Transcript Pricing and Gaming in a Simple Electricity Market (Brown1-PPT)

Pricing and Gaming in a Simple
electricity Market
Queen’s University Regulatory
Economics Class Guest Lecture
March 24, 2015
• David Brown
• Senior Advisor, Regulatory Policy
• [email protected]
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Overview
• Deregulation in Electricity
– Potentially competitive sectors
– Regulated natural monopoly sectors
– Motives for restructuring
• Concept of congestion in general
• A simple electricity grid
• Pricing, shadow prices, LMP
• Ontario’s uniform pricing
• Congestion side payments and gaming
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Structure of the Electricity Sector
Demand
bids
Generators
Supply
Bids
Hydro One
(Transmission)
Retailers
Local Distribution
Company
Dispatchable loads
Independent
Electricity System
Operator (IESO)
Demand
Bids
Distribution
Electricity Retailer
Customers
(Fixed Contracts)
LDC Customers
(SSS)
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Deregulation in electricity
• Potentially competitive sectors
• Natural monopoly regulated sectors
• Motives for electricity deregulation: Official story
– Transfer investment risk to private sector
– Greater price and cost transparency
– Benefits of competition
• Motives for electricity deregulation: Real story
– Political lobbying by industrial loads
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Congestion Generally
• Economic Activity takes place via infrastructure networks.
Examples are: road systems, telephony, gas pipelines,
electric grid, the banking system, air travel system.
• Some networks are “hard” like the grid, gas pipelines,
road system. Some are “soft” like common languages
e.g.., English, common software packages e.g., Microsoft
Windows.
• Mostly networks are in the background when we think of
the activity that uses them – we take them for granted.
• Congestion: reaching the capacity of the network to
transmit what ever it transmits.
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Gardiner and Lakeshore
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Two regions trading
P
S2
S1
D2
D1
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Region 1
Region 2
S1: P = 5 + 0.5Q
D1: P = 30 – 0.5Q
S2: P = 10 + 0.5Q
D2: P = 30 – 0.25Q
Aggregate
•
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Two regions trading
Pre-trade
Price
Quantity
Exports
Imports
Trade
Price
Quantity
Supplied
Quantity
Demanded
Exports
Imports
Trade with
congestion
Price
Quantity
Supplied
Quantity
Demanded
Exports
Imports
Region 1
17.5
25
-
Region 2
23 1/3
26 2/3
-
Aggregate
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21
21
32
22
54
18
36
54
14
-
14
19 1/4
22 1/6
28 1/2
24 1/3
52 5/6
21 1/2
31 1/3
52 5/6
7
-
7
51 2/3
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Congestion generally
• When the infrastructure is uncongested
production is at its highest and there are no
“congestion costs”. The quantity is produced at
its lowest possible cost.
• When trade is restricted (to 7 units in the
example) or not possible there is a re-dispatch
of production from lower cost to higher cost
producers. The total produced is lower. There is
a price difference between the two regions.
• Starting from the no trade / no infrastructure
position a social decision must be made as to
how much capacity to build.
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Congestion generally
• This decision has that “one size must fit all”
characteristic of many public goods.
• Thus the decision will tend to be made in the
political arena.
• Who will oppose larger capacity and who will
support it?
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Congestion generally
• These types of issues arise frequently in
regulatory economics
• There is at least one very big example of a
congestion story happening right now in North
America with big implications for Canada
• What is it?
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A Three Node Electricity Grid
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Figure 1
A Three Node Grid
NW
NE
S
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A Three Node Electricity Grid
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Figure 2
Dispatch with no constraints
26 2/3 MW
NW
NE G2 = $30
G1 = $20
Injection = 80
53 1/3 MW
26 2/3 MW
S Load = 80
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A Three Node Electricity Grid
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Figure 3
Injections at both nodes
33 1/3 - 10 = 23 1/3 MW
NW
NE G2 = $30
Injection = 30
G1 = $20
Injection = 100
66 2/3 + 10 = 76 2/3 MW
33 1/3 + 20 = 53 1/3 MW
S Load = 130
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A Three-Node Electricity Grid
• In figure 3 in the text the market price would be
$30 given a demand of 130 MW.
