House of Lords - Economic Affairs

The Economics of Renewable Energy - Economic Affairs Committee Contents

Memorandum by EDF Energy

INTRODUCTION TO EDF ENERGY

EDF Energy is one of the UK's largest energy companies. We provide power to a quarter of the UK's population via our electricity distribution networks in London, the South East and the East of England. We supply gas and electricity to over 5 million customers and generate about 5GW of energy from our coal and gas power stations, as well as combined heat and power plants and wind farms. The company is also a key player in national infrastructure projects including management of private electricity networks serving four London airports and the Channel Tunnel Rail Link, the country's first major new railway in 100 years. We employ nearly 13,000 people at locations across the UK. EDF Energy is a core part of EDF Group, one of Europe's largest power companies.

EDF Energy recently announced the formation of a new company, EDF Energy Renewables, to take forward its sustainability and renewables agenda. The deal formalises a well established history of cooperation between two EDF Group companies—EDF Energy and EDF Energies Nouvelles. Each party will combine its renewable energy development skills, expertise and resources in one place in order to spearhead their renewables development activities in the UK.

As one of the UK's largest energy companies, EDF Energy already owns and operates two onshore wind farms in the north east of England, and has around 120 MW of on and offshore wind projects under construction or in advanced development. We have also entered into Power Purchase Agreements (PPAs) providing approximately 900 MW of electricity from renewables, thereby supporting the development of capacity by third parties.

EDF Energies Nouvelles is a leading international player in the renewable energy sector and a 50% owned subsidiary of EDF Group. The company has an overall installed capacity of over 2,500 MW in operation or under construction worldwide and in the UK owns 154 MW of capacity.

The creation of EDF Energy Renewables will be a cornerstone of plans, announced last year in Our Climate Commitments, to transform our business to help tackle climate change. A key commitment is an investment by 2012 in around 1,000 MW of UK renewable energy production. EDF Energy Renewables will be key to meeting this target and has ambitions to participate in the UK Government drive to develop increased offshore wind capacity by 2020.

SUMMARY OF EDF ENERGY'S EVIDENCE

The 15% renewable energy target for the UK is extremely challenging. It will:

— significantly increase the cost of delivering greenhouse gas emission reductions;

— create new security of supply challenges (by increasing the amount of plant that must be built to achieve a satisfactory capacity margin and increasing the volume of actions that the system operator must take to ensure that supply and demand are matched in real-time) if a very high percentage of intermittent renewable electricity generation is built;

— create the need for radical change in how the UK electricity and heat sectors are structured and operate; and

— alter investment incentives for other types of new plant including nuclear and clean coal fitted with carbon capture and storage equipment both of which are important elements of a low carbon, diverse, secure energy mix in the future.

Government's primary environmental objective must be greenhouse gas emission reduction targets. The delivery of the 2020 renewables targets must be a "stepping-stone" that facilitates delivery of the UK's 2050 climate change target in the least-cost manner. When deciding on the apportionment of effort between UK sectors the cost-benefit of proposed measures must consider the whole lifetime energy system cost.[50] A target of 40% renewable electricity by 2020 will be extremely difficult and very costly to deliver. All sectors including heat and transport must take a fair share of the burden and the electricity sector should not be used as the sector of "last resort" for delivering the UK renewable energy target.

Given the large cost increases that customers will face, delivering expensive renewables targets in the most efficient manner possible is essential. The ability to trade renewables certificates across national borders will help reduce the additional costs. The current draft Directive text restricts trade and should be amended.

Renewable electricity delivery to-date has been slowed by transmission access and planning issues rather than the nature of the financial support mechanism. However, despite this, we consider that there is a major question mark over whether the Renewables Obligation is fit for purpose for delivering a large, mandatory renewable energy target because:

— suppliers have the option to pay the buyout and do not have to contract with enough renewable generation to meet the target;

— if carbon price rises (and this was not foreseen when ROC bands were initially set) existing ROC-eligible projects will receive excessive support and increase costs for consumers.

We support a full review of the most appropriate financial support mechanism.

Whilst the existing transmission access arrangements can be reformed to improve the allocation of existing capacity, for example by enabling the sharing and trading of instantaneous access rights to the transmission system, the key to accommodating much larger volumes of renewable generation is the construction of new assets. Strategic investment ahead of need is necessary to build these assets in time to meet the 2020 target. Proposals in the Renewables Directive for priority access for renewables are of concern because the UK requires major investment in both new renewable and new thermal capacity. Investor confidence must be maintained for investment to occur in all technologies. A recent report by the Council of European Energy Regulators (CEER)[52] recognised that the draft provisions relating to priority access could exacerbate the implications for system balancing as well as impacting competition and security of supply.

