- Email: [email protected]
The case for a new capacity mechanism in the UK electricity market—Lessons from Australia and New Zealand
Energy Policy 39 (2011) 5096–5098
Contents lists available at ScienceDirect
Energy Policy journal homepage: www.elsevier.com/locate/enpol
Viewpoint
The case for a new capacity mechanism in the UK electricity market—Lessons from Australia and New Zealand Jamie Carstairs a,n, Ian Pope b a b
Linnfall Consulting, UK Mercados, UK
a r t i c l e i n f o
a b s t r a c t
Article history: Received 24 May 2011 Accepted 2 June 2011 Available online 30 June 2011
The UK Government plans a capacity mechanism to ensure sufficient reserves as the share of intermittent generation increases. This article reviews the use of last resort capacity mechanisms in two other energy-only markets, Australia and New Zealand. The Australian National Electricity Market has infrequent price spikes up to A$12,500 (£7800)/MWh. Option contracts have supported significant investment in peak capacity. The system operator also has an ability to contract reserve up to 9 months before projected shortfalls. Reserve has been contracted on two occasions but never dispatched. The New Zealand electricity market includes a reserve energy scheme which allows the system operator to contract and dispatch reserve capacity. One plant has been contracted under the scheme. The plant is currently offered into the market at NZ$5000 (£2300)/MWh. In both markets there have been concerns that reserve schemes could reduce the frequency of high prices and damage price signals for peak investment. Following a Ministerial review in 2009 the New Zealand scheme is being closed down and the plant is for sale. The Australian scheme is to be closed down in 2013. This experience raises concerns about the possible impact of a new capacity mechanism in Great Britain. & 2011 Elsevier Ltd. All rights reserved.
Keywords: Electricity Market Reform
1. Introduction The Government released its proposals for Electricity Market Reform (EMR) in November 2010. Four measures are discussed: carbon price support, feed-in tariffs for new low carbon generation, an emissions performance standard and a capacity mechanism. This paper considers the possible design of a capacity mechanism. It looks at experience from the Australian market in providing price signals for peak generation; the use of ‘last resort’ reserve contracts in both Australia and New Zealand; and the implications for a capacity mechanism in Great Britain.
2. The need for a capacity mechanism An energy only market rewards capacity through the economic rent realised when prices are above variable operating costs. Peak generation typically has high operating costs and is used infrequently. The returns to peak generation therefore rely on infrequent price spikes. Prices should reflect opportunity cost. When there is sufficient capacity this is the variable operating cost of the marginal plant. n
Corresponding author. Tel: þ44 208 1331751. E-mail addresses: [email protected] (J. Carstairs), [email protected] (I. Pope). 0301-4215/$ - see front matter & 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2011.06.004
As capacity becomes scarce and the risk of outage increases, the opportunity cost is increasingly set by the value of lost load (VOLL). As VOLL is much higher than operating costs, this leads to infrequent price spikes, which provide returns to peak generation. The EMR consultation has raised concerns that this mechanism may be ineffective, stating: ‘‘The modelling suggests that if peak prices can rise to the value of lost load (which we assume to be £10,000/MWh on average) when the system is very tight, then in theory CCGT investors could earn a reasonable return operating at lower load factors. However, there is significant uncertainty surrounding this, increasing risk, and investment may lag as a result.’’1 The modelling considers whether investment will be sufficient to meet a 10% reserve margin. It concludes that forecast generation investment may be insufficient to meet this target and additional capacity may be required. The requirement starts in 2020, peaks at around 5000 MW in 2024 and then declines.2 The Government is proposing a new capacity mechanism to offset this risk. However a mechanism of this kind may further undermine price signals for peak investment. This article looks at 1 Electricity market reform, Analysis of Policy Options, Redpoint in association with Trilemma, December 2010. 2 Electricity Market Reform Consultation Document, Fig. 10 available at http://www.decc.gov.uk/en/content/cms/consultations/emr/emr.aspx
J. Carstairs, I. Pope / Energy Policy 39 (2011) 5096–5098
experience in incentivising peak generation through infrequent price spikes and in using last resort contracting for reserve in two other energy-only markets, Australia and New Zealand.
