Transcript Slide - IEEE Entity Web Hosting

The Ontario Electricity
Market 1 Year in
Richard Penn
Mgr - Market Assessment
The IMO
Agenda
• Introduction - brief overview
• Market Design
• Issues Identified in the MSP reports
IMO
www.theimo.com
3
The IMO Web - Today’s market
4
The IMO - As Operator
of Reliable System
We balance generation to meet constantly
changing demand for electricity:
• Monitor conditions on IMO-controlled grid
• Schedule production from suppliers
• Maintain reliability to industry standards
5
The IMO - As Impartial
Market Administrator
We ensure accountability:
• Authorize/register participants
• Run commercial activities of market
We ensure equal, unbiased access:
• Provide historical and forecast
performance data
• Monitor conduct of participants –
fair competition, level playing field
6
www.theimo.com
The Energy Market
Statistics
Some Facts
Ontario has set a new Peak Demand of 25,414 Mw Aug 13,
2002
Ontario has set a new Monthly Energy Consumption of 14,500
Gw-hrs
Imports at times totaled over 4000 Mw an hour
Average energy price since May 1 58.42 $/Mw-hr
Average Weighted energy price since May 1 62.50 $/Mw-hr
Minimum Hourly Price was
7.84 $/Mw-hr
Maximum Hourly Price was
1036.80 $/Mw-hr
The Ontario Demand for the first year of the market is about
156 Tw-hr
Close to 10 B$ has been settled through the IAM markets
More than 136,000 Settlement Statements will have been
issued by April 30, 2003
100% of Settlement Statements issued on time, so far
99.6% of Settlement Statements issued to date were error free
Average HOEP for May to April 2003
$120.00
$100.00
Average Off Peak HOEP
Average On Peak HOEP
Average HOEP
$60.00
$40.00
$20.00
pr
il
A
h
ar
c
M
t
Se
pt
em
be
r
O
ct
ob
er
N
ov
em
be
r
D
ec
em
be
r
Ja
nu
ar
y
Fe
br
ua
ry
ug
us
A
y
Ju
l
Ju
ne
$M
ay
$/Mw-hr
$80.00
Month
11
Surrounding Spot Market Prices May 2002 to April 2003 ($CDN per MWh)
Preliminary
$80.00
$70.00
$60.00
$C/Mw-hr
$50.00
$40.00
$30.00
$20.00
$10.00
$IMO
NY Zone OH
ISO New England
PJM Western Hub
Market
May 2002 to April 2003 ($CDN per MWh)
12
20
02
-0
20 5-0
1
02
-0
20 5-1
5
02
-0
20 5-2
9
02
-0
20 6-1
2
02
-0
20 6-2
6
02
-0
20 7-1
0
02
-0
7
20
02 24
-0
20 8-0
7
02
-0
8
20
02 21
-0
20 9-0
4
02
-0
20 9-1
8
02
-1
20 0-0
2
02
-1
20 0-1
6
02
-1
20 0-3
0
02
-1
20 1-1
3
02
-1
20 1-2
7
02
-1
2
20
02 11
-1
20 2-2
5
03
-0
1
20
03 08
-0
20 1-2
2
03
-0
2
20
03 05
-0
20 2-1
9
03
-0
20 3-0
5
03
-0
319
Henry Hub Spot Price ($ Cdn/MMBtu)
Daily Natural Gas Prices
May 1'st to April 1, 2003
30
25
20
15
10
5
0
Delivery Date
13
The Energy Market
Simple Energy Spot Market
Energy Suppliers
Offer
Energy amount and
price offered for each
hour of the dispatch day,
for each dispatchable
supply facility
Offers
IMO Administered
Markets
Real-time
Energy
The market clears where the
offer and bid curves intersect.