How do and should renewables fit into Britain's overall energy policy? How does the UK's policy compare with the United States, Australia, Canada, and other EU countries?

1. The four main objectives of UK energy policy as set out in the 2007 Energy White Paper are:

— to put the UK on a path to cutting CO2 emissions by some 60% by about 2050, with real progress by 2020;

— to maintain the reliability of energy supplies;

— to promote competitive markets in the UK and beyond; and

— to ensure that every home is adequately and affordably heated.

2. A 60-80% reduction in CO2 emissions by 2050 will require significant decarbonisation of all sectors (electricity, heat and transport). In the electricity sector, nuclear and CCS provide alternative low carbon options to renewables. In the heat sector, energy efficiency, solar thermal and biomass have only limited potential. Implementing low carbon heat solutions on a large-scale for millions of existing properties in urban environments is likely to require the use of heat pumps which use c 1 unit of electricity to deliver c 3-4 units of renewable heat. In the transport sector biofuels are likely to achieve only limited penetration due to resource availability and sustainability concerns—low carbon electricity provides an alternative decarbonisation route as described in the King Review. It therefore seems inevitable that UK energy policy will result in a large increase in (decarbonised) electricity demand.

3. The current targets for renewable electricity build in the UK are a pragmatic response to the non-binding renewable electricity targets in the existing Renewables Directive and a desire to create an indigenous renewable electricity industry. The introduction of a mandatory 15% renewable energy target for the UK will create major additional costs for consumers.[53] Current BERR thinking appears to be to place a large proportion of the burden onto the electricity sector (indicative targets of 40% renewable electricity, 10% heat and 10% transport by 2020).

4. Reliability of energy supplies is a function of diversity of energy sources and reliability and spare capacity of energy infrastructure. At a high level renewable energy targets will displace imported fossil fuels in the EU and improve security of supply.[54] However, the targets will also create problems for the UK because the primary means of meeting the proposed electricity sector target will be intermittent onshore and offshore wind. Managing this intermittency will create additional costs for consumers because it will entail:

— greater reserves held by the system operator to ensure system balancing;

— lower load factors for conventional plant which will therefore require higher prices when these plant do run to recover their fixed and financing costs over fewer running hours.

The need for lower load factor mid-merit or peaking plant is likely to lead to the construction of low capital cost, flexible plant which is likely to be gas-fired Combined Cycle Gas Turbine (CCGT) and the less efficient Open Cycle Gas Turbine plant. This may lead to an increased dependence on gas than would otherwise have been the case if renewable build was more limited.

5. With the exception of the heat sector, none of the four policy objectives necessarily requires the use of renewable energy. In particular large-scale deployment of intermittent renewable electricity generation runs counter to the second and fourth objectives because:

— nuclear (and potentially CCS) can provide large volumes of low carbon electricity at lower cost than renewable technologies;

— large volumes of wind generation, whilst reducing dependence on imported fossil fuels, will create new security of supply risks associated with intermittency, the management of which will also incur major additional costs; and

— it could delay investment in the technologies which will be required to deliver the 2050 target (nuclear, CCS) because subsidised investment in renewables will cause wholesale electricity prices to become more volatile (and even negative at times of moderate demand and high wind resource).

6. High penetration of renewables in the UK electricity generation mix by 2020, as a consequence of the proposed Renewables Directive, therefore appears to be a very inefficient mechanism for delivering energy policy objectives.

7. Our current understanding is that BERR is considering a sectoral split of approximately 10% transport, 10% heat and 40% electricity. How the burden is allocated between the sectors is within the control of the UK government. Redistributing the burden such that a greater emphasis is placed onto heat would reduce the logistical difficulties associated with major electricity transmission system reinforcement and installing c 30GW of offshore wind capacity in little more than ten years. This could make the UK target more easily achievable. It may also be more cost-effective when considering the necessary decarbonisation of the heat, transport and electricity sectors to deliver a CO2 emission reduction target for the UK of 60-80% by 2050 to have a more balanced low carbon electricity generation portfolio with a lower penetration of intermittent renewable generation. We believe the following principles should define the UK's approach to implementing renewable energy targets:

— reduction in greenhouse gases at least cost must have primacy relative to technology-specific targets to deliver renewable energy;

— all sectors should take a fair share of the burden and the electricity sector should not be used as the sector of "last resort" for delivering the UK renewable energy target.