5097
$ 1,000 $ 900 $ 800 $ 700
3. Price spikes as a capacity signal in the Australian market The Australian National Electricity Market (NEM) provides an example of a much ‘spikier’ market, of the kind that may develop in Great Britain. The NEM is a gross energy-only market with a system marginal price (SMP) established in five regions. Price volatility can be illustrated using the South Australian region.3 Due to favourable wind regimes by December 2010 South Australia had 51% of installed wind capacity in Australia, despite having only 8% of the population. Wind energy was estimated to serve 14% of demand in 2008/20094 and has since risen to 20% of installed capacity.5 There is also volatility in demand due to variable air conditioning load. These factors result in substantial price volatility. During 2010 there were 70 h of negative prices. Prices were above $100/MWh for 78 h and above $1000/MWh for 21 h, with a maximum price of just under $10,000/MWh. The median price was $24/MWh. The average price was $40/MWh. The difference between the two reflected a ‘fat tail’ of high and very high prices. High price periods are rare but their level is so high that they are very material. The top 8 h (or 0.09% of the price periods) accounted for around 22% of the un-weighted sum of half-hourly prices. These were generally periods of high demand so the impact on demand-weighted turnover was greater. As in Great Britain market participants are heavily contracted. As the Australian NEM is a gross pool the contracts are derivatives against the wholesale market price. Option contracts are frequently used to hedge against occasional price spikes. The structure of an option contract is illustrated in Fig. 1. A payment is made for a given level of capacity (in MW). A strike price is agreed. The standard strike price for a base cap (that is, an option to cover all price periods) is $300/MWh in the Australian contract market.6 This represents the approximate variable operating costs of an OCGT, which is typically used to cover this contract. The purchaser pays a fixed annual cost, obtains an option to buy a defined output (in MW) at this strike price, and exercises that option if SMP exceeds the strike price. The seller has an obligation to supply during these high price periods, and typically hedges that obligation by operating an OCGT. Options accounted for 14% of the contract market in 2009/ 2010 and 33% of the contract market in South Australia.7 This form of contract is well suited to peak generation with high capital costs but low operating costs. The higher share of cap contracts in South Australia may reflect the impact of high wind penetration on the need for peak generation. The NEM also allows the system operator8 to contract for reserve under the Reliability and Emergency Reserve Trader scheme (RERT). The NEM has a reliability standard of 0.002%
$ 600 $ 500 $ 400
Option exercised when SMP above strike price
Strike price
$ 300 $ 200 $ 100
Fixed payment per MW for option right
$0 Fig. 1. Illustrative option contract based on January 2010 spot prices in South Australia.
