Electricity Market Reform

House of Commons Energy and Climate Change Committee

Fourth Report of Session 2010–12

Volume II Additional written evidence

Ordered by the House of Commons to be published 25 January, 2 and 15 February, 15 March and 27 April 2011

Published on 16 May 2011 by authority of the House of Commons London: The Stationery Office Limited

The Energy and Climate Change Committee

The Energy and Climate Change Committee is appointed by the House of Commons to examine the expenditure, administration, and policy of the Department of Energy and Climate Change and associated public bodies.

Current membership Mr Tim Yeo MP (Conservative, South Suffolk) (Chair) Dan Byles MP (Conservative, North Warwickshire) Barry Gardiner MP (Labour, Brent North) Ian Lavery MP (Labour, Wansbeck) Dr Phillip Lee MP (Conservative, Bracknell) Albert Owen MP (Labour, Ynys Môn) Christopher Pincher MP (Conservative, Tamworth) John Robertson MP (Labour, Glasgow North West) Laura Sandys MP (Conservative, South Thanet) Sir Robert Smith MP (Liberal Democrat, West Aberdeenshire and Kincardine) Dr Alan Whitehead MP (Labour, Southampton Test)

The following members were also members of the committee during the parliament:

Gemma Doyle MP (Labour/Co-operative, West Dunbartonshire) Tom Greatrex MP (Labour, Rutherglen and Hamilton West)

Powers The committee is one of the departmental select committees, the powers of which are set out in House of Commons Standing Orders, principally in SO No 152. These are available on the Internet via www.parliament.uk.

Publication The Reports and evidence of the Committee are published by The Stationery Office by Order of the House. All publications of the Committee (including press notices) are on the internet at www.parliament.uk/parliament.uk/ecc. A list of Reports of the Committee in the present Parliament is at the back of this volume.

The Report of the Committee, the formal minutes relating to that report, oral evidence taken and some or all written evidence are available in a printed volume. Additional written evidence may be published on the internet only.

Committee staff The current staff of the Committee are Nerys Welfoot (Clerk), Richard Benwell (Second Clerk), Dr Michael H. O’Brien (Committee Specialist), Jenny Bird (Committee Specialist), Francene Graham (Senior Committee Assistant), Jonathan Olivier Wright (Committee Assistant), Emily Harrisson (Committee Support Assistant) and Nick Davies (Media Officer).

Contacts All correspondence should be addressed to the Clerk of the Energy and Climate Change Committee, House of Commons, 7 Millbank, London SW1P 3JA. The telephone number for general enquiries is 020 7219 2569; the Committee’s email address is [email protected]

Published on 16 May 2011 by authority of the House of Commons London: The Stationery Office Limited

List of additional written evidence

1 Dr Barrie Murray Ev w1 2 Swanbarton Ev w4 3 Ecolateral Ltd Ev w6 4 Combined Heat and Power Association Ev w10 5 Westinghouse Ev w14 6 Nuclear Industry Association Ev w15 7 Renewable Energy Association Ev w17 8 ESB International Ev w19 9 Association of Electricity Producers Ev w23 10 Welsh Power Ev w26 11 Scottish Renewables Ev w31 12 InterGen (UK) Ltd Ev w32 13 Renewable Energy Systems Limited Ev w35 14 Low Carbon Group Ltd Ev w39, w43 15 Institution of Engineering and Technology Ev w45 16 Grantham Research Institute and Centre for Climate Change Ev w47 Economics and Policy 17 Professor Michael Grubb, Cambridge University Ev w50 18 Alex Henney, EEE Ltd Ev w59 19 Mainstream Renewable Power Ev w64 20 Carlton Power Ev w65

cobber Pack: U PL: CWE1 [SO] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w1

Written evidence

Memorandum submitted by Dr Barrie Murray

Summary This memorandum advocates the establishment of a centralised procurement agency for low carbon energy sources as the only viable option to secure an optimal least cost development whilst managing the many new and diverse issues associated with alternative energy sources. The previous efforts to promote competition in the electricity sector have moved the country into a position where we no longer exercise control over a key part of our national infrastructure. We are left with attempting to seduce potential generators with incentives under the guise of market reforms to build new capacity. The industry is controlled by foreign utilities whose only interest is profit and they use the threat of future shortages to extract more subsidies and are in a position to blackmail us. This contrasts with our neighbouring European partners who have retained national champions that have enabled them to thrive whilst maintaining an ability to exercise control. Given the wide range of issues that the sector faces over the coming years it will not be possible to effect an optimum development strategy through market mechanisms and some form of central planning and control needs to be implemented. End users and industry have to be able to input their needs and concerns. It is likely that the escalation of energy prices associated with the proposed EMR will put some companies out of business and reduce electricity demand. The proposals can only lead to higher end user prices and the government has to evidence why it believes prices will be lower than they would otherwise have been. How reliable is this assertion without knowing what investors plan to do when they will seek to maximise profit? Can we be certain what the rest of Europe will be doing during this period and why investors in new plant would choose the UK? Where are the academic economists that said that the market would solve all including the provision of adequate levels of investment? It is naive to believe that the targets and the required optimal outcome will all be delivered through manipulation of a carbon floor price. Nuclear must be the most cost effective way of meeting requirements to reduce emissions because of its high load factor producing three to four times more energy than the equivalent wind capacity. Nuclear should form a dominant proportion of the future plant mix and its contribution to reducing emissions should be recognised. But, how will its provision be made competitive when we purposely and openly disadvantage the alternatives of coal and gas generation. A further consequence of the proposed CCL on fuel will be to encourage energy intensive users to locate outside the UK. The current government agencies that exercise authority to commit the nation to crippling subsidies were not constituted with the necessary skills for their current engagements in negotiating and establishing an optimal way forward.

