Article, CILA Digest – December 2012
Insurance / Property
In 2011, Scottish & Southern Energy declared its intention to phase-in “a new and transparent” approach to the management of its supply and demand requirements. This approach, “Gross Trading” involves the auction of all of its electricity supply, and the purchase of all of its electricity demand, in the day-ahead market. RGL examines why a Gross Trading model would be used and some of the potential Business Interruption issues.
Scottish and Southern Energy PLC (“SSE”) issued a press release on 11 October 2011 regarding its intention to phase-in “a new and transparent” approach to the management of its supply and demand requirements. This new approach involves the auction of all of its electricity supply, and the purchase of all of its electricity demand, in the day-ahead market. This is commonly referred to as “Gross Trading”.
The purpose of this article is to explain why a UK energy company, such as SSE, may consider adopting a Gross Trading model and to outline some of the potential Business Interruption (“BI”) issues that could arise from doing so.
The current wholesale market structure (known as BETTA) has been in place since 2005. When BETTA was introduced, it was thought that this market structure would make it easier for new firms to enter the market for electricity generation and supply. However, according to a recent parliamentary research paper this has not been the case.
99% of the market is currently served by the Big 6 energy companies (Centrica, EDF, E.ON, RWE npower, Scottish Power and SSE) who are “vertically integrated” meaning they provide both generation and supply services. There is a general perception that the amount of electricity that these companies trade on the day-ahead market only represents the difference between their generation and electricity demand.
The day-ahead market in the UK is small when compared to other European electricity markets. For example, in early 2011 approximately 40GWh was traded each day on the UK day-ahead market with a further 200GWh traded through brokered markets. Whereas in other European energy markets the amounts traded on the day-ahead markets are much greater, such as 500GWh in Germany, and 750GWh on Nordpool. In fact Britain was the only European power market to decrease in size during 2009, which allegedly prompted Alistair Buchanan, the Chief Executive Officer of Ofgem, to say “The UK electricity market is rubbish; we know we’ve got a structural weakness in Britain.”
According to SSE’s October press release, the average daily demand from its customers is approximately 165GWh, thus the phasing in of Gross Trading would have a significant impact on the day-ahead market.
Why change to Gross Trading
In November 2010 Ofgem (the UK energy regulator) commissioned a report into the competition of the UK Energy market. On publication of the report in March 2011, it was strongly suspected that the lack of liquidity in wholesale market was a significant barrier for new entrants. It recommended five action points, including:
“Enhance liquidity to address continued concerns on low electricity wholesale market liquidity and new entry by improving access to wholesale market products for new entrants and independent suppliers and generators.”
A move towards Gross Trading would help satisfy this action point and could explain why SSE has embarked on the process. It is also possible that other vertically integrated suppliers may follow suit.
SSE published a letter in April 2012 confirming that it had started to phase-in Gross Trading in October 2011 and that its actions had increased the liquidity of the day-ahead market from approximately 40GWh per day to approximately 200GWh per day by April 2012.
Potential claim issues
Currently, when generation is impacted by an incident at a vertically integrated energy company, the overall business does not generally suffer a loss of sales to its end customers, assuming there is not a black-out, as the customers will continue to watch TV and turn their lights on as normal (there may be a loss of some ancillary revenue streams such as Frequency Response payments which are made in respect of the ability to increase generation at short notice). Instead, the energy company will suffer an increased cost due to having to buy back the generation shortfall it has suffered via a combination of purchasing from the day-ahead market and forward contracts. It may also have to sell the associated unused fuel and carbon emission certificates.
Energy companies generally undertake two types of trading. The first, “operational trading”, is where generation and customer demand is kept in balance. This involves, for example, buying back any shortfalls in generation and selling off any excess generation.
The other form of trading, “proprietary trading”, is where the traders analyse the wholesale markets and try to spot buying and selling opportunities to make a profit.
Based on our experience of dealing with the Big 6, some of them keep the two types of trading separate and others do not. Notwithstanding that a BI policy would probably not be seeking to cover proprietary trading, in a volatile market it is possible that it could incur large losses. Therefore, it is important to ensure that these trades are excluded in any measurement of an Insured event. However, this can be extremely difficult if the two types of trading are not kept separate and even if they are separate, trading is often undertaken by and between separate legal entities within the same organisation which adds another level of complexity to the process.
In a wholesale energy market that is only being used to balance supply and demand, price spikes are difficult to calculate and attribute to particular incidents unless it is a very significant incident as would be the case with a Nuclear powered station. However, if all generation were to be traded as per the Gross Trading model, a loss of generation would have a more predictable effect on prices.
If a loss is significant the reduction in supply may cause a price spike within the day-ahead market. There is, therefore, a possibility of make up at other locations due to the Insured achieving a greater price for the electricity generated at other sites.
Prior to the incident, the market was willing and able to supply along S1 line. Following an incident, the market supply contracts to S2. Due to the limited supply available generators demand a higher price for electricity i.e. a rise in price from P1 to P2. The analysis required to substantiate the changes in demand and the impact on price is detailed and may call for programming tools to take into account the many variable factors in play.
However, price spikes will generally only be short lived due to the UK’s approximately 10-15% System Margin (i.e. spare generating capacity) together with the four sub-sea interconnectors with the continent.
On the reverse side due to a lack of supply, the cost of meeting customer’s electricity demands are likely to increase. Although the effect of this issue may be less pronounced as the majority of customer demand is likely to be secured using forward contracts.
Potential makeup under Gross Trading
If we use the basic demand economic principles from the above example, following an incident at a generating unit there will be a reduction of the supply of electricity, which will cause the market price to increase. The effect of this will depend on the size of impacted generating unit.
For example, a gas powered combined cycle unit comprised of two gas turbines and one steam turbine can generate approximately 15GWh per day. If we assume that the size of the day-ahead market is approximately 200GWh per day then an outage at such a plant would mean that supply to the market would fall by 7.5%.
Assuming that no other factors affect the market supply, and demand remains constant; we can assume that there will be a price increase.
Due to an increase in the market price, unaffected generators supplying to the day-ahead market will benefit. If the Insured operates other generating units during the interruption period then providing that they supply the day-ahead market, the unaffected generating units will earn more gross profit without altering their generation than they would have but for the incident. Effectively there will be makeup at other plants; the amount of makeup will depend on various factors such as the proportion that the Insured’s generation is of the whole market and the size of the price spike.
The size of the price spike will be impacted by various factors such as the volume of trading and whether the price spike makes it viable for other generating units to begin to generate. Different types of generators have different variable costs associated with generation. For example a hydroelectric plant’s variable costs are significantly lower when compared to an oil fired plant. An increase in price makes the operation of less efficient plants more viable, which in turn reduces the impact of the price spike. Therefore the importance of makeup will vary on a loss-by-loss basis.
In contrast to make-up there are likely to be factors which can exacerbate a loss following an incident, such as the distressed sale of unused “must take” fuel. Again, these will vary on a loss-by-loss basis.
Hopefully this article has highlighted a potentially significant change in the UK energy market and the impact this may have on claims i.e. switching from mainly being an increased cost of working calculation to loss of sales calculation.
As appeared in CILA Digest, December 2012.