Transcript Slide 1

Electricity transmission pricing:
getting the prices “good enough”?
Richard Green
Institute for Energy Research and Policy
Transmission pricing
• Geographical differentiation in the
wholesale market
• Prices for connecting to and using the
transmission network
Six objectives
1. Promote the efficient day-to-day
operation of the bulk power market
2. Signal locational advantages for
investment in generation and demand
3. Signal the need for investment in the
transmission system
Six objectives
4 Compensate the owners of existing
transmission assets
5 Be simple and transparent
6 Be politically implementable
Green (Utilities Policy, 1997)
Three approaches
• Ignore transmission issues
• Ignore transmission issues, then bribe
market participants to sort things out
• Integrate transmission issues into your
market design(s)
Major power flows
Source: UCTE
Major power flows and congestion
Congested 26-75%
Source: UCTE
76-99%
100%
If costs differ between areas
P
P
PH
Pricetrade
PL
Xpts
GW
Mpts
GW
If costs differ between areas
P
P
Pricetrade
Xpts
GW
Mpts
GW
If costs differ between areas
and the lines are too thin…
P
P
Pricetrade
Xpts
GW
Mpts
GW
If costs differ between areas
and the lines are too thin…
P
P
T{
Xpts
GW
Mpts
GW
If costs differ between areas
and the lines are too thin…
you could still ignore the problem
P
P
Pricetrade
Xpts
GW
Mpts
GW
but someone will want money to sort it out!
Zones in the NEM
• NEM runs nodal model and dispatches
according to nodal conditions (prices)
• Generators / loads grouped into regions
• All generators in a region receive the
regional reference price
– Marginal cost at a reference node
• No compensation for constrained running
From a line to a network…
• Electricity will flow along every path
between two nodes
• It “cannot” be steered
• If one line fails, the flows instantly change
• Overloading any line can be catastrophic
(for example…)
The impact of loop flows
A
B
C
The impact of loop flows
A
B
C
Nodal prices
• Set price of power equal to marginal cost
at each point (node) on the network
– Marginal cost of generation (if variable)
– MC of bringing in power from elsewhere
• Centralised market uses the nodal prices
• Bilateral trades which move power pay the
difference in nodal prices
Nodal trading
•
•
•
•
Price at A = 20, Price at B = 30
B
I sell at A, I receive 20
A
I sell at B, I receive 30
I generate at A and sell at B, I receive the
agreed bilateral price and pay (30 – 20)
• I generate at B and sell at A, I receive the
agreed bilateral price and pay (20 – 30)
The impact of loop flows
and constraints
A
B
C
6 MW at C needs
3 MW from A and
3 MW from B
Prices – constraint AB
• Price at C = (Pa + Pb)/2
• 1 MW extra capacity allows 1.5 MW from A
to replace 1.5 MW from B
• Shadow cost of constraint = 1.5 (Pb – Pa)
• If Pa = 10, Pb = 30
• Pc = 20, shadow cost = 30
• Pc = Pa + 1/3 shadow cost
= Pb – 1/3 shadow cost
The impact of loop flows
and constraints
A
B
C
3 MW at C needs
–3 MW from A and
6 MW from B
Prices – constraint AC
• Price at C = 2Pb – Pa
• 1 MW extra capacity allows 3 MW from A
to replace 3 MW from B
• Shadow cost of constraint = 3 (Pb – Pa)
• If Pa = 10, Pb = 30
• Pc = 50, shadow cost = 60
• Pc = Pa + 2/3 Shadow cost
= Pb + 1/3 Shadow cost
The impact of loop flows
and constraints
A
B
C
3 MW at C needs
6 MW from A and
–3 MW from B
Prices – constraint CB
• Price at C = 2 Pa – Pb
• 1 MW extra capacity allows 3 MW from A
to replace 3 MW from B
• Shadow cost of constraint = 3 (Pb – Pa)
• If Pa = 10, Pb = 30
• Pc = –10, shadow cost = 60
• Pc = Pa – 1/3 shadow cost
= Pb – 2/3 shadow cost
Summary
Constraint is on line:
None
AB
AC
BC
Price at A
10
10
10
10
Price at B
10
30
30
30
Price at C
10
20
50
-10
Implications
• Nodal prices can vary significantly
– Over time
– Over space
• The first creates a need for hedging
• The second makes it harder
• The prices may be counter-intuitive
How to hedge
• Transmission Congestion Contract
• Spatial contract for differences
– Pays the holder the difference in nodal prices
between two specified points (from A to B)
– Price at B – Price at A
– Perfect hedge if you generate that amount of
power at A and sell it at B
• Remember the real-time charge is (PB – PA)
Who’d sell that hedge?
• The spot market charges raise a surplus
– Who gets it?
• If the Transmission Congestion Contracts
allocation is feasible, Hogan (1992) shows
spot market surplus ≥ TCC payments
• Organisation receiving the spot surplus
can issue TCCs and find itself hedged!
Inferior ways of hedging
• Financial Transmission Rights (options)
– Only pay out when value is positive
– Payments may exceed spot revenues
• Physical Transmission Rights
– Limited by system capacity
– If line limit on AB is 100, can only issue 100
– With TCCs, 100 BA “allows” an extra 100 AB
• “Smeared” share of congestion revenues
What if you get it wrong?
