|Issue number: 95||
Following on from a recent MZINE article on the new gas generation strategy, this month we will look at the related issue of Electricity Market Reform and whether it can truly provide a stable future for low-carbon energy. With the debates on nuclear energy almost always at fever pitch, this article will also examine the current issues over EDF’s proposed nuclear facility at Hinkley Point and the role that nuclear power can and might play as part of a low-carbon future.
In late November last year, after repeated delays, the Energy Bill was introduced to Parliament. This has taken forward the Electricity Market Reform (EMR) process that has been on-going since 2010 and will seek to entrench into primary legislation the tools that are required to deliver the Government’s objectives of decarbonising generation, ensuring security of supply and ensuring affordability for consumers.
The Government has stated that Electricity Market Reform ‘represents the biggest change to the electricity market since privatisation. It will transform the UK’s electricity sector, while working with the market and encouraging competition. The main elements of EMR are Contracts for Difference (CfDs) and Capacity Market (CM). These mechanisms aim to guarantee investment in low carbon electricity as an attractive prospect, through stable and predictable incentives, ensuring that the UK electricity sector will deliver a secure, affordable supply to consumers.
Contracts for Difference
The basic principle of CfDs is that investors are not exposed, in the long term, to electricity price volatility. The generator will receive a fixed price for the electricity known as the strike price, which will provide stable returns on the project. The generators will receive revenue from selling their electricity into the market as usual, however, when the market price is below the strike price they will receive a top-up payment from the suppliers. If the market price is above the strike price, the generator must pay back the difference.
As can be seen from the illustration above, this creates a situation highly beneficial to the generator as it is not subject to a volatile electricity price. It allows the generator to set a price, based on an internal rate of return (IRR) which ensures they receive a stable price for their electricity.
This price will allow the generator to cover the costs of the project over its lifetime whilst also providing an incentive or reward for the high amount of capital they will need to initially invest. This method seems likely to ensure investment, as providing any prospective generators do their sums correctly, they can enter the projects in the knowledge that they will come out with a profit. Initially, it appears that there is no cost to the taxpayer. However, where the market price of electricity is below the strike price, the generator will receive a top-up payment from the supplier which will ultimately mean the consumer. Therefore, it becomes clear that there is always some risk to the consumer.
Future electricity prices are notoriously hard to predict, as are future developments in the industry. On the one hand, long contracts locked in at a certain price, ideally across a range of low carbon technologies will hopefully mean a security of supply that is not subject to other factors and can act as a protection against high prices. On the other hand, there is the possibility of being locked into long term contracts, potentially as long as 40 years in the case of nuclear power, which are far higher than the market price and other technologies.
The current on-going negotiations between EDF and the Government over the nuclear power station at Hinkley Point C provide no better example of the fine line that must be walked when negotiating the IRR, and perhaps more importantly, the strike price. The higher the strike price, the higher the liability the consumer must bear. However, if the Government demands, currently reported as represented by the treasury, are too low, then EDF could walk away. In fact, alongside fears over project costs and construction delays, Centrica CEO Sam Laidlaw also stated ‘the lengthening time frame for a return on the capital invested on a project of this scale’ as a reason for Centrica’s withdrawal, which perhaps suggests that amongst other things the prospective strike price was too low.
Exactly what represents a good deal for the consumer is somewhat of an exercise in futility, especially when one considers that it is probably not entirely fair to directly compare the prospective price of nuclear with its higher carbon counterparts. Nonetheless, the graph below plots three different, DECC calculated electricity price scenarios, alongside potential strike prices, starting at 2020, the earliest likely start up for Hinkley Point C. The potential strike prices are 8, 9 and 10 p/KWh (equal to £80, £90 and £100 per MWh) respectively, with the lower figure said to be preferred by the Treasury, whilst the EDF are said to have started negotiations above the higher figure. This article can only speculate on what figure will eventually be agreed but suggests given EDF’s better negotiating position due to the lack of competition and the UK’s tight capacity projections the figure may be between 9 and 9.5p/KWh. In such an event, the graph below shows the potential cost to the consumer. Even at 9p, a figure that may well be lower than that eventually agreed, only the highest electricity price scenario exceeds the strike price. In the event of low electricity prices, perhaps predicated by an abundance of shale gas entering the market, the difference becomes larger.
As stated above, with the UK currently planning to continue its commitment to reducing emissions, nuclear power, as a form of low carbon electricity generation cannot be directly compared to gas and coal generation as in some senses it forms a separate part of that market. Presently, nuclear is far superior to the likes of wind and solar in price, reliability and generation quantities. For example, offshore wind energy currently has a strike price of £140 per MWh and unlike nuclear is subject to weather conditions. Carbon Capture Storage presents a unique ‘low carbon’ opportunity that could take advantage of cheap coal or gas, but doubts remain about its commercial viability making it an unrealistic alternative to nuclear. Despite nuclear power’s low emissions it does create a separate environmental uneasiness which the country would rather avoid. Unfortunately, avoidance of one pitfall often leads to another, either in the form of higher carbon emissions, higher energy bills or even the lights going out.