unserved energy. This is converted to required minimum reserve levels (MRL) by region. If there is evidence that the market will not meet the MRL the System Operator can contract for reserves or demand side response up to 9 months in advance. The scheme has been used twice. In both cases reserves were contracted but not dispatched. The contracting of reserve may protect against the risk of outages. It may also increase the risk by affecting the price signals for investment in peak generation. A review of the RERT was completed in April 2011. The review concluded that the RERT is not required to ensure reliable electricity supply. The scheme which currently runs to 2012 is to be extended for one year to manage transitional arrangements and shut down in June 2013.9
4. New Zealand’s ‘last resort’ capacity mechanism New Zealand also has an energy-only market, with prices determined at 220 nodes. New Zealand has significant hydro generation and limited storage. This reduces short term price volatility, in comparison with the Australian NEM, but creates a risk of reserve shortages during dry years. The reserve energy scheme in New Zealand was put in place after shortages due to low inflows during 2001 and 2003. It enables the Electricity Commission to contract for reserve generation and demand response. The only reserve plant contracted under the scheme is Whirinaki, a 155 MW diesel plant. The plant was commissioned in 2004. It is owned by the Ministry of Economic Development and operated by Contact Energy.10 The plant is bid into the market in accordance with offer instructions that provide transparency to other market participants. Under the original offer instructions Whirinaki was bid into the market as follows:
When the security was normal (and the risk of either fuel or 3
Current and historic half-hourly spot market price data is available by region from the Australian Energy Market Organisation, at http://www.aemo.com.au/ data/price_demand.html Data analysis was undertaken by the authors. 4 Government of South Australia, Renewable Energy in South Australia, available at http://www.climatechange.sa.gov.au/index.php?page=renewableenergy-in-sa 5 Australian Energy Market Commission (AEMC) Strategic Priorities for Energy Market Development available at www.aemc.gov.au. 6 D-Cypha Trade price data, available at http://d-cyphatrade.com.au/market_ options#A. 7 The Australian Financial Markets Association provides an annual report giving data on contract volumes available at http://www.amfa.com.au. 8 Currently the Australian Energy Market Operator (AEMO) and previously the National Electricity Market Management Company (NEMMCO).
hydro shortage was low) the plant was bid in at $1000/MWh. When high prices were forecast for the next 8 trading periods this offer was reduced to $387/MWh. During a ‘security watch’ phase (when there is a 1–4% risk of energy shortage) Whirinaki was bid into the market at
9 AEMC, Review of the Reliability and Emergency Reserve Trader, Final Report April 2011 http://www.aemc.gov.au/Market-Reviews/Completed/Review-of-andEmergency-Reserve-Trader-RERT.html. 10 A general description of the scheme is available in the preliminary report to the Ministerial Review of Electricity Market Performance, at http://www.med. govt.nz/templates/StandardSummary____41689.aspx.
5098
J. Carstairs, I. Pope / Energy Policy 39 (2011) 5096–5098
$387/MWh, in line with its variable operating costs. When the risk of energy shortage exceeded 4% it could be bid in at lower prices. In response to concerns about the possible dampening of peak price signals, this offer strategy was increased to $5000/MWh, regardless of price forecasts, in March 2010.11
The fixed costs of the scheme are recovered by a consumer levy. The intentions of this reserve energy scheme appear consistent with one option for the Capacity Mechanism set out in the EMR. A Ministerial Review in 2009 stated: ‘‘The concept was that reserve energy would not normally operate in the market and would not distort investment intentions or operating decisions of participants, but would be available as a last resort.’’12 Despite this intention, reserve energy under arrangements of this kind must have a dampening effect on spot market prices. The only exception to this is if the plant is never used and its offer price always remains above the spot market price. In all other cases, returns to other peak capacity will be lower than they would in the absence of the reserve energy. The Ministerial Review identified three problems with the Reserve Energy Scheme. First, it created a moral hazard—market participants anticipated that the Electricity Commission would manage future supply risks. There was also likely to be lobbying for the Electricity Commission to take action, with the most active lobbying by suppliers who had failed to manage their own supply risk. Second, the offer price when the risk of energy shortage was material was too low. It reflected the costs of supply, rather than the opportunity costs of the energy. And thirdly, the fixed costs of the scheme were smeared across all market participants regardless of the actions they had taken – through their own investment or demand side agreements – to manage supply risk. The Ministerial Review recommended that the reserve scheme be shut down and the plant be sold. This recommendation was accepted and the sale announced in December 2010.13
11 A description of the offer strategy up to February 2010 and the revised offer strategy is available on the Electricity Authority (previously Commission) website at http://www.google.co.uk/#hl=en&xhr=t&q=changeþ toþwhirinaki&cp=19&pf=p& sclient=psy&rlz=1R2SUNC_enGB416&aq=f&aqi=&aql=&oq=changeþtoþ whirinaki& pbx=1&fp=b47e5f98a01423ac. 12 Ministerial Review, page 13 Sale details are on the Government of New Zealand website at http://www. beehive.govt.nz/release/whirinaki-plant-be-sold.