This determines the:
• market clearing quantity and
• market clearing price (MCP)
Bids
Energy
Purchasers
Bid
Energy amount and
price required for each
hour of the dispatch day,
by each dispatchable
load facility
15
The Present Market
IMO - Administered Markets
Financial
Physical
Real-time
Energy
Operating
Reserve
Procurement
Transmission
Rights
Ancillary
Services
16
Who Can Participate in the
Markets
• Anyone can apply to become a registered
market participant
• Anyone who wishes to inject energy into,
or withdraw energy from the IMOcontrolled grid MUST become a Market
Participant
17
Who Can Participate?
Direct Large
Customer
Generator
Participants
Outside
Ontario
Embedded Large
Customer
Embedded
Generator
Distributor
18
Simplified Energy Market
Offers and Bids
Bid and Offer Basics
Generators and
Imports
Offers
IMO Administered
Markets
Bids
Loads and
Exports
Real-time
Energy
20
Composite Energy Offer Curve
Price
Available
Capacity
+MMCP
0
Cumulative
Quantity
-MMCP
21
Composite Energy Bid Curve
Price
Available
Capacity
+MMCP
0
Cumulative
Quantity
-MMCP
22
Market Clearing Price
Market Clearing Price
Demand
Supply
MCP
Price
Quantity
23
Determining Market Price
Market Design Principles
• The price of energy at each time and place
should reflect the marginal cost of producing or
not consuming one more unit of energy (at that
time and place)
• Dispatchable market participants should be
compensated for the effects of constraints
25
Setting the Market Clearing Price An Example
Generator 1
50 MW - $38/MWh
Generator 3
50 MW - $25/MWh
100 MW - $15/MWh
Generator 2
50 MW - $20/MWh
26
Offers Are Selected
Economically
Quantity
50 MW
$38 / MWh
50 MW
$25 / MWh
50 MW
$20 / MWh
100 MW
$15 / MWh
12:00
13:00
14:00
15:00
Generator 1
16:00
Time
17:00
Generator 2
18:00
19:00
20:00
Generator 3
27
Offers and Demand
Quantity
250 MW
$38 / MWh
200 MW
$25 / MWh
150 MW
$20 / MWh
100 MW
50 MW
12:00
$15 / MWh
13:00
14:00
15:00
Generator 1
16:00
Time
17:00
Generator 2
18:00
19:00
20:00
Generator 3
28
Offers and Demand - 5 Minute Intervals
MCP
$ / MWh
25
25
25
25
25
25
25
38
38
38
38
38
Quantity
50 MW
$38 / MWh
50 MW
$25 / MWh
50 MW
$20 / MWh
100 MW
$15 / MWh
16:00 16:05 16:10 16:15 16:20 16:25 16:30 16:35 16:40 16:45 16:50 16:55 17:00
Time
Generator 1
Generator 2
Generator 3
29
July 2002 Offer Stack
30
Comparison of a July to an October Domestic Offer Curve
Difference is due to Outages
31
Now it Gets Complicated
In the Ontario Design there are actually two
schedules for each generator
The Unconstrained schedule determines a uniform
Market Clearing price ( MCP) and assumes Ontario
is a copper plate where all generation can flow to all
loads
The Constrained schedule which determines the
actual dispatched output for each generator to meet
the physical limitations of the Transmission System
The difference is schedules can result in a
Constrained Payment
MCP - Copper Plate
Generator 1
Load
100 MW
$15
190 MW
Generator 2
100 MW
$20
No
transmission
line limit
Generator 3
100 MW
$25
Requirement is
190 MW
Region 1
• Gen 1: 100 MW
• Gen 2: 90 MW
• Gen 3: does not run
• MCP $20
Region 2
33
The IMO Web - Today’s market
34
Physical Limitations
• Bid/Offer selection must
result in system flows
within system’s physical
limitations
• Increases the cost of
power to ensure
reliability
Manitoba
East-West Tie
Quebec North
Minnesota
Flow North/
Flow South
Quebec
South
FETT
New York
East
Michigan
QFW
BLIP
New York
Niagara