8. Ideally this would mean no specific renewable energy target and reliance instead upon a long-term carbon price to provide the economic signal for investors to select the most cost-effective low carbon technologies. However, given that the UK's intent is to use best endeavours to implement its share of the EU renewable energy target then in practice this should mean:

— maximising deployment of measures in the heat sector to minimise overall cost and start the process of decarbonising the heat sector that will be needed to deliver the 2050 GHG emission targets;

— ensuring trading is effective to allow the UK to access lower cost projects elsewhere in the EU; and

— reducing the capacity threshold on the late deployment clause to allow the target to be delivered over a longer time period.

What are the barriers to greater deployment of renewable energy? Are there technical limits to the amount of renewable energy that the UK can absorb?

9. A number of barriers exist to the greater deployment of renewable energy including:

— delays in the planning system—which are being addressed via the Planning Bill although concerns still remain that the new IPC process may not provide binding, definite timescales for decisions on planning applications;

— long lead times for obtaining connections to the transmission system;

— constraints in turbine manufacturing and installation, particularly offshore; and

— public acceptance of wind farms and new forms of renewable energy generation.

10. Stable financial support mechanisms that provide adequate levels of support and sufficient confidence to investors are also a necessary prerequisite for greater deployment.

11. Intermittency of wind generation can be managed by holding additional reserve for short-term balancing and keeping additional conventional plant on the system to provide an adequate plant margin to maintain security of supply—at additional cost. There is unlikely to be a technical limit, instead the willingness to pay these additional costs will create a barrier.

12. 40% renewable electricity generation (dominantly from wind) combined with a nuclear portfolio of c.10GW with sufficient plant synchronised to manage fluctuations in demand and generation output will cause a significant number of half-hour periods in the UK when generation output exceeds electricity demand. Technically this could be managed by the system operator constraining plant off the system at additional cost. Perversely the SO could be forced to constrain renewable generation off the system for system stability reasons—this would force the construction of yet further renewable capacity to meet the renewable energy target. Increased interconnection, storage and demand management may play a role in mitigating this effect subject to their cost-effectiveness.

13. The Transmission Access Review (TAR) is seeking to improve the timeliness of transmission connection. However a key concern for EDF Energy is that the TAR primarily introduces measures to improve short term allocation efficiency which could in turn increase long term uncertainty for market participants and undermines long term investment in both generation and transmission. The core issue is scarcity of transmission capacity and securing this capacity and utilising it well must remain the prime objective of the review.

Are there likely to be technological advances that would make renewable energy cheaper and viable without Government support in the future? Should, and how could, policy be designed to promote such technological advances?

14. A number of technologies clearly have potential for cost reductions due to their relative immaturity. For example, PV, wave, tidal stream, tidal barrage, offshore wind and heat pumps have relatively small installed capacities globally. As installed capacity increases, learning curve effects may be realised, reducing costs. Also, more manufacturers may enter these markets and existing manufacturers are likely to increase manufacturing capacity reducing supply chain constraints. Offshore wind deployment is however likely to move to deeper water and more hostile environments in future years which will increase capital costs.

15. Government support is likely to be needed for the foreseeable future for almost all renewable energy technologies unless either the carbon price rises significantly or fossil fuel prices rise to much higher levels.

16. We believe that R & D and commercialisation support should be provided to new emerging technologies to assist them in reaching maturity, at which point they should compete on a level-playing field with other low carbon technologies.

Has Government support been effective in leading to more renewable energy? What have been the most cost-effective forms of support in the UK and other countries and what should the balance be between subsidies, guaranteed prices, quotas, carbon taxes and other forms of support? Should such support favour any particular form of renewable energy over the others? For instance, what are the relative merits of feed-in tariffs versus the UK's present Renewables Obligation Certificate (ROC) regime?

17. Financial support from the Renewables Obligation has led to more renewable energy deployment and the creation of a large pipeline of renewable projects.

18. Direct comparisons between UK and overseas support mechanisms are not straight-forward because:

— the cost effectiveness of a 25 year obligation style mechanism cannot be accurately based on the subsidy per MWh delivered in the first few years of the obligation; and

— generators may require financial support to cover differences in costs (eg different transmission charging arrangements) in different markets.