• Generator 2 at the NW node would be earning
rents as its costs are $20 / MW while it receives
the price of $30.
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Shadow Prices
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Figure 4
Shadow Prices
P = 30
NW
33 1/3 - 10 = 23 1/3 MW
G1 = $20
Injection = 100
P = 30
NE G2 = $30
Injection = 30
66 2/3 + 10 = 76 2/3 MW
33 1/3 + 20 = 53 1/3 MW
S Load = 130
P = 30
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Shadow Prices
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The Shadow Price
The Shadow Price at a node is the marginal cost of serving another MW of
load at that node. In a system with no transmission constraints or line
losses each node could be served by the generator that is at the margin in
the merit order. Thus the shadow price at all nodes would be that
generator’s offer price.
If transmission constraints are present then generation will have to be redispatched around the constraint – the merit order will have to be departed
from. This will result in locational differences in shadow prices.
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Transmission constraints
• Thermal Limit: exceed this limit and the line
might melt
• Security Limit: exceed this limit and the line
would not be able to handle the extra surge that
might occur under some other contingency. This
type of limit will be more restrictive than a
thermal limit.
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Grid with a Constraint
• Figure 4 in Word doc.
• Figure 5: Redispatch around the constraint is
necessary to avoid violating the constraint.
• For every 2 MW injected at NE, only need to
reduce injection at NW by 1 MW.
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A Three-Node Electricity grid
• What will the shadow prices be with a corrected
dispatch?
• In figure 6, with locational marginal pricing,
there are rents being earned but not by the
generators.
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Ontario’s uniform price system
• Although the intention at market opening in
2002 was to move to an LMP system, it never
sat well with the Ontario government.
• Also, it would have meant higher prices for
consumers in southern Ontario – many of whom
are politically influential.
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Uniform Price System
• It is actually referred to as the two-schedule,
uniform price system
• Market Schedule ignores congestion constraints
– pretends we can operate as in Figure 2 here.
• Dispatch schedule includes constraints – sets
quantities for the generator but the price is set
by market schedule. With load = 80, price =
$20.
• But what about G2 whose costs are $30?
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Congestion Payments
• G2 must be given a “constrained on” payment –
pay the owner the profits he loses by not being
able to actually carry out the market schedule:
• G2’s market schedule is 0 output therefore 0
profit.
• G2’s dispatch schedule is 10 MW. With MCP set
at $20 in market schedule G2 loses $100.
• Congestion payment is the operating profit he
would make in market schedule minus the
operating profit he makes in dispatch schedule
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Uniform prices and two schedules:
Congestion side payments
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Congestion payment = Operating Profit (Market Schedule) – Operating Profit (Dispatch
Schedule)
Operating profit in the market schedule is defined as:
1) Operating profit(MS) = (MCP – Offer price) * Market Quantity = (20 – 30) * 0 = 0
Similarly operating profit in the dispatch schedule is defined as:
2) Operating profit(DS) = (MCP – Offer price) * Dispatch Quantity = (20 – 30) * 10 = -$100
•
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Congestion payment = 1 – 2 = 0 - 9-100) = $100.
•
More Generally Congestion payment = (MCP – Offer price) (Market Quantity – Dispatch Quantity)
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Congestion Payment to G1
• This payment is harder to understand
• Because of congestion G1 can only produce 70
MW, not 80.
• Pay G1 the difference between his market
schedule profit and his dispatch schedule profit.
• With Load = 80, MCP = 20 G1 gets no payment.
• However if load was up at 130, then MCP = $30,
and G1 will get a congestion payment. (Fig 7 in
doc.)
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Gaming of Congestion Payments
• A big problem in this market is that generators can influence
the size of the congestion payments they receive:
• Congestion payment = (MCP – Offer price) (MQ – DQ)
• If you are constrained on MQ < DQ. What can you do to
increase the size of the payment?
• If you are constrained off MQ > DQ. Same question…
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