5. Implications for design of a capacity mechanism in the market in Great Britain The Australian market indicates that investment in peak capacity (that is, capacity with low capital and high operating costs, suitable for meeting peak load) can be made against infrequent, high price spikes, with those investments mediated by the contract market. The South Australian market in particular indicates that minimum reserve levels can be achieved despite high penetration of wind generation. The market in Great Britain is currently very different from the market in South Australia. In the UK as a whole, wind, hydro and other renewables accounted for 7% of total generation in 2010 and wind alone for a little over 3% of total electricity generation. Demand volatility is lower, with a greater reliance on gas for heating compared to use of electricity for cooling in South Australia. Price volatility in the balancing mechanism is much lower. This is graphically illustrated by the share of the top 8 h. During 2010 these accounted for 0.6% and 0.7% of the un-weighted sum of system sell and system buy prices. This compares with 22% in South Australia. One reason for this may be the comfortable reserve margins at present. However there may also be obstacles to any future tightening of reserve margins being fully reflected in prices. Ofgem stated in Project Discovery.14 ‘‘In electricity, the problem is primarily caused by the fact that certain balancing actions undertaken by the system operator can be mispriced.’’ Our conclusion is that energy-only markets can deliver sufficient capacity provided the market design delivers appropriate price signals. The optimal approach in Great Britain would be to address the factors which are constraining price signals. The introduction of a targeted last resort mechanism is likely to further weaken price signals for peak generation and runs the risk of an increasing reliance on central procurement rather than market signals. The recent decision to close down ‘last resort’ schemes in Australia and New Zealand indicates that this risk may be material.
14 Ofgem, Project Discovery Consultation Document, February 2010, available at http://www.ofgem.gov.uk/MARKETS/WHLMKTS/DISCOVERY/Documents1/Project_ Discovery_FebConDoc_FINAL.pdf.
Contents lists available at ScienceDirect
Energy Policy journal homepage: www.elsevier.com/locate/enpol
Viewpoint
The case for a new capacity mechanism in the UK electricity market—Lessons from Australia and New Zealand Jamie Carstairs a,n, Ian Pope b a b
Linnfall Consulting, UK Mercados, UK
a r t i c l e i n f o
a b s t r a c t
Article history: Received 24 May 2011 Accepted 2 June 2011 Available online 30 June 2011
The UK Government plans a capacity mechanism to ensure sufficient reserves as the share of intermittent generation increases. This article reviews the use of last resort capacity mechanisms in two other energy-only markets, Australia and New Zealand. The Australian National Electricity Market has infrequent price spikes up to A$12,500 (£7800)/MWh. Option contracts have supported significant investment in peak capacity. The system operator also has an ability to contract reserve up to 9 months before projected shortfalls. Reserve has been contracted on two occasions but never dispatched. The New Zealand electricity market includes a reserve energy scheme which allows the system operator to contract and dispatch reserve capacity. One plant has been contracted under the scheme. The plant is currently offered into the market at NZ$5000 (£2300)/MWh. In both markets there have been concerns that reserve schemes could reduce the frequency of high prices and damage price signals for peak investment. Following a Ministerial review in 2009 the New Zealand scheme is being closed down and the plant is for sale. The Australian scheme is to be closed down in 2013. This experience raises concerns about the possible impact of a new capacity mechanism in Great Britain. & 2011 Elsevier Ltd. All rights reserved.
Keywords: Electricity Market Reform
1. Introduction The Government released its proposals for Electricity Market Reform (EMR) in November 2010. Four measures are discussed: carbon price support, feed-in tariffs for new low carbon generation, an emissions performance standard and a capacity mechanism. This paper considers the possible design of a capacity mechanism. It looks at experience from the Australian market in providing price signals for peak generation; the use of ‘last resort’ reserve contracts in both Australia and New Zealand; and the implications for a capacity mechanism in Great Britain.