35
Transmission Congestion
Generator 1
Load
100 MW
$15
190 MW
Generator 2
150 MW
transmission
line limit
100 MW
$20
Generator 3
100 MW
$25
Requirement is
190 MW
Region 1
•
•
•
•
Region 2
Gen 1: 100 MW
Gen 2: 50 MW
Gen 3: 40 MW
MCP $20 determined from Unconstrained
Schedule
36
Unconstrained vs Constrained
Reminder
• Unconstrained schedule determines prices
• Constrained schedule determines dispatch
instructions
• Any differences between unconstrained and
constrained schedule creates potential for CMSC
37
Constrained Payments for the 1’st
Year of the Market
• Constrained on Payments = about 75M$
• Constrained Off Payments = about 132 M$
38
The Actual Constrained Schedule
takes into account
- Available Transmission
- Transmission Limits
- Losses
- Generator Capabilities such as
Ramp rates
-Actual generator Output
39
The Reserve Area Bubble Diagram
KAPUSKASING
LITTLE
LONG
MOOSE RIVER
BASIN 230kV
MISS(ECCT)E
E-W-TR-E
LKHD(ECCT)E
TEM
TEK
KAO
Lakehead
115 kV Area
/A
8K
A
+
9K
X
02
5
P
LOWER
NOTCH
C
North of
FN/FS
TS
A
NORTHEAST
CHENAUX
Purchase
through
Michigan &
Nigara interfaces
QF
W
East of
QFW
S
DE
MAD
JO
S
ESSA
LA
C
/
AN
CL
LENNOX
230
St
11 . L
5
West of
FETT
MS
C
TE
LAMBTON
IP
BL
West of
BLIP
HI
AC
St
.L
FETT
23
0
0
23
FN/FS
H
GLP
EAST
CENTRAL
ALLANBURG
40
Operating Reserve
Now it Gets More complicated
• Algorithm simultaneously solves for
energy and three classes of OR
• whether a generator is in the energy
market or is “switched” to the OR market
they are held whole to their operating
profit.
• Requirement for OR determined by IMO,
based on industry standards
42
Operating Reserve
• Three classes of Operating Reserve
• 10 minute spinning - 25% of the largest
single contingency
• 10 minute non-spinning - 75% of the largest
single contingency
• 30 minute - 1/2 of the second largest
contingency
43
Operating Reserve
Who can offer OR?
• Dispatchable Loads
• Dispatchable Generators
• Importers and Exporters ( Injections /
Off-takes)
44
Offer Basics Operating Reserve Markets
Energy
Suppliers
OR
Offers
IMO Administered
Markets
OR
Offers
Energy
Purchasers
Operating
Reserve
Offer
Classes of OR Markets
Operating Reserve amount
• 10 min spinning
and price offered for each hour
• 10 min non-spinning
of the dispatch day
• 30 min
45
Optimization Objective
Value of Electricity
produced
…as indicated by
Energy demand from
non-dispatchable
loads and Energy bids
-
Cost to
produce Electricity
…as indicated by
offers to supply
Energy & Operating
Reserve
=
Economic gain
from trade
Algorithm maximizes
economic gain from trade
for all market participants
46
Interjurisdictional Trade
Further Complications
Interjurisdictional Trade
Similar to trade by resources inside Ontario
• Everyone must bid and offer to be scheduled
• Scheduling is independent of any bilateral
contracts
• No physical transmission rights
• Uplifts apply to exports (some exceptions)
48
Interjurisdictional Trade
Some differences from resources in Ontario
• Zonal pricing
• Scheduled hourly
• Bid and offer from Boundary Entity
Resources
49
Interjurisdictional Trade
Quebec (8)
Manitoba
Minnesota
Michigan
New York
50
Boundary Entities and
Boundary Entity Resources
• MP acts as a Boundary Entity
• Place bids and offers from Boundary
Entities Resources
• Participant must navigate other jurisdictions,
supply NERC tag, have NEB permit (for
export to US) this can lead to failed
transactions
51
Types of Interjurisdictional Trade?
