Select Committee on Innovation, Universities, Science and Skills Written Evidence

Memorandum 40

Submission from Sustainable Development Commission

  The Science and Technology Select Committee (STSC) in conducting a wide-ranging inquiry on Renewable Energy-Generation Technologies. This is the Sustainable Development Commission's (SDC) response to the call for evidence.

  We have focussed on two renewable technologies (wind and tidal) and on the role of intelligent grid management in supporting the development of renewable technologies. This draws on our previous work on wind energy[119] and our current work on the role of Ofgem,[120] and on tidal power,[121] both due to be published in autumn 2007.


  Onshore wind is the most commercialised renewable technology today. It is one of the more competitive renewable generating technologies and as such has been the technology most supported by the Renewables Obligation (RO).

  The connection of offshore wind projects represents the next stage of UK renewables deployment with projects starting in Robin Rigg (180MW), Lynn (90MW), Inner Dowsing (90MW), and Gunfleet Sands (180MW) all of which are being supported by the Offshore Wind Demonstration Programme.

Deployment and timescales

  There is currently around 2GW of wind generation connected to the UK's electricity generating system, with a further 1,260MW of renewables under construction; there is also 4,600MW with consent and 11,4000 MW in the planning process.[122]

  The main barrier to further deployment is the multiple delays in granting planning permission for both individual wind development projects and for the transmission and distribution infrastructure required to connect renewable generators to the energy system.

  The grid infrastructure in the North of England and Scotland is currently congested with little spare capacity for the connection of new projects. Under the current Security and Quality of Supply Standards (SQSS) the capacity of all generating stations cannot exceed the capacity of the grid infrastructure. This means that the capacity of the network needs to be increased before new projects can connect.

  The upgrade of the Beauly-Denny line to 400kV would increase the capacity of the network in Scotland by around 6GW and would allow for the connection of 67 new renewable projects. However the upgrade of the line will have an impact on visual amenity in areas of Scotland and as a result is currently subject to public inquiry, which could delay construction until 2012. It may also be subject to under-grounding requirements.

  An influx of renewable applications prior to the introduction of the British Electricity Transmission and Trading Arrangements (BETTA) along with existing capacity constraints has lead to a queue of projects (known as the GB or BETTA queue) awaiting connection to the transmission and distribution system in Scotland. This queue is managed on a first-come first-served basis which has led to a situation where some of the projects at the front of the queue which do not have planning consent or appropriate financial backing are delaying the connection dates for other projects which are more likely to go ahead. One alternative approach would be to move to a "connect then manage" approach, which would see renewable generation connected so that the capacity of the grid was exceeded, but accounted for by a reduction in the generating output of fossil fuelled plant.

  These challenges apply to both onshore and offshore wind. However, for offshore wind the absence of a firm offshore regulatory framework adds additional risk. At present there is no agreed framework for how offshore wind should connect to the transmission system and how the commercial relationship between projects and grid operators should work. Government and Ofgem have recently agreed part of the offshore regulatory regime, and this will allow the construction of offshore lines to be open to competitive tendering between transmission companies and other interested parties. This is important progress in finalising the offshore regulatory regime by 2008. However, the process so far has been characterised by decision-making delays in the Department for Business, Enterprise and Regulatory Reform (formerly Department for Trade and Industry) which need to be avoided in future if the 2008 deadline is to be met.


  In our 2005 report on wind power, we estimated that the generation costs of onshore wind power to be around 3.2p/kWh (+/-0.3p/kWh), with offshore at around 5.5p/kWh, compared to a wholesale price of around 3p/kWh.[123] The additional system cost was estimated to be around 0.17p/kWh when wind makes up 20% of total capacity installed. This figure accounts for the additional costs caused by the variability of wind, which requires a small increase in "balancing requirements" of the network operator. Generation costs are likely to decrease over time as the technology improves, but this will be balanced against increased costs for integrating higher levels of wind generation into the system. However, as the SDC's work, and the more recent work by the UK Energy Research Centre (UKERC),[124] has shown, wind power and other "intermittent" generators do not require dedicated backup capacity, and the cost of handling any net increase in variability is small.