However, the quota-based Renewables Obligation has clearly been inefficient from a consumer perspective in the UK market where deployment of renewables has been delayed by planning and transmission access issues. This is because:

— consumers pay the buyout price for the target percentage of renewable energy generation irrespective of the how much renewable energy is actually delivered; and

— delays that have prevented deployment of lower cost generation have increased the ROC recycle value and provided excessive support for low cost generation whose deployment has not been delayed.

19. Conceptually, support should not unduly favour one renewable technology relative to another. However, it is clear that different renewable technologies are at different stages of maturity resulting in large levelised cost differences. Using a uniform support level that is sufficient to deliver the last MWh of renewable energy from the marginal technology necessary to meet the target can be highly inefficient for consumers because it can over-reward cheaper technologies. This inefficiency must be avoided if costs to consumers are to be minimised.

20. In the longer-term, intermittent renewables will become increasingly dependent upon the financial support mechanism because power prices will be inversely correlated to national wind output (ie wholesale prices will be low when it is windy so the price that suppliers will be prepared to pay for electricity from wind generators will decrease). Maximising the efficiency of the support mechanism will become ever more important.

21. The Renewables Obligation has a number of drawbacks when considering its appropriateness for delivering the greatly enhanced renewable electricity target.

These include:

— the target is likely to be so stretching that almost all available projects in the UK will have to be constructed—the efficiency benefits of a market-based solution which delivers the most cost-effective projects within the UK is therefore likely to be diminished;

— within each technology band, support costs are likely to be divergent. For example the cost of supporting the 30th GW of offshore wind, in deep water and distant from shore, may be very different to that of the 1st GW of offshore wind in shallow water and close to shore. The current approach of providing adequate support for the marginal MW to be delivered will create inefficiencies for consumers and windfalls for cheaper technologies or projects within each band;

— the RO, which is intended to have five-yearly band reviews, may not be flexible enough to rapidly adjust to short-term changes in turbine costs etc. For example, concerns are already being expressed that a 1.5ROC/MWh band for offshore wind may be insufficient (even though the band has not yet been introduced). A FiT or CfD approach would be flexible enough to enable annual changes in financial support to reflect changes in project economics. To deliver the target it is essential that the UK remains a competitive location for deployment if turbine supply remains constrained;

— suppliers may not want high exposure to intermittent generation because of ROC price or balancing market price risks and may therefore rationally not contract with enough renewable generation to meet the UK target (alternatively, suppliers will be prepared to pay less for each additional MWh of renewable generation). If a FiT was introduced, government would be capable of finessing support level until desired volume of renewable generation was delivered; and

— if carbon or commodity prices rise then existing projects with their grandfathered banding will receive excess support.

22. The most likely alternatives to a quota-based system include:

— feed-in tariffs where the support-level is determined either by government or through a competitive tender process; or

— contracts for difference against either carbon price or electricity price where the support-level is determined either by government or a competitive tender process.

In the former, the support mechanism would have to finance the whole cost of renewable generation whereas in the latter only the difference between the market price and the strike price would be financed by the support mechanism. Penalties for non-delivery would address the defect that existed in the Non Fossil Fuel Obligation tender process that existed before the Renewable Obligation was introduced, whereby generators bid at levels which subsequently proved uneconomic for them to develop projects. Both mechanisms provide protection to the consumer if carbon or electricity prices rise. The CfD option would enable a transition to support solely from the carbon price in the longer-term.

23. The table below compares the main support mechanism options against assessment criteria. It indicates that the RO may not be the optimal support mechanism to support delivery of increased renewable support mechanisms.


Criteria	RO	FiT	CfD4

Build different technologies simultaneously	Yes	Yes	Yes
Efficiently support construction of low and high cost projects of same technology simultaneously	No	Possibly	Possibly
Prevent windfall to generators if carbon prices rises	No	Yes	Yes
Guarantee delivery versus targets	No	Possibly	Possibly
Integrate auction revenues into support mechanism	No5	Yes	Yes
Continuity for investors	Yes	No	No

We consider that a full review of the appropriate financial support mechanism is necessary.

Financial support for renewable heat

24. Renewable heat sources would be more viable if the cost of CO2 emissions from conventional heating sources was internalised in the cost of heating. This could be achieved by including the CO2 emissions arising from fuels used in heating in the EU ETS.

25. Alternatively assuming that customers are required to make at least a contribution to the costs of any support mechanisms, EDF Energy's preferred funding solution would be for Government to levy a p/kWh charge on sales of fossil fuels used for heating, with the charge based on the carbon content of the fuel. The revenues would be paid into a national fund used specifically to pay for the delivery of low carbon heating solutions.

