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 implementableGreen (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
Source: UCTE
Congested 26-75% 76-99% 100%
If costs differ between areas
GW
P
GW
P
PL
PHPricetrade
Xpts Mpts
If costs differ between areas
GW
P
GW
P
Pricetrade
Xpts Mpts
Pricetrade
If costs differ between areas
GW
P
GW
P
and the lines are too thin…
Xpts Mpts
If costs differ between areas
T {
GW
P
GW
P
and the lines are too thin…
Xpts Mpts
Pricetrade
If costs differ between areas
GW
P
GW
P
and the lines are too thin…you could still ignore the problem
but someone will want money to sort it out!Xpts Mpts
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…)
A B
C
The impact of loop flows
A B
C
The impact of loop flows
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
• I sell at A, I receive 20
• 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)
AB
A B
C
6 MW at C needs3 MW from A and3 MW from B
The impact of loop flowsand constraints
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
A B
C
3 MW at C needs–3 MW from A
The impact of loop flowsand constraints
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
A B
C
and constraints
3 MW at C needs 6 MW from A
The impact of loop flows
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
GW
Gas, Coal,Nuclear Oil
North
South-West
A DC load flow model with losses (proportional to the square of flows) and constraints on the total flows across NGC’s system boundaries
Transmission system model
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
0
10
20
30
40
50
0 1 2 3 4 5 6 7 8 9 10 12 13
£/MWh
Optimal
G varying
Uniform
Prices – summer trough
0
2
4
6
8
0 1 2 3 4 5 6 7 8 9 10 12 13
£/MWh
Optimal
G varying
Uniform
Basic results
Pricing System Optimal Nodal (forGenerators)
Uniform
Av. Revenue (£/MWh) 27.17 27.39 28.21
Changes (% of optimal, competitive, revenue):
Consumer surplus -0.2% -3.4%
Generators’ profits -0.9% 2.1%
Welfare -1.2% -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 import-
constrained 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
0
2
4
6
8
10
0 1 2 3 4 5 6 7 9 10 8 12 13
Zone
GW OtherPowerGenNational Power
North
South-West
Prices – winter peak
0
25
50
75
100
125
150
0 1 2 3 4 5 6 7 8 9 10 12 13
£/MWh
Optimal MP Optimal
G varying MP G varying
Prices – summer trough
0
2
4
6
8
10
0 1 2 3 4 5 6 7 8 9 10 12 13
£/MWh
Optimal MP Optimal
G varying MP G varying
Prices – zone 12
0
25
50
75
100
125
150
Winterpeak
Trough Summerpeak
Trough
£/MWh MP Optimal
MP G varyingOptimal
G varyingUniform
Prices – zone 1
0
10
20
30
40
Winterpeak
Trough Summerpeak
Trough
£/MWh MP Optimal
MP G varyingOptimal
G varyingUniform
Market power
Pricing System Optimal Nodal (forGenerators)
Uniform
Av. Revenue (£/MWh) 44.70 46.90 45.25
Changes (% of optimal, competitive, revenue):
Consumer surplus -6.6% -1.0%
Generator profit 4.3% -2.1%
Welfare Rel. to optimal -2.3% -3.1%
Rel. to comp -5.4% -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