1. What should the main objective of the Electricity Market Reform project be? (a) The aim has always been to minimise the overall energy cost to end users whilst maintaining accepted levels of security. The end user payments also include a significant proportion to cover transmission and distribution as well as metering, administration and regulation and they can be expected to add significant extra costs to accommodate renewable sources. What’s missing in the current debate is how the optimum development is supposed to be established. The procedure prior to restructuring was to establish optimal coordinated generation and transmission development plans that took account of all the requirements including cost minimisation security, fuel diversity, operational efficiency and minimum risk. This was achieved using large scale LP formulations of the problem which over the years had become highly developed. It is to retain this ability to coordinate development that many informed countries have chosen the Single Buyer market model where a central procurement agency acts on behalf of all customers to establish supplies and facilities to meet their agreed needs. This enables overall government strategy to be incorporated with competitive tenders for new capacity aimed at developing an appropriate plant mix. It is difficult to see how this can effectively be managed by tinkering with current market arrangements were each player has the option to pursue their own plans. The long lead times for development confound the problem and introduce risk that has to be covered through market prices. It is a delusion to think that DECC or Ofgem are going to establish an optimal way forward by tinkering with market arrangements and CO2 prices. The costs involved and implications of failure are too great to rely on ad hoc trials of different market arrangements and someone needs to take control of the situation. A centralised market to coordinate the development of low carbon sources offers the best approach to deal with the many abnormal issues surrounding renewable development. This approach offers more scope and flexibility to address some of the technical problems associated with renewable integration and has parallels with the centrally managed balancing market. It must be arranged to foster competition through competitive tender in all time frames. Amongst the many other issues that need to be addressed are: — Should renewable energy sources receive special treatment related to balancing? — Should this balancing treatment be differentiated by renewable energy sources? — The market time frames that should apply recognising the intermittency. — The degree of optionality available to market participants. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w2 Energy and Climate Change Committee: Evidence

— The requirements to realise competition and liquidity including, tenders and auctions in different timeframes. — Avoiding market distortions and maintaining compatibility with current market arrangements. — The potential role of capacity payments. — The importance attached to establishing an appropriate level of system security. — Avoiding undue complexity, implementation delays and operating costs. — The governance of the market. — Consideration of associated storage options.

2. Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? (a) The problems with capacity payments are well known in that the expectation is that they should be paid to all generators, including those that are already there, even if they are not used. The calculation of the justifiable charge to end users is usually based on the overall LOLP (Loss of Load Probability) and VLL (Value of Lost Load). The optimum arrangement is where the likely cost to end users of loss of supply is in balance with the fixed annual cost of new generation. Where these payments are spread between all generators they make only a small contribution to the fixed costs of a particular new entrant and there is no guarantee that any new plant will be built. In a Single Buyer model the exact amount of new capacity would be established through a competitive tender and contract process. (b) The suggestion of capacity payments has been prompted by the concern to retain marginal peaking generation to cater for wind output variation. With the large volumes of wind proposed mid merit and even base load generation will also see a reduction in utilisation. Any mechanism would have to recognise the different impact on generation and added wear and tear costs incurred by generation in regulating to follow the net demand. There should be the option to meet the regulating requirement from other sources like Scandinavian hydro which is likely to prove cheaper. A new North Sea super- grid extension should be actively promoted to facilitate competition between the various options. These options are best coordinated and developed as part of a centralised procurement function for low carbon energy embracing the procurement and contracts for provision of balancing energy.

3. What is the most appropriate kind of capacity mechanisms for the UK? (a) Any capacity payment should be self correcting and not encouraging new entry when sufficient capacity is already in place. In some implementations the payment has been geared to the overall plant margin (a measure of excess capacity over demand). Other implementations have proposed payments according to technology type to encourage an appropriate plant mix. The question also arises as to the credit to firm capacity that should be given to wind generation and other marine sources. (b) There are two issues involved; one is ensuring sufficient capacity is available to meet future needs recognising onstruction timescales; the other is securing availability in operation on the day. The requirement to manage the intermittency of generation ultimately rests with the System Operator (part of NGC). They are best placed to determine need and should be incentivised to contract for capacity considering all options including demand side management and import/export. The SO should also be incentivised to coordinate wind and marine output forecasting as part of a centralised management function. In operational time scales the original UK Pool model aimed to achieve availability through a LOLP increment to the marginal price when capacity was in danger of being short of that required to maintain security. It was considered that market spot prices provided an adequate mechanism through price spikes to secure capacity in the short term. Price spikes can be minimised by better forecasting and control. The requirements for balancing are most easily coordinated centrally.

4. Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology-based view? (a) The world is full of examples where long term commitments to power purchase agreements have proved a subsequent burden when developments have changed the situation. The tariffs should be linked through contracts to general market prices and available to any source to promote the least cost abatement for emissions. They should be linked to the price of CO2 to enable nuclear, coal and gas with CCS to compete on an equal basis. It is dangerous to set tariffs artiﬁcially high to promote industrial development