26. An advantage of this approach is that by levying this charge on all customers, including domestic customers, Government would be ensuring that all sectors of the electricity and gas markets now paid a "cost of carbon" in their energy use. At present, unlike with electricity, the cost of carbon is not reflected in domestic and small business gas prices, therefore leading customers to make potentially inefficient decisions when selecting replacement heating technologies. A "low carbon heat levy" set at an appropriate level would resolve this market failure.

27. For micro-generation heat technologies, such as single dwelling heat pumps, biomass boilers and solar thermal, the key barrier to uptake is capital cost. We believe that capital grants should be provided to reduce the cost differential between conventional heating sources (such as gas) and lower carbon solutions.

28. For larger low carbon solutions, such as community scale gas, biomass or waste fired CHP, ongoing financial support should be provided on a £/MWh generated basis. Proposals for feed in tariffs and a "low carbon heat obligation" should be considered in more detail.

29. Government will need to determine the most equitable basis for raising funds and consider limiting the impact on vulnerable customers. Some form of contribution from Government will ease the burden on customers, and Government should consider all available options including using part of the revenues generated through the auctioning of European Union Emissions Trading Scheme (EU-ETS) carbon permits.

On top of the costs of building and running the different types of electricity generators, how much investment in Britain's transmission and distribution networks will different renewable energy sources require compared to other forms of generation? Are the current transmission and distribution systems capable of managing a large share of intermittent renewable electricity generation and, if not, how should they be changed? Are the rules about how we connect capacity to the grid supportive of renewables?

30. The challenges are not unique to UK; northern Germany, Denmark and Spain already have considerable experience in integrating capacities of wind generation. However, much research, development and deployment remains to be undertaken to fully explore the challenges and opportunities of integrating large volumes of renewable sourced electricity generation with transmission and distribution networks. With this in mind, The European SmartGrids Technology Platform[57] has been created and has already produced a "Vision and Strategy" document and a "Strategic Research Agenda". In the summer of 2008 a "Strategic Deployment Document" will be published providing guidance on developing business cases for deployment of the more advanced and relevant technologies.

TRANSMISSION SYSTEMS

31. For transmission networks which are already designed to accommodate generation, the issues are essentially capacity (and/or constraint) management, frequency and voltage stability, and system balancing capability. Much work, strongly supported by the GB Transmission Network Operators and the GB System Operator (GBSO), has already been undertaken by the Government (BERR)/Ofgem sponsored Electricity Networks Strategy Group's Transmission Working Group (TWG). Examples of relevant studies include: the development of a framework for offshore transmission licensing; queue management; Connection and Use of System Code (CUSC) amendments; Transmission Access for Distributed Generation (TADG); managing the allocation of Transmission Export Capacity (TEC); and the Transmission Access Review (TAR).

32. The proposed offshore licensing regime will give rise to individual licences for connecting offshore wind farms to the onshore grid, sometimes directly and sometimes with 132kV distribution networks providing the linkage to the national 400/275kV transmission system. In terms of network investment, it has been estimated that this strategy would enable the 9GW of "Round 1 and 2" offshore wind farms to be connected for around £10 billion of network investment; roughly £300 per KW of wind capacity connected.

33. While studies have shown this "radial connection" approach to be the most economic in the context of the Round 1 and 2 wind farms, development on the scale implied by the 33GW offshore wind proposal raises questions as to whether this radial arrangement is sustainable or whether instead (or in addition) an offshore interconnected transmission grid might be desirable from both a technical and economic perspective. Whether such a grid might be best developed as a conventional AC system or possibly as a multi-point DC system, potentially interlinking with subsea inter-connectors,[58] would be a matter for detailed assessment. Each approach has its own merits and challenges, and such work is now being undertaken by the Government (BERR) sponsored Centre for Distributed Generation and Sustainable Electrical Energy (SEDG).

34. Other important transmission related work that SEDG intends to pursue through 2008-09 includes: dynamics and control of wind generation (including small signal stability)[59]; harmonic resonance and switching transients with highly capacitive AC systems[60]; fault ride-through capability of voltage-source inverter connected wind sourced generators; examining the aerodynamic performance of wind turbines; and investment access and pricing of transmission systems with significant penetrations of wind power (including requirements for GB Security and Quality of Supply Standards).