2. The need for a capacity mechanism An energy only market rewards capacity through the economic rent realised when prices are above variable operating costs. Peak generation typically has high operating costs and is used infrequently. The returns to peak generation therefore rely on infrequent price spikes. Prices should reflect opportunity cost. When there is sufficient capacity this is the variable operating cost of the marginal plant. n
Corresponding author. Tel: þ44 208 1331751. E-mail addresses: [email protected] (J. Carstairs), [email protected] (I. Pope). 0301-4215/$ - see front matter & 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2011.06.004
As capacity becomes scarce and the risk of outage increases, the opportunity cost is increasingly set by the value of lost load (VOLL). As VOLL is much higher than operating costs, this leads to infrequent price spikes, which provide returns to peak generation. The EMR consultation has raised concerns that this mechanism may be ineffective, stating: ‘‘The modelling suggests that if peak prices can rise to the value of lost load (which we assume to be £10,000/MWh on average) when the system is very tight, then in theory CCGT investors could earn a reasonable return operating at lower load factors. However, there is significant uncertainty surrounding this, increasing risk, and investment may lag as a result.’’1 The modelling considers whether investment will be sufficient to meet a 10% reserve margin. It concludes that forecast generation investment may be insufficient to meet this target and additional capacity may be required. The requirement starts in 2020, peaks at around 5000 MW in 2024 and then declines.2 The Government is proposing a new capacity mechanism to offset this risk. However a mechanism of this kind may further undermine price signals for peak investment. This article looks at 1 Electricity market reform, Analysis of Policy Options, Redpoint in association with Trilemma, December 2010. 2 Electricity Market Reform Consultation Document, Fig. 10 available at http://www.decc.gov.uk/en/content/cms/consultations/emr/emr.aspx
J. Carstairs, I. Pope / Energy Policy 39 (2011) 5096–5098
experience in incentivising peak generation through infrequent price spikes and in using last resort contracting for reserve in two other energy-only markets, Australia and New Zealand.
5097
$ 1,000 $ 900 $ 800 $ 700
3. Price spikes as a capacity signal in the Australian market The Australian National Electricity Market (NEM) provides an example of a much ‘spikier’ market, of the kind that may develop in Great Britain. The NEM is a gross energy-only market with a system marginal price (SMP) established in five regions. Price volatility can be illustrated using the South Australian region.3 Due to favourable wind regimes by December 2010 South Australia had 51% of installed wind capacity in Australia, despite having only 8% of the population. Wind energy was estimated to serve 14% of demand in 2008/20094 and has since risen to 20% of installed capacity.5 There is also volatility in demand due to variable air conditioning load. These factors result in substantial price volatility. During 2010 there were 70 h of negative prices. Prices were above $100/MWh for 78 h and above $1000/MWh for 21 h, with a maximum price of just under $10,000/MWh. The median price was $24/MWh. The average price was $40/MWh. The difference between the two reflected a ‘fat tail’ of high and very high prices. High price periods are rare but their level is so high that they are very material. The top 8 h (or 0.09% of the price periods) accounted for around 22% of the un-weighted sum of half-hourly prices. These were generally periods of high demand so the impact on demand-weighted turnover was greater. As in Great Britain market participants are heavily contracted. As the Australian NEM is a gross pool the contracts are derivatives against the wholesale market price. Option contracts are frequently used to hedge against occasional price spikes. The structure of an option contract is illustrated in Fig. 1. A payment is made for a given level of capacity (in MW). A strike price is agreed. The standard strike price for a base cap (that is, an option to cover all price periods) is $300/MWh in the Australian contract market.6 This represents the approximate variable operating costs of an OCGT, which is typically used to cover this contract. The purchaser pays a fixed annual cost, obtains an option to buy a defined output (in MW) at this strike price, and exercises that option if SMP exceeds the strike price. The seller has an obligation to supply during these high price periods, and typically hedges that obligation by operating an OCGT. Options accounted for 14% of the contract market in 2009/ 2010 and 33% of the contract market in South Australia.7 This form of contract is well suited to peak generation with high capital costs but low operating costs. The higher share of cap contracts in South Australia may reflect the impact of high wind penetration on the need for peak generation. The NEM also allows the system operator8 to contract for reserve under the Reliability and Emergency Reserve Trader scheme (RERT). The NEM has a reliability standard of 0.002%
$ 600 $ 500 $ 400
Option exercised when SMP above strike price
Strike price
$ 300 $ 200 $ 100
Fixed payment per MW for option right
$0 Fig. 1. Illustrative option contract based on January 2010 spot prices in South Australia.
