Transcript Power Trading Seminar on Jan 22 2011 Gabriel Ejebe

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
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
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)
Independent System Operators (ISOs) and
Regional Transmission Operators(RTOs)
CAISO
57,124 MW 25,526 miles Tx
ISO-NE
33,700
8,130
Midwest ISO 144,132
55,090
NYISO
40,685
10,893
PJM
164,895
56,499
SPP
66,175
50,575
ERCOT
72,712
40,000
30m
14m
43m
19m
51m
15m
22m
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
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
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
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
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
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 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
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
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
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 the
RTO 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-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
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 MW@$78
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
Numerical Example #3 Hedging a
Generator Offer
Day-ahead
Market Participant bids scheduled Generation of 100 MW @ $50.
Also Dec bids 10 MW @ $65 (virtual)
Assume Day Ahead Market clears at $60
Both bids clear @ $60
Day-ahead position is therefore -commitment of 100MW @$60 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
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
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+$100$700=$5400
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
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
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
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
24
?
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
25
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)
26
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
WHY?
To provide methodology to
allocate congestion charges
to those who pay the fixed
cost of the RTO
transmission system
27
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
28
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
29
FTRs & Congestion Charges
Congestion Charge =
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)
30
Energy Delivery
Consistent with FTR
Thermal Limit
FTR = 100 MW
Bus A
Energy Delivery = 100 MWh
Source
(Sending End)
Sink
(Receiving End)
LMP = $15
LMP = $30
Congestion Charge = 100 MWh * ($30-$15) = $1500
31
Bus B
FTR Credit = 100 MW * ($30-$15) = $1500
Energy Delivery
Not Consistent with FTR (I)
Bus A
LMP = $10
Bus B
LMP = $30
Bus C
LMP = $15
Congestion Charge = 100 MWh * ($30-$15) = $1500
32
FTR Credit = 100 MW * ($30-$10) = $2000
Energy Delivery
Not Consistent with FTR (II)
Bus A
LMP = $20
Bus B
LMP = $30
Bus C
LMP = $15
Congestion Charge = 100 MWh * ($30-$15) = $1500
33
FTR Credit = 100 MW * ($30-$20) = $1000
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
34
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
35
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 onemonth 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.