35. Much has been reported about the current "GB Queue" and how current transmission system constraints might be eased through a "connect and manage" approach, perhaps coupled with access rights being prioritized towards wind farms with planning approval and/or actually under development, and with a more dynamic approach to transmission system thermal ratings. While these suggestions have merit, in the context of 33GW of offshore wind capacity, the scale and materiality of the issues being studied by SEDG will need to be thoroughly understood, and cost-effective solutions developed, before the financial implications for transmission grid investment can be reliably evaluated.

DISTRIBUTION NETWORKS

36. In England and Wales, the interface between transmission and distribution networks is at 132kV with NGET being responsible for the 400/275kV grid and for 400 (or 275)/132kV transformation, and Distribution Network Operators (DNOs) managing the remainder of the network infrastructure ranging from 132kV through various voltage levels (including typically 33kV and 11kV) down to 400/230V. In Scotland, 132kV is treated as a transmission voltage with the Scottish DNOs taking responsibility from 33kV down to 400/230V.

37. As noted above, while large offshore wind farms will impact mainly on transmission networks, 132kV distribution networks will provide the offshore to onshore link in some cases. Often this will require reinforcement of the 132kV networks (including use of higher thermal rating/lower sag conductors). At the other end of the scale, the Government's "Zero Carbon Home" initiative[61] will impact on new low voltage (LV), and to a lesser extent 11kV, networks and might require new approaches to network design, for example shorter LV feeders and automatic voltage regulating equipment on 11kV/LV distribution transformers. 33kV and 132kV connected generation (typically onshore wind farms and biomass power stations) may require conventional reinforcement possibly in conjunction with "Registered Power Zone" (RPZ)[62] developed techniques such as enhanced voltage management, active constraint, and active (dynamic) conductor rating. There may be some opportunities for using non-intermittent forms of renewable generation (or intermittent generation in conjunction with storage) and Demand Side Management to offset network capacity reinforcement.

38. For distribution networks, the challenges are those associated with "distributed" generation (DG); ie generation connected directly to distribution networks which have hitherto been designed to deal with (so-called) "one-way" powerflows down through the "hierarchy" of voltages from 132kV to 400/230V. The key DG related technical issues for distribution networks are: voltage management[63]; plant and equipment thermal ratings under different cyclic loading patterns; electrical protection requirements at the network/generation interface[64]; fault level management (ie ensuring plant and equipment ratings can safely deal with increased levels of short-circuit current as a consequence of additional locally connected generation); overall system electrical protection co-ordination[65]; network constraint management; voltage inversion (due to reverse powerflows at voltage transformation points); and maintenance of design levels of network security.[66]

39. Much work, strongly supported by DNOs, has already been undertaken by the Government (BERR)/Ofgem sponsored Electricity Networks Strategy Group's Distribution Working Group (DWG) and its predecessors the Distributed Generation Coordinating Group and the Embedded Generation Working Group. Many studies have been undertaken and reports written to support the wider penetration of DG, including for example: a "Report into Network Access Issues" (2001); "Solutions for the Connection and Operation of Distributed Generation" (2003); the "Technical Guide to the Connexion of Generation to the Distribution Network" (2004); and more recently, the "Future Network Architectures" report (2007).[67] Work is currently in progress to review the requirements under Engineering Recommendations ER G59 and ER G75 that might under certain circumstances ease the requirements on generators in terms of interface protection.

40. The "Future Network Architectures" report considers a number of DG penetration scenarios and provides an insight into the scale of change to network architecture that might be required under each. In terms of the scale of required investment in the distribution networks between now and 2020, the report notes that the relationship is very non-linear with investment estimates ranging from £19 to £89 per kW of connected DG (the latter being more closely associated with high levels of 11kV and LV network connected DG, and a market wherein there is wide deployment of micro-generation and active participation in demand-side management facilitated by a comprehensive smart metering and an associated Information Communication Infrastructure).

41. With very high levels of penetration of DG it is envisaged that DNOs might have to provide ancillary services to the GBSO, including system balancing and reactive power (voltage) support. The report concludes that while the technical challenges are manageable in the medium to longer term, the current GB commercial framework could become a constraint to the development of the fully integrated "Smart Grid" regime (such as that envisaged by the European SmartGrids Technology Platform).