unserved energy. This is converted to required minimum reserve levels (MRL) by region. If there is evidence that the market will not meet the MRL the System Operator can contract for reserves or demand side response up to 9 months in advance. The scheme has been used twice. In both cases reserves were contracted but not dispatched. The contracting of reserve may protect against the risk of outages. It may also increase the risk by affecting the price signals for investment in peak generation. A review of the RERT was completed in April 2011. The review concluded that the RERT is not required to ensure reliable electricity supply. The scheme which currently runs to 2012 is to be extended for one year to manage transitional arrangements and shut down in June 2013.9
4. New Zealand’s ‘last resort’ capacity mechanism New Zealand also has an energy-only market, with prices determined at 220 nodes. New Zealand has significant hydro generation and limited storage. This reduces short term price volatility, in comparison with the Australian NEM, but creates a risk of reserve shortages during dry years. The reserve energy scheme in New Zealand was put in place after shortages due to low inflows during 2001 and 2003. It enables the Electricity Commission to contract for reserve generation and demand response. The only reserve plant contracted under the scheme is Whirinaki, a 155 MW diesel plant. The plant was commissioned in 2004. It is owned by the Ministry of Economic Development and operated by Contact Energy.10 The plant is bid into the market in accordance with offer instructions that provide transparency to other market participants. Under the original offer instructions Whirinaki was bid into the market as follows:
When the security was normal (and the risk of either fuel or 3
Current and historic half-hourly spot market price data is available by region from the Australian Energy Market Organisation, at http://www.aemo.com.au/ data/price_demand.html Data analysis was undertaken by the authors. 4 Government of South Australia, Renewable Energy in South Australia, available at http://www.climatechange.sa.gov.au/index.php?page=renewableenergy-in-sa 5 Australian Energy Market Commission (AEMC) Strategic Priorities for Energy Market Development available at www.aemc.gov.au. 6 D-Cypha Trade price data, available at http://d-cyphatrade.com.au/market_ options#A. 7 The Australian Financial Markets Association provides an annual report giving data on contract volumes available at http://www.amfa.com.au. 8 Currently the Australian Energy Market Operator (AEMO) and previously the National Electricity Market Management Company (NEMMCO).
hydro shortage was low) the plant was bid in at $1000/MWh. When high prices were forecast for the next 8 trading periods this offer was reduced to $387/MWh. During a ‘security watch’ phase (when there is a 1–4% risk of energy shortage) Whirinaki was bid into the market at
9 AEMC, Review of the Reliability and Emergency Reserve Trader, Final Report April 2011 http://www.aemc.gov.au/Market-Reviews/Completed/Review-of-andEmergency-Reserve-Trader-RERT.html. 10 A general description of the scheme is available in the preliminary report to the Ministerial Review of Electricity Market Performance, at http://www.med. govt.nz/templates/StandardSummary____41689.aspx.