  The generation costs of offshore wind are harder to calculate, and are proving to be more expensive than anticipated. In its current form the Renewables Obligation will not deliver sufficient financial support to for large-scale deployment of offshore wind, but the recent decision to band the RO should change this.[125]

Market arrangements

  Wind is free and uncontrollable which means that the marginal operating cost for wind generation is close to zero. Wind generation would rather sell its output than not. This essentially means that wind will take the lowest wholesale price which is often set by the price of gas. As such the financial return on wind generation is variable and dependent on the wholesale price of electricity.

  Under the British Electricity Trading and Transmission Arrangements (BETTA) around 2% of the electricity traded is done so through the balancing and settlement mechanism. The mechanism was designed to incentivise parties to match supply with demand and encourage investment in generation to minimise the risk of large-scale power outages. This was achieved by having two imbalance prices, a System Buy Price and System Sell Price.

  Through this mechanism generators have to state how much electricity they will generate every half hour. Generators that under-produce must buy electricity at the system buy price, those that overproduce must sell the surplus at the system sell price. Whilst the predictability of wind and other intermittent generators does improve over a half hour period there is still greater scope for being out of balance and paying punitive charges.

  The costs of the mechanism are very high for small generators, such as renewables, who are exposed to risk from the spread between the two imbalance prices. However, renewable generation has to reach a significant proportion of the total GB generating mix to pose a significant risk to the balance of supply and demand.

  Ofgem recently approved a code modification (P197) which changed the basis for system buy and sell prices to reflect the marginal price of electricity, thereby increasing the cost borne by the generator for being out of balance. This has led to a situation where the generators that are being most heavily penalised are the ones that pose the least risk to the system.

  Whilst the RO allows wind to cover the cost of the balancing mechanism, it's existence is evidence of a set of trading arrangements which do not recognise the particular characteristics of wind or other renewable generation.

Carbon footprint

  The energy balance, or "carbon payback", of wind turbines has been cited as a factor that limits its effectiveness at reducing greenhouse gas emissions. There are a number of studies on this subject[126] with most suggesting that wind turbines take between three to 10 months to produce the electricity consumed during their life-cycle. The payback period varies depending on the size of the project and the location.


  The SDC is currently conducting a review of the potential for tidal power in the UK, with funding support from the UK Government, Welsh Assembly Government, Scottish Executive, Department of Enterprise, Trade and Investment (Northern Ireland), and the South West Regional Development Agency. The project was originally announced in the DTI's Energy Review,[127] and was restated in the Energy White Paper 2007.125 The review covers both types of tidal resource, tidal stream and tidal range, and reviews the technologies available for harnessing this resource.

  The SDC is assessing the potential role of tidal power generally, and of a Severn barrage specifically, to contribute to the twin challenges of climate change and energy security. The primary aim of the project is to develop a public-facing report on tidal power in the UK from a sustainable development perspective which will include recommendations for policy-makers. The SDC's work is based on a set of evidence-based research reports looking at the various issues in more detail, along with the results of a substantial public and stakeholder engagement programme.

  Our review has been confined to an assessment of existing studies and research; it has not involved any new primary research except where this has been provided to the SDC directly. Our review of options for a Severn barrage has focussed on two principal barrage options: the large Cardiff-Weston barrage promoted by the Severn Tidal Power Group (STPG) and the smaller Shoots barrage close to the second Severn crossing and currently promoted by PB Power. The review recognises that there are other schemes which have been studied previously or are currently being suggested, for example, Somerset County Council's interest in an outer barrage to address flood protection objectives, and these schemes will be referenced but are not considered in detail. The report will also address tidal lagoons and tidal stream technologies from a UK-wide perspective.