42. In conclusion to this question the costs of developing the transmission and distribution systems will be significant and there are a number of initiatives that are being brought forward as a result of existing incentives that should help in accommodating an increased role for renewables in electricity generation. However this development needs to take place in the context of a system that allows renewable generation and other forms of low carbon generation to co-exist and there is a need to ensure that any enabling solutions for renewables do not undermine investment in other lower cost low carbon technologies that are essential for the UK to deliver its CO2 reduction aspirations.

How do the external costs of renewable generation of electricity—such as concerns in many affected rural areas that wind farms and extra pylons spoil areas of natural beauty—compare with those of fossil fuels and nuclear power? How should these be measured and compared? Is the planning system striking the right balance between all the different considerations?

43. Some of these issues are relevant for both renewables and other forms of generation as the latter may also require transmission system reinforcements. What is clear is that, although all forms of generation have external costs associated with them, society places great value on reliability of electricity supply which therefore necessitates the construction of new power stations and associated infrastructure. These issues need to be addressed by the new National Policy Statements proposed by the Planning Bill to provide an appropriate framework for the IPC to make decisions balancing national need with local concerns.

How do the costs of generating electricity from renewables compare to fossil fuel and nuclear generation? What are the current estimates for the costs of "greener" fossil fuel generation with carbon capture and storage and how do these costs compare to renewable generation? What impact do these various forms of electricity generation have on carbon emissions?

44. Costs for all forms of generation technology have increased in the last 12-18 months in response to rising steel prices, high demand and constraints in manufacturing capacity. However we believe that the relative price differentials presented as a marginal abatement curve in the Government's Energy White Paper (Meeting the Energy Challenge—A White paper on Energy, May 2007) remain broadly valid. The costs of generating from renewables technologies are higher than the generation costs from conventional technologies including nuclear. The relative cost differences in the different renewable technologies are reflected in the varying level of subsidy provided through the Renewables Obligation.

45. Longer-term cost estimates for CCS are still uncertain, particularly how these costs might evolve as deployment increases, technology develops and manufacturing efficiencies are achieved. Current estimates of CCS costs suggest that they are comparable with offshore wind.

46. A number of studies have investigated the full lifecycle emissions of different electricity generating technologies. They demonstrate that nuclear and renewable technologies have very low lifecycle emissions[68] circa 5g/kWh.

How do the costs and benefits of renewable electricity generation compare to renewables in the other key forms of energy consumption—transport and heating?

47. Before comparing technology costs it is important to note that:

— domestic gas prices do not include a CO2 cost. This automatically creates a financial disincentive to invest in low carbon heating solutions; and

— for any such analysis to be comprehensive it must include whole system costs (eg for renewable electricity this would include increased balancing costs, the cost of maintaining additional conventional capacity on the system as backup, increased transmission costs, etc).

48. The key issue that comparative analysis of cost differences between technologies in different sectors needs to address is how the target is allocated between the heat and electricity sectors, ie does the marginal technology in the electricity sector (which is likely to be offshore wind) require more or less subsidy than the marginal technology in the heat sector.

49. EDF Energy's analysis indicates that a high temperature air-water source heat pump, which can be retrofitted to a conventional hot water and radiator heating system in an existing property, would require less subsidy per MWh of renewable energy produced than an offshore wind farm. When considering the cost per tonne CO2 abated, the heat pump is considerably more expensive. However, on an integrated basis it is as cost-effective because CO2 can be abated using non-renewable technologies at a relatively low EU ETS market price.

50. Over time, heat pumps will become even more cost effective (with regard to renewable MWh delivered and CO2 abatement) because:

— major improvements will occur in efficiency (learning curve gradient is steep);

— there will be cost reductions as the volume manufactured increases; and

— they will achieve higher CO2 savings as the grid decarbonises (and the new generation technology benchmark emission factor moves from CCGT to lower carbon technologies).

51. In Europe, heat pump deployment rates are much higher than in the UK and increasing rapidly in a number of major markets. This demonstrates the potential customer uptake that exists for this technology if it is appropriately incentivised. The assumed deployment rate in the Renewable Heat Call for Evidence appears to dramatically underestimate what could be a achieved in practice. Redistributing the renewable energy target to place a greater emphasis onto heat will reduce the logistical difficulties associated with major electricity transmission system reinforcement and installing c 30GW of offshore wind capacity in little more than 10 years. This could make the UK target more easily achievable. It will also be more cost-effective in the long-term when considering the necessary decarbonisation of the heat, transport and electricity sectors through the use of low carbon electricity to have a more balanced low carbon electricity generation portfolio with a lower penetration of intermittent renewable generation.