Despite projections that the levelised cost of energy (LCOE) for offshore wind (sum of discounted generation costs (£) divided by the sum of discounted lifetime electricity output (MWh)) could fall below £100/MWh wind energy cannot yet emulate the reliability of nuclear power which makes the latter, as a low carbon option fairly strong.
The question is, how long will this be the case and what does the future hold for nuclear power. Interestingly, whilst this author suggests the CfDs appear to create an atmosphere ripe for investment, the absence of investment, from a number of potential companies, must be noted. Furthermore, with the Government planning 16GW of new nuclear by 2030, this is certainly a worry. Especially when one considers that all bar one of its 16 reactors in the current fleet, which total 10GW, are scheduled to be decommissioned by the mid 2020s.
The price certainly appears high for nuclear at present, but in the absence of such a reliable source of low carbon generation, it is an option the Government is likely going to be forced to make. It is also worth pointing out the wider ramifications a deal or non-deal could have. In the case of the former, it will likely set a precedent, for better or for worse, for later stations. In the more unlikely case of the latter, the future of nuclear power in the UK, or at the very least privately funded nuclear power, could be in danger, a result that would likely come at the cost of higher carbon emissions or less reliable renewables.
In order to guarantee security of supply, the Government is introducing the Capacity Market to ensure there is enough capacity in place to meet demand. In addition to its use as a method of assuring energy security where low carbon technology with intermittent or inflexible characteristics are deployed or even in the case of eroded capacity margins, it is also seen as the ‘primary market intervention that will support the construction of new build gas generation in the UK. The main aim of the Capacity Market is to establish a forecast of future demand and capacity and then where extra capacity is needed to ensure security of supply, auction it through a competitive central auction. It has stated that it may well run its first capacity auction in 2014, with delivery aimed for 2018/2019.
Previously, the liberalised electricity market has been trusted to run itself, regulated independently, and guard against tight capacity. By its own admission, the introduction of this mechanism shows that the Government feels there is sufficient risk of market failure. The winning bidder will be paid a high price for providing electricity at the right time, although will also pay a penalty if it fails to deliver. In its own words the ‘The Capacity Market provides an ‘insurance policy’ against a tight future electricity generation market resulting in higher levels of blackouts. In fact, the ‘premium’ is estimated to cost around an extra £14 on bills, a cost borne by the suppliers, and so ultimately the consumer. The actual effects of CM could be fairly small. In fact, there is a danger that it is more likely to be used as a political tool to reassure the public than a mechanism that will encourage new capacity build. Existing plants, or electricity users who wish to lower their demand may well provide the capacity needed but it seems unlikely that the capacity agreements will provide assurance or financial feasibility to potential projects.
Carbon Price Floor
As described in the policy overview, the Carbon Price Floor (CPF) ‘will provide clear economic signals to move away from high carbon technologies, by increasing the price paid for emitting carbon dioxide. As the EU Emission Trading Scheme (ETS) has seen the cost of carbon fall dramatically following the 2009 crash the Government introduced the CPF, effectively as a top-up, to provide an incentive for the use of low-carbon generation. The current price, as launched at the beginning of this month was £16 per tonne of carbon dioxide (£/tCO2), with the price set to increase to £30 in 2020 and up to £70 by 2030. One calculation suggests that should the ETS remain at £4/tCO2 the Treasury stands to gain over £4 billion in the next three years, money that is expected to go into the general coffers. The increase in cost of carbon intensive fuels is likely to make renewables more competitive, although this policy should be seen for what it is, which is a tax that according to the Institute of Public Policy Research (IPPR) will push the wholesale price of electricity up by 17% in the next three years and the Treasury has admitted could push 10,000 to 20,000 households into fuel poverty.
There is no doubt that the Government’s ambition in the EMR to provide a ‘framework to incentivise private investors to deliver an orderly transition to decarbonisation of the power sector, at a price tag which is palatable for consumers is certainly admirable. Whether the long awaited Energy bill can provide this is another matter. In its attempt to cover all bases it has created some confusion. In order to provide a diverse supply that allows for the possibility of cheap, flexible gas as well as decarbonisation it appears to be creating exactly what it is legislating to avoid, uncertainty. By sending out mixed messages and contradictory policies the Government appears to be facing a difficult task in reaching all three goals, and a poor deal with EDF could ensure security of supply - but at a cost.
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