  We hope to publish our final report and the accompanying evidence base in Autumn 2007.


  There is an increasing need for the development of more sophisticated grid management solutions in order to facilitate the connection of renewable and low carbon generation.

  The current energy system is based around a series of large power stations connected to the transmission network. The transmission system operator's role is to ensure that supply and demand of energy are always in balance so as to ensure that the lights stay on. The distribution network operators (DNO) in the current system are designed to be only passive players in the energy system, ensuring that electricity flows from the transmission network to our homes and businesses.

  However, as the market moves towards increasing levels of distributed generation so it will be important for the distribution networks to become more active managers of the energy flowing across their network. As the distribution networks become more active, so the system can start to provide more innovative solutions for matching the characteristics of different types of generation with different demand profiles.

Deployment and timescales

  Ofgem have recognised the potential for intelligent grid management and put in place a series of incentives to move the distribution networks to become more active in managing energy flows. However, a move to more active management of the distribution networks could be costly, and the need depends largely on whether distributed generation technologies can compete in the current market framework.

  The DNOs have an incentive to connect distributed generation, which in 2005 was set at the rate of £1.50 per MW of connected distributed generation. This incentive is reinforced by the Registered Power Zones programme which provides an extra £3 per MW if the connection is made using an innovative solution. However, the incentive is having little impact as the criteria for receiving the it is quite narrow and, once demonstrated, the innovative solution can no longer gain the additional funding when used by other DNOs. This has led to the demonstration of innovative solutions but no mechanism for the rapid commercialised roll-out.

  Work being done by Surrey University in association with United Utilities[128] highlights the potential for DNOs to lose money by connecting distributed generation. This is due to the loss of revenue that would have come from the charges associated with the pass-through of electricity from the transmission network. Whilst this work is still at an early stage, it potentially highlights the need for a more thorough review of the charging and incentive arrangements for DNOs, to facilitate the move towards more active management.

  At present, the innovation spend by DNOs is very low, with the highest (EdF) at around 0.4% of turnover. The UK all-industry average for innovation expenditure is around 2% of turnover. Ofgem adopted an innovation funding incentive in the 2005 price control review which allowed DNOs to spend 0.5% of their turnover on innovation. This has helped to restore innovation funding to levels equivalent to pre-privatisation, but is still below the UK national average for all industries.

  Timing is a critical issue. Network assets have a long lifetime, with investments made over the next five to 10 years delivering infrastructure that will last until 2050. However, the low level of innovation means that network expenditure is going on like-for-like replacement of network assets, meaning that the grid in 2050 will be no more technologically advanced than the grid of 1970. A much stronger focus is required on the incentive regimes for network innovation to reduce network losses, increase capacity and ensure that the system is future-proofed for the connection of new generating technologies.

July 2007

119   SDC (2005). Wind power in the UK. Back

120   Further details can be found on the SDC website at Back

121   Further details can be found on the SDC website at Back

122   Figures obtained from the British Wind Energy Association website: Back

123   These prices are based on pre-2005 data and are therefore likely to have changed. Back

124   UKERC (2006). The Costs and Impacts of Intermittency. Back

125   HM Government (2007). Meeting the Energy Challenge. Energy White Paper 2007. Back

126   Danish Wind Turbine Manufactureres Association (1997), The Energy Balance of Modern Wind Turbines, Available from; citations in Wind Power Weekly (1992), Available at; and Milborrow, D, (1998), Dispelling the Myths of Energy Payback Time, Wind Stats Newsletter, Vol 11, No 2. Back

127   HM Government (2006). The Energy Challenge. Energy Review Report 2006. Back

128   University of Surrey/Unied Utilities a tool to analyse the regulatory incentives on a distribution network operator at a project level (2007). Back

previous page contents next page

House of Commons home page Parliament home page House of Lords home page search page enquiries index

© Parliamentary copyright 2008
Prepared 19 June 2008