52. We consider it is essential that heat pump (both air source and ground source) is an eligible renewable technology under the Directive. In the long term, heat pumps are likely to be the main low carbon technology for delivering low carbon heat as biomass supplies are limited and the transport of large volumes of biomass into urban environments is problematic. The Directive provides an excellent opportunity to commence the roll-out of this technology in the UK and develop a large supply chain and installer base. The technology is developing, efficiency is improving rapidly and units are now available that can be retrofitted to conventional radiator-based heating systems found in most properties in the UK. In other European markets annual deployment rates are as high as 120,000 units per annum.

If the UK is to meet the EU target that by 2020 15% of energy consumed will come from renewables, will most of this come from greater use of renewable sources in electricity generation? If so, why? Should British support for renewables in other countries be allowed to contribute towards meeting the target for the UK?

53. It is clear that the electricity generation sector will make a major contribution to the UK target.

However as set out above making a large deployment in the heat sector will:

— potentially be more cost effective by requiring less subsidy;

— avoid additional costs associated with mitigating the impact of high levels of intermittent renewable electricity generation;

— create the supply chain and installer base that will be required to deliver the level of decarbonisation in the heat sector that will be needed to meet 2050 targets; and

— reduce the risk that investment in nuclear and CCS will be deferred.

The technologies to increase renewable heat above 10% penetration, already exist.

54. UK support for renewables in other EU countries, or countries directly linked to the EU, should be allowed to contribute to meeting the target for the UK. Trading can lead to efficiencies and lower costs for UK consumers by allowing either the development of cheaper projects or development of similar cost projects in countries where barriers such as transmission access and/or planning do not prevent construction.

55. Trading beyond EU borders where there is no flow of power into the EU is more controversial. It would lower the cost of the policy and provide benefits to consumers but would not deliver benefits associated with reduced import dependence. Also, it would create complexity through its interaction with Clean Development Mechanism projects developed under UNFCC protocols, many of which are renewables.

How would changes in the cost of carbon—under the European emissions trading scheme—affect the relative costs of renewables and other sources of energy? Would a more effective carbon emissions trading scheme remove the need for special support of renewable energy?

56. An increased cost of carbon in the EU ETS will make renewables more cost competitive because it will increase the SRMC of fossil generation and therefore increase the wholesale electricity price that renewable generation will receive. However maintaining free allocation to new entrants would reduce the long-term electricity price needed for thermal plant new entry and discriminate against low carbon technologies.

57. A more effective carbon trading scheme may not remove the need for special support for renewable energy because:

— the abatement required by the market may be delivered by lower cost options such as energy efficiency, nuclear, fossil fuel switching between coal/lignite and gas and potentially CCS; and

— carbon pricing will provide a uniform support level—this may be insufficient to enable deployment of higher cost renewable technologies which may not have reached maturity yet.

What are the costs and benefits of the present generation of biofuels? Will there be a second generation of biofuels and, if so, what are the estimated costs? What are, or are likely to be, the carbon emission impacts of first and second generation biofuels, and what are the other relevant environmental effects?

No comment.

16 June 2008

50 This should include the additional costs of transmission, back-up capacity and reserves to cope with intermittency, and costs associated with the displacing more cost-effective methods of low carbon electricity generation for the lifetime of the renewable generation assets. Back

51 For example, the cost of the 1st GW of offshore wind could be much lower than the 30th GW due to factors such as water depth, distance from shore, etc. Back

52 Green Package-Proposed EU ETS and Renewables Directives-A CEER position paper. Back

53 Poyry report-Compliance Costs for meeting the 20% Renewable Energy Target in 2020-A report to the Department of Business Enterprise and Regulatory Reform. Back

54 They may also displace indigenous fossil fuels such as UK coal and German lignite. Back

55 The wind capacity that can be relied upon to deliver energy at times of peak demand is approximately the square root of the installed capacity in GW. Back

56 This should include the additional costs of transmission, back-up capacity and reserves to cope with intermittency, and costs associated with the displacing more cost-effective methods of low carbon electricity generation for the lifetime of the renewable generation assets. Back

57 http://www.smartgrids.eu/ Back

58 DC systems are generally point-to-point; a multi-point system would be a relatively innovative development and would require careful consideration from a technical and economic perspective. Back

59 Studies have indicated that with high levels of Doubly Fed Induction Generators (DFIG) in Scotland (ie associated with wind farms) and high levels of synchronous generation in England (eg nuclear, coal and CCGT) system instability could occur. Back