Liberalised Electricity Markets and
Nuclear Power:
The case of Australia’s NEM
Professor Tony Owen
UCL Australia, Adelaide
tony.owen@ucl.ac.uk
Presentation to the Nuclear Engineering Panel,
Engineers Australia (Sydney), 27 March 2013
The question
Is the National Electricity Market impeding the
effectiveness of energy-sector policies designed
to mitigate climate change through long-term
investment in low-carbon technologies?
The market has changed
Before market liberalisation
Vertically-integrated monopolies, largely capacitydriven investment, with average cost pricing, and
consumers bearing market risks. Discount rate =
social rate (social opportunity cost of capital).
After market liberalisation
Investment and market risks borne by the investor,
with short-run marginal cost (SRMC) pricing
(generating price uncertainty). Discount rate =
commercial rate (private opportunity cost of
capital).
The NEM: an energy-only market
• Gross pool: obligatory market
• Price bids every 5 minutes, averaged over halfhour in five regional spot markets
• Generally, bids = technology’s SRMC
• All dispatched power attracts the same
marginal bid price, irrespective of the above
• Floor price = -$1000/MWh
• Ceiling price = $12,900/MWh
($13,100/MWh from1 July 2013)
The Cumulative Price Threshold
If the sum of the trading interval spot prices
over a rolling seven day period total or exceed
the Cumulative Price Threshold (CPT),then spot
prices are capped at the administrative price cap
of $300/MWh. The CPT is currently $193,500
($197,100 from 1 July 2013)
Electricity market intervention
Current government policy in the power sector is
primarily focused on policies to support the
development and deployment of non-nuclear lowcarbon technologies to reduce their costs and thus
reduce the long-term costs of decarbonising the
sector. However, the current NEM market design
may make low-carbon investment riskier than
continued investment in fossil fuel technologies.
Thus, even with a carbon price, investment in lowcarbon technologies may be discouraged.
Investment in power generation
It is intended that price “signals” should encourage
investment in new capacity, but long-term investment
decisions appear to conflict with the short-term (i.e.
instantaneous) nature of the market and may impede the
effectiveness of climate policies. Uncertainty on future
electricity prices is compounded by other risks:
1. Long-term uncertainty on carbon price;
2. Unclear competitive nature of low carbon technologies;
3. Long lead times for high-up-front-cost low-carbon
technologies: the chain of innovations is too long, too
complex and too diverse; and
4. High levels of political and regulatory risks.
Carbon pricing
The marginal generator (that sets the wholesale
price) is generally a fossil fuel generator. Thus,
marginal bid pricing should include the carbon
price. This should benefit low carbon technologies.
However, the risks attached to recovery of fixed
costs of new generation assets will vary
considerably depending on the capital intensity of
the different technologies. For large up-front cost
low carbon technologies (such as new nuclear,
concentrated solar thermal, off-shore wind, CCS,
etc.) these risks may more than offset the cost
minimisation criteria for investment choice.
Investment in gas is much less risky than in
wind (and other low-carbon technologies)
• Wind power operates as base-load, ahead of nuclear,
coal and CCGT, because of its lower SRMC.
• However, the large gap between SRMC and average
cost of wind gives rise to a high level of risk that full
cost recovery will not be achieved.
• CCGT lower capital cost, plus partially self-hedged
particularly as it is generally the marginal-bid
technology. Thus price volatility for CCGT is likely to
be lower than for wind and nuclear.
Number of negative trading intervals
in the NEM
2009-2010
86
2010-2011
208
2011-2012
274
Given the RECs wind receives, it can bid negative
to ensure dispatch. Nuclear and brown coal may
also bid negative to avoid costs associated with
shutting down or operating inefficiently.