• Operational difficulties
– PJM’s first market
• Economic operating mistakes
• Investment mistakes
– At present, we don’t know much about these
How much does it cost to get it wrong?
• Compare demand and operating patterns
with different pricing rules
• Model applied to England and Wales,
1996 data
• Numbers are country- and time-specific
• Approach is general
The model
• NGC system in 1996/97
• Thirteen zones (two pairs of NGC’s zones
are combined, one zone split into two)
• Iso-elastic demand in every zone
• Generation in most £/MWh Gas, Coal,
Nuclear
Oil
GW
Figure 2: Simplified Version of the Transmission System in England and Wales
Transmission system model
Flow in GW shown on each line
North
1
0.4
0
2.5
2
1.2
5.1
2.6
4
2.9
3
5
2.6
2.4
7.5
2.1
6
2.1
7
2.5
2.0
4.7
1.6
8
10
South-West
0.8
2.8
13
0.7
0.2
12
3.0
2.2
9
A DC load flow
model with losses
(proportional to the
square of flows)
and constraints on
the total flows
across NGC’s
system boundaries
Three pricing rules
• One price for generation and for demand
in each zone (optimal)
• One price at each node for generation, but
a common national price for demand
• One national price for generation and one
national price for demand (actual system)
– Constraints are managed via payments for
constrained-on and constrained-off running
What is welfare?
• NGC’s operating surplus
– Kept the same under each of the rules
• Generators’ operating surpluses
– Energy revenues less variable fuel costs
– Gas contracts assumed not to be variable
• Consumer surplus
– Area under their demand curve and above the
price they actually pay
Prices – winter peak
£/MWh
50
40
Optimal
30
G varying
20
Uniform
10
0
0
1
2
3
4
5
6
7
8
9
10
12
13
Prices – summer trough
£/MWh
8
6
Optimal
4
G varying
2
Uniform
0
0
1
2
3
4
5
6
7
8
9
10
12
13
Basic results
Pricing System
Optimal Nodal (for
Uniform
Generators)
Av. Revenue (£/MWh)
27.17
27.39
28.21
Changes (% of optimal, competitive, revenue):
Consumer surplus
-0.2%
-3.4%
Generators’ profits
Welfare
-0.9%
-1.2%
2.1%
-1.3%
Intuition for the results
• Adjustments to generation for constraints
have to happen, whatever the pricing rule
– Here, these are in the same direction as the
economic response to marginal losses
• Cost differences at stations partially offset
marginal transmission losses
Market power
• Sometimes a problem in this market
– General incentive to raise prices
– Particular incentive to raise prices in importconstrained area
– Uniform pricing gives incentive to reduce
prices in export-constrained area
• Model two strategic generators plus fringe
– Both firms change slope of bids (by region)
Generators’ capacities
Other
PowerGen
National Power
GW
10
8
North
South-West
6
4
2
0
0
1
2
3
4
5
6
Zone
7
9
10
8
12
13
Prices – winter peak
£/MWh
150
125
100
75
Optimal
MP Optimal
G varying
MP G varying
50
25
0
0
1
2
3
4
5
6
7
8
9
10
12
13
Prices – summer trough
£/MWh
10
8
6
4
Optimal
MP Optimal
G varying
MP G varying
2
0
0
1
2
3
4
5
6
7
8
9
10 12
13
Prices – zone 12
MP Optimal
MP G varying
Optimal
G varying
Uniform
£/MWh
150
125
100
75
50
25
0
Winter
peak
Trough
Summer
peak
Trough
Prices – zone 1
MP Optimal
MP G varying
Optimal
G varying
Uniform
£/MWh
40
30
20
10
0
Winter
peak
Trough
Summer
peak
Trough
Market power
Pricing System
Optimal Nodal (for
Uniform
Generators)
Av. Revenue (£/MWh)
44.70
46.90
45.25
Changes (% of optimal, competitive, revenue):
Consumer surplus
Generator profit
Welfare
Rel. to optimal
Rel. to comp
-5.4%
-6.6%
4.3%
-1.0%
-2.1%
-2.3%
-3.1%
-6.5%
-7.2%
Conclusions of this study
• Optimal pricing would create winners
(northern consumers, southern generators)
and losers (northern generators, southern
consumers)
• It would be less vulnerable to market power
• Welfare gains of 1% of turnover are quite
large as Harberger triangles go!
Other transmission charges
• Connection assets – local costs
• Capacity-based use of system
– Affect investment decision, not operating
choices
• Output-based use of system
– Affect operating choices and might be used to
offset consistent errors in the market rules
• Contracts for constrained running
Interactions between charges
• Investing generators should consider both
spot market and transmission charges
– With the right spot signals, transmission
charges should be uniform
– Differentiated transmission charges needed if
spot prices send inadequate signals
– Using both would over-signal, reducing
transmission costs, but raising generators’
Conclusion
• For major changes, transmission charging
creates well-informed winners and losers
– Gains typically small relative to transfers
• With good operators, the system is
resilient to poor rules
• Better rules will create gains worth having