Energy and Climate Change Committee - Draft Energy Bill: Pre-legislitive ScrutinyWritten evidence submitted by Barrie Murray
1. Overall Approach
The current status of the proposals in the draft bill includes too much uncertainty and would not enable a potential investor to undertake an analysis of any development proposals. The degree of market intervention embodied within the EMR proposal represents a half way house between a fully competitive market and a centralised single buyer model. The Single Buyer model works very effectively in a number of countries with a central agency purchasing the energy and capacity requirements of all consumers and could work in the UK. Otherwise the mechanisms adopted need to be designed to work in parallel with normal market arrangements and be entirely transparent to facilitate independent new entry.
2. Clarifications
Some of the issues that need to be clarified include:
The capacity mechanism is described as optional and may or not be invoked. The basis for this decision is not defined.
The question as to how the viability of peaking plant will be maintained given the reduction in its utilisation as a result of wind energy is not addressed.
The level of the FIT has yet to be defined and more importantly how it will be established.
There is no discussion as to how future plant requirements will be determined taking account of the different operating regimes required.
The report claims that consumer costs will be lower with the EMR but there is little evidence to substantiate this claim or detail of the modelling approach used.
3. Capacity Mechanism
A capacity mechanism will facilitate new entry by contract but this is likely to deter independent new entry. There will also be concern that market arrangements may change with successive governments. One option is to establish a premium to energy prices based on the prospective plant margin for the four years ahead with costs based on the value attributed to lost load. The mechanism would be self correcting and each market participant could establish their own assessment of likely future conditions. It would also mirror the normal market mechanism where scarcity drives up prices encouraging new entry. The capacity credits could be made technology specific to encourage the development of the optimum plant mix with payments linked to the annual loss of load probability and an assumed value of lost load. The target plant margin would be set to contain capacity shortfalls to typically eight hours a year based on expected plant availability.
4. Peaking Capacity
To establish a practical mixture of base load and peaking capacity the mechanism also needs to recognise that the peaking plant utilisation will be very low with energy displaced by wind energy. The capacity is still required to meet demand on days with little wind output. In a normal market the tight margin at the time of peak would drive up spot prices but this would not compensate for the loss of energy revenue. To reflect this, the energy price premium should be inversely linked to the plant utilisation. By this process base load generation would get a small premium as it would cover its fixed cost through a small increment to normal energy prices. Peaking plant would receive most payment with its premium designed to be higher to recover its fixed costs from fewer generated units. This reflects the normal market approach to determining bid prices to recover costs. It also needs to be recognised that part load operation and regulation have a significant impact on operating costs and this needs to be reflected in the premium. The energy premium would adjust in relation to the expected plant margin.
5. FIT/CfD
The FIT needs to be set to make investments viable taking account of the risks. A fundamental problem with wind generation is the predictability of the wind load factor that has a major impact on the revenues likely to be earned and will vary significantly between farm locations. The mechanism should encourage developments at the windiest sites first. Currently investors take a very conservative view of the prospective load factor using a 90% probability that the value will be exceeded. This risk could be managed by including a prospective load factor in the contract terms. The level of FIT should adjust as the target requirements are met in the same manner as the current ROC mechanism.
6. Optimal Plant Mix
There will be an optimum mixture of generation to meet the varying customer demand profile at minimum cost with a proportion of base load, mid merit and peaking plant. These will have different cost characteristics with base load tending to have high capital but low operating costs like nuclear and peaking plant having low capital costs but higher running costs reflecting its lower utilisation. The capacity contracting arrangement needs to be designed to foster the optimum mix. The Bill proposals recognise the need for peaking plant like open cycle gas turbines but do not provide a basis for it to be seen as a viable investment. The arrangement described in paragraph 4 with a premium to energy prices inversely related to utilisation would go some way to meeting this requirement. It would also compensate mid merit plant that will also see a reduction in utilisation as wind capacity increases. The volume of base load generation like nuclear should be related to the minimum demand level and technology specific contracting should recognise this. The overall capacity level would be contained by reducing premiums as capacity reaches the target level.
Very sophisticated generation expansion models have been established and used by state utilities for many years and National Grid, in its role as advisor to the government, should be encouraged to exploit this type of modelling.
7. Economic assessment & Modelling Results
It is suggested that overall customer bills would in the long term be less than they would without the EMR proposals. This claim needs to be substantiated given that off-shore wind costs with subsidies around £150/MWh whereas combined cycle gas based on DECC fuel price projections and high CO2 prices of £70/t would only reach £80/MWh (less than £70/MWh with CO2 at £30/t). The suggestion that wholesale prices will be less as a result of low carbon generation with a low SRMC is suspect. Marginal prices are likely to be set by expensive peaking generation.
The financial modelling undertaken and reported is inadequate in not describing a range of scenarios and sensitivities with more detail of the process used to simulate the market operation. The modelling process needs to embrace a number of features to fully assess the impact of wind intermittency on system operation and conventional generation. In particular it should describe:
The modelling approach to identifying the timing and type of generation new entry.
A full chronological model using actual wind data output profiles in conjunction with a real half-hourly system demand profile to simulate system operation for a year and provide adequate granularity.
The range of assumptions about how it is proposed to balance wind intermittency using a combination of peaking plant, pumped storage and demand side response.
The future role of the increased capacity of interconnection and exchanges with Europe and Ireland.
The approach to assessing the impact of the wind intermittency on the operating costs of conventional generation.
The assumptions about demand side participation and embedded generation.
The details of the modelling approach need to be available to all potential participants to enable them to make their own judgements about future market conditions. This is essential to creating investor confidence and enabling other stakeholders to challenge assumptions.
June 2012