Capital costs ($/kW)
Source: BREE (2012) & ACIL Tasman (2011)
IGCC (brown):
6306
IGCC (black):
5346
Coal S/C (brown):
3788
Coal S/C (black):
3124
CCGT:
OCGT
Wind (on-shore):
Nuclear:
Solar thermal (para. trough):
6841 (with CCS)
7363 (with CCS)
5855 (with CCS)
1062
723
2530
3470
4920
Levelised costs of electricity ($/MWh)
Source: BREE (2012)
IGCC (black):
176-189 193-253 (with CCS)
Coal S/C (brown): 162
205 (with CCS)
Coal S/C (black): 135-145 162-205 (with CCS)
CCGT:
96-108
OCGT
203-259
Wind (on-shore): 111-122
Nuclear:
94-99
Solar thermal (para. trough): 330-402
Levelised cost of electricity by technology and discount rate
(5% and 10%): 2015¢/kWh (Source: IEA/NEA)
Country
Nuclear
Belgium
6.1 10.9
8.2 10.0
Czech Rep
7.0 11.5
9.0 12.4
France
5.6
9.2
Germany
5.0
8.3
Hungary
8.2 12.2
Japan
5.0
7.6
8.8 10.7
Korea
3.1
4.5
6.7
Netherlands
6.3 10.5
Slovakia
6.3
Switzerland
6.2 11.3
USA
4.9
7.7
7.4
9.0
China
3.3
5.0
5.5
5.8
9.8
Coal
Coal with CC
CCGT
9.0
9.1 13.9
Onshore
wind
9.6
9.6 13.6
9.2 10.4
14.6 21.9
9.0 12.2
7.5
9.1
7.7
9.8
8.5
9.3
10.6 14.3
10.5 12.0
7.3
9.1
9.5
8.2 10.0
7.8
8.2
8.6 12.2
9.4 10.5
16.3 23.4
12.0 14.2
6.8
9.4
7.7
8.3
4.8
7.0
4.9
5.2
7.0
9.9
Recovery of capital (i.e. fixed) costs
• Infra-marginal rent
• Scarcity rent
Low-carbon market-based renewables (such as
wind) have extremely low SRMCs and will
displace fossil fuel plants and lower inframarginal rents (following diagrams).
Wholesale market without wind
Price ($/MWh)
Demand
WP
Infra-marginal
rents
Capacity (MW)
Baseload technologies
Intermediate technologies
Peaking technologies
Wholesale market with deployment of
wind
The theory
The sum of the half-hourly infra-marginal rents
will cover the fixed costs of each new plant,
whatever the cost structure of its technology.
For peaking plants, it is the scarcity rent from
short-term price spikes that enables them to
cover their fixed costs (although scarcity rent
benefits all, not just the peaking plants).
Wholesale market without wind
Price ($/MWh)
Demand
WP
Scarcity rent
Infra-marginal
rents
Capacity (MW)
Baseload technologies
Intermediate technologies
Peaking technologies
Incentive mechanisms for investment
Long-term security of supply, or capacity adequacy,
is a public good since it is non-rival and nonexcludable. Non-rival because everybody benefits
from the security provided to the system by new
plant, but investors in peak units that are never
used earn nothing despite the fact that they
contribute towards system security (a positive
externality to operating reserves). Non-excludable
because it is impossible to derive each consumers
preference for supply reliability and their
willingness to pay.
Addressing the problem
The problem is to replace, or complement, longterm market arrangements with technologyspecific policies. The challenge is to combine
public and market co-ordinations in order to
maintain financial incentives, while
simultaneously reducing the risks inherent in the
market regime sufficiently so as to ease
investment.
Separate markets for low carbon generation
• Feed-in tariffs
Structured either as fixed payments, premium
payments on top of the electricity price, or
financial contracts for difference against the
market price.
• Establishing a market for clean energy
Imposition of quantity obligations on suppliers
(e.g. renewables obligation in Australia).
Market-wide interventions/reforms
• Carbon price support: the guarantee of a
minimum carbon price in the electricity
market;
• Long-term contracts for all low-carbon
generators: structured as contracts-fordifference against the market price;
• Targeted capacity payments for
flexible/peaking plants; and
• Emission performance standards.
Ultimate option
Central purchaser model: undo the liberalisation
process!
Hot off the press!
Planning consent has been granted for two Areva EPR
units at Hinkley Point C, which would represent the
biggest infrastructure project in the UK since the 1950s.
At 1630 MWe each they would jointly meet 7% of UK
current electricity demand and have a design life of 60
years. Intensive discussions between EdF Energy and the
government are on-going to set a long-term electricity
price, and EdF will not proceed with the project unless
this question is resolved favourably to justify
investment. Newspapers have reported that EdF Energy
is seeking a price of £96-97/MWh over 35-40 years from
2018.
Conclusions
Liberalised electricity markets such as the NEM
have raised the risks faced by investors in highcapital-cost, low-operating-cost generation. In
addition, such market structures may not
encourage low-carbon-technologies. A key question
for governments, therefore, is whether to use
targeted measures to ensure capital cost recovery
for low-carbon investments, or whether to impose
market-based policies such as long-term contractsfor-difference payments that cover selected
generation technologies.