Export
Import
52
Wheel-Through
Export of Energy From Ontario
IMO-Administered Markets
Ontario
NY
Intertie
Zone
MWs Exported
from Ontario
External Market (New York Example)
New York
MWs Imported to
New York
53
Import of Energy Into Ontario
IMO-Administered Markets
Ontario
NY
Intertie
Zone
MWs Imported to
Ontario
External Market (New York Example)
New York
MWs Exported
from New York
54
Quick Summary
55
Ontario’s
Wholesale Electricity Market
Suppliers
Generators
Purchasers
Offers
Schedule
& Dispatch
Wholesale
Sellers
Bids
IMO Administered
Markets
Settlements Energy Market
$
MCP calculated
Wholesale
Consumers
Schedule
& Dispatch
Billing
$
Distributors
Retailers
Transmitters
Transactions / Information
56
Electricity
Where is the Market Evolving To
57
Anticipated Evolution to the Market
IMO - Administered Markets
Physical
Financial
Real-time
Energy
Day Ahead Energy
Forward
Transmission
Rights
Operating
Reserve
Hour
Ahead
Dispatcha
ble Load
Procurement
Ancillary
Services
58
The MSP Reports
http://www.theimo.com/imoweb/marketSurveil/mspReports.asp
59
From the 1’st MSP Report
• Serious Capacity problem in Ontario
• Structure is not yet conducive to effective
competition
• Implications of Out of Market Control Actions
• Transmission Co-ordination is an issue
• Demand Responsiveness is an issue
• No inappropriate behavior
60
From the 2’nd MSP Report
• Nothing Abnormal about outage programs by
generators, but it contributed to a shortage in
supply
• No inappropriate behavior, anomalous events
can be explained satisfactorily
• Price responsiveness of load can have a
significant impact upon price and examples of
that have occurred in the past summer
• Non-intuitive Price Outcomes continues to be
an issue
61
From Pre-dispatch to Real-time:
An Hour in the Life of the
Market
Purpose of Case Study
• Provides graphical illustration of the factors
contributing to the three key pricing issues.
• Uses actual data for a representative hour in July to
isolate the pricing implications of:
• different treatment of imports/exports in pre-dispatch vs. real-time
• differences between pre-dispatch demand forecast and real-time
demand
• new “market contingencies” such as self-scheduling deviations and
failed intertie transactions
• Outages and derates
• Reduction of market-based operating reserve requirements
63
The Inter-relationship of the “Factors”
Forecast vs Actual
Demand
Failed Transactions
Self-Scheduler Error
Outages / Deratings
Impact on Supply Adequacy
Sum of these Factors can lead to an OR
Reduction
64
Price Change
Background Facts
• Pre-dispatch
• Real-time
• Energy price - $950.66
• HOEP - $132.51
• 10 N - $868.74
• Hourly IOG - $62.78
• 10S - $878.14
• 30R - $868.73
• Demand - 24,679 MWh
• Interval 4
• Energy price - $169.63
• 10 N - $0.99
• 10S - $10.29
• 30R - $0.10
• Interval 4 demand - 24,514
MWh
65
Treatment of Net Imports
• Imports and exports are scheduled for real-time
delivery in the one-hour ahead pre-dispatch.
• Imports and exports can set the price in pre-dispatch
• In real-time, the schedules of selected imports and
exports are fixed and placed at the bottom of the
offer curve.
• Imports and exports cannot set the price in real-time
• Real-time offer curve is steeper than pre-dispatch
offer curve around forecast of demand.
