.
In this example, there is a thermal limit from Bus A to Bus B -- this line is congested in the direction shown by the green arrow.
The Market Participant defined (in advance of real-time) an FTR from Bus A to Bus B for 100 MW (shown by the blue arrow).
In real-time, the same Market Participant has an energy transaction from Bus A to Bus B for 100 MWh. (shown by the red arrow).
The congestion charge and FTR Credit calculations are shown at the bottom of the slide.
Remember, congestion charges are based on the differences between the LMPs at the receiving and sending end buses. In this case, the congestion charge for the 100 MWh transaction is $1500. So, the Market Participant will be charged $1500 for congestion.
This FTR holder is due a credit equal to the FTR MW value times the difference between the sink and source LMPs, or in this case $1,500.
So, you can see for this example the FTR holder breaks even or is completely hedged.
The holder of the FTR is not required to deliver energy in order to receive a congestion credit. If a constraint exists on the transmission system, the holders of FTRs receive a credit based on the FTR MW reservation and the LMP difference between point of delivery and point of receipt. This credit paid to the holder regardless of who delivered energy or of the amount of energy delivered across the path designated in the FTR.
LMP = $15
LMP = $30
Congestion Charge = 100 MWh * ($30-$15) = $1500
FTR Credit = 100 MW * ($30-$15) = $1500

32. 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
Now let’s look at another example in which the energy delivery is NOT consistent with the FTR.
Our FTR is defined from Bus A to Bus B for 100 MW.
The energy deliver is 100 MWh from Bus C to Bus B. This is inconsistent with the FTR (the energy delivery and FTR source and sink are not the same.)
In this case ,the congestion charge is the 100 MWh times the difference between the LMPs at Bus B and Bus C (or $30 - $15). The congestion charge that this participant has to pay is $1500.
However, this market participant also receives an FTR credit equal to the 100 MW times the difference between the FTR’s source and sink, or $30 - $20. So in this case the Market Participant receives an FTR credit for $2,000.
So, in this case the FTR holder ends up ahead $500.
Although inconsistent with the energy delivery, this situation is a case where the FTR is a benefit.

33. Energy Delivery Not Consistent with FTR (II)
Bus A
LMP = $20
Bus C
LMP = $15
LMP = $30
Bus B
Energy Delivery = 100 MWh
FTR = 100 MW
Here is another example when the energy delivery is NOT consistent with the FTR.
In this case the congestion charge is $1,500; the FTR credit is $,1000.
The difference between this case and the previous case is the LMPs.
In this case the FTRs is a liability. The FTR did not cover the congestion charges.
Congestion Charge = 100 MWh * ($30-$15) = $1500
FTR Credit = 100 MW * ($30-$20) = $1000

34. Characteristics of FTRs
Defined from source to sink
MW level based on transmission reservation
Financially binding
Financial entitlement, not physical right
Independent of energy delivery
Let’s summarize the characteristics of an FTR.
An FTR is defined from the point of receipt (or source) to the point of delivery (where it is withdrawn). The points of receipt and points of delivery are “buses” or locations in the PJM control area.
The MW amount of the FTR is based on the transmission service reservation.
Financially binding -- An FTR financially binds the owner to the congestion activity on that path. In other words, once you have an FTR, you can’t give it back. They can be either a benefit or a liability, as we shall see shortly.
Financial entitlement, not physical right -- FTRs are separate from the actual energy delivered. The holder of the FTR is not required to deliver energy in order to receive an FTR credit. Once defined the FTR is in effect for the pre-defined period, regardless of whether energy is actually delivered.
The FTR can be consistent or inconsistent with the actual energy delivery. We will discuss this concept shortly.

35. 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
Let’s summarize the characteristics of an FTR.
An FTR is defined from the point of receipt (or source) to the point of delivery (where it is withdrawn). The points of receipt and points of delivery are “buses” or locations in the PJM control area.
The MW amount of the FTR is based on the transmission service reservation.
Financially binding -- An FTR financially binds the owner to the congestion activity on that path. In other words, once you have an FTR, you can’t give it back. They can be either a benefit or a liability, as we shall see shortly.
Financial entitlement, not physical right -- FTRs are separate from the actual energy delivered. The holder of the FTR is not required to deliver energy in order to receive an FTR credit. Once defined the FTR is in effect for the pre-defined period, regardless of whether energy is actually delivered.
The FTR can be consistent or inconsistent with the actual energy delivery. We will discuss this concept shortly.

36. 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).

37. FTR Packaged as Peak & Off Peak
FTRs are auctioned in the following blocks:
(a) 5x16 blocks for hours ending , Monday through Friday (excluding NERC holidays), in one-month strips;
(b) 2x16 blocks for hours ending , Saturday and Sunday, and NERC holidays in one-month strips; and
(c) 7x8 blocks for hours ending 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.

38. 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.

39. 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.