5098
J. Carstairs, I. Pope / Energy Policy 39 (2011) 5096–5098
$387/MWh, in line with its variable operating costs. When the risk of energy shortage exceeded 4% it could be bid in at lower prices. In response to concerns about the possible dampening of peak price signals, this offer strategy was increased to $5000/MWh, regardless of price forecasts, in March 2010.11
The fixed costs of the scheme are recovered by a consumer levy. The intentions of this reserve energy scheme appear consistent with one option for the Capacity Mechanism set out in the EMR. A Ministerial Review in 2009 stated: ‘‘The concept was that reserve energy would not normally operate in the market and would not distort investment intentions or operating decisions of participants, but would be available as a last resort.’’12 Despite this intention, reserve energy under arrangements of this kind must have a dampening effect on spot market prices. The only exception to this is if the plant is never used and its offer price always remains above the spot market price. In all other cases, returns to other peak capacity will be lower than they would in the absence of the reserve energy. The Ministerial Review identified three problems with the Reserve Energy Scheme. First, it created a moral hazard—market participants anticipated that the Electricity Commission would manage future supply risks. There was also likely to be lobbying for the Electricity Commission to take action, with the most active lobbying by suppliers who had failed to manage their own supply risk. Second, the offer price when the risk of energy shortage was material was too low. It reflected the costs of supply, rather than the opportunity costs of the energy. And thirdly, the fixed costs of the scheme were smeared across all market participants regardless of the actions they had taken – through their own investment or demand side agreements – to manage supply risk. The Ministerial Review recommended that the reserve scheme be shut down and the plant be sold. This recommendation was accepted and the sale announced in December 2010.13
11 A description of the offer strategy up to February 2010 and the revised offer strategy is available on the Electricity Authority (previously Commission) website at http://www.google.co.uk/#hl=en&xhr=t&q=changeþ toþwhirinaki&cp=19&pf=p& sclient=psy&rlz=1R2SUNC_enGB416&aq=f&aqi=&aql=&oq=changeþtoþ whirinaki& pbx=1&fp=b47e5f98a01423ac. 12 Ministerial Review, page 13 Sale details are on the Government of New Zealand website at http://www. beehive.govt.nz/release/whirinaki-plant-be-sold.
5. Implications for design of a capacity mechanism in the market in Great Britain The Australian market indicates that investment in peak capacity (that is, capacity with low capital and high operating costs, suitable for meeting peak load) can be made against infrequent, high price spikes, with those investments mediated by the contract market. The South Australian market in particular indicates that minimum reserve levels can be achieved despite high penetration of wind generation. The market in Great Britain is currently very different from the market in South Australia. In the UK as a whole, wind, hydro and other renewables accounted for 7% of total generation in 2010 and wind alone for a little over 3% of total electricity generation. Demand volatility is lower, with a greater reliance on gas for heating compared to use of electricity for cooling in South Australia. Price volatility in the balancing mechanism is much lower. This is graphically illustrated by the share of the top 8 h. During 2010 these accounted for 0.6% and 0.7% of the un-weighted sum of system sell and system buy prices. This compares with 22% in South Australia. One reason for this may be the comfortable reserve margins at present. However there may also be obstacles to any future tightening of reserve margins being fully reflected in prices. Ofgem stated in Project Discovery.14 ‘‘In electricity, the problem is primarily caused by the fact that certain balancing actions undertaken by the system operator can be mispriced.’’ Our conclusion is that energy-only markets can deliver sufficient capacity provided the market design delivers appropriate price signals. The optimal approach in Great Britain would be to address the factors which are constraining price signals. The introduction of a targeted last resort mechanism is likely to further weaken price signals for peak generation and runs the risk of an increasing reliance on central procurement rather than market signals. The recent decision to close down ‘last resort’ schemes in Australia and New Zealand indicates that this risk may be material.
14 Ofgem, Project Discovery Consultation Document, February 2010, available at http://www.ofgem.gov.uk/MARKETS/WHLMKTS/DISCOVERY/Documents1/Project_ Discovery_FebConDoc_FINAL.pdf.