• In sample hour 3,494 MWh imports selected and
304 MWh of exports selected.
66
Treatment of Net Imports
PD
RT
Price ($)
Pre-dispatch
Demand plus
OR
Requirement
2000
$1275.55
1000
$950.66
0
-1000
-2000
Net Imports
0
5000
10000
15000
MWh
20000
25000
67
Sensitivity to Demand Forecast
• One demand value used to establish pre-dispatch
schedules and price
• Forecast hourly peak demand
• Real-time interval by interval demand will always
be different
• When real-time offer curve is steep, modest
differences in demand can cause large price
differences
• In sample hour, interval 4, demand difference was
165 MWh
68
Sensitivity to Demand Forecast
PD
RT
Price ($)
2000
$1275.55
1000
$348
0
Real-time
Demand plus
OR
Requirement
-1000
-2000
0
5000
10000
15000
MWh
20000
25000
69
The Inter-relationship of the “Factors”
Forecast vs Actual
Demand
Failed Transactions
165 MW
Self-Scheduler Error
Outages / Deratings
Impact on Supply Adequacy
165 MW
Sum of these Factors can lead to an OR
Reduction
70
Price Change
$348
New Market Contingencies
Failed Transactions and Self-Scheduling
• Failed net imports or under forecast of selfscheduling production cause the real-time
offer curve to shift to the left.
• less supply causes upward pressure on price
• In sample hour, interval 4, 75 MWh of net
imports had failed (275 MWh of imports
and 200 MWh of exports).
• In sample hour, interval 4, 36 MWh under
forecast of self-scheduling generation.
71
New Market Contingencies
Failed Transactions and Self-Scheduling
RT
RT2
Price ($)
2000
$1500.00
1000
$1275.55
0
-1000
-2000
5000
10000
15000
MWh
20000
25000
72
The Inter-relationship of the “Factors”
75 MW
Forecast vs Actual
Demand
Failed Transactions
36 MW
Self-Scheduler Error
Outages / Deratings
Impact on Supply Adequacy
111 MW
Dependent upon Sum of these Factors can lead
to an OR Reduction
Price Change
$1500
73
Outages and Derates
• Outages or derates that occur after the final
pre-dispatch remove supply from the realtime offer curve.
• places upward pressure on the price
• In sample hour, interval 4, 690 MWh had
been lost due to forced outage or derates
• Outages caused the unconstrained sequence
to be short operating reserve.
74
Outages and Derates
RT
RT2
Price ($)
2000
1000
$1275.55
0
-1000
-2000
5000
10000
15000
20000
25000
MWh
75
The Inter-relationship of the “Factors”
Forecast vs Actual
Demand
Failed Transactions
Self-Scheduler Error
Outages / Deratings
690 MW
Impact on Supply Adequacy
690 MW
Sum of these Factors can lead to an OR
Reduction
76
Price Change
$2000
Reduction in Market-Based Operating
Reserve Requirement
• Market-based operating reserve requirement
reduced when IMO look-ahead tool forecast a
pending shortage of operating reserve in the
constrained schedule
• IMO satisfies NERC/NPCC requirements with
“out of market” mechanisms
• reductions in operating reserve requirements done
manually and can be “blunt”
• In sample hour, interval 4, total operating reserve
requirements reduced by 1210 MW
77
Reduction in Market-Based Operating
Reserve Requirement
RT
RT2
Price ($)
2000
$1275.55
1000
-1000
-2000
$136.23
0
-1000
Reduce OR
requirement by
1210 MWh
-2000
5000
10000
15000
20000
25000
MWh
78
The Inter-relationship of the “Factors”
Forecast vs Actual
Demand
Failed Transactions
Self-Scheduler Error
Outages / Deratings
Impact on Supply Adequacy
1210 MW
Sum of these Factors can lead to an OR
Reduction
1210 MW
79
Price Change
$136.23
Effect of All Factors
PD
RT2
Price ($)
2000
$950.66
1000
$169.63
0
-1000
-2000
0
5000
10000
15000
MWh
20000
25000
30000
80
The Inter-relationship of the “Factors”
165 MW
Forecast vs Actual
Demand
75 MW
36 MW
Failed Transactions
Self-Scheduler Error
Outages / Deratings
690 MW
Impact on Supply Adequacy
165
MW
90 MW
54
-636
MW
574
MW
Sum of these Factors can lead to an OR
Reduction
1210 MW
81
Price Change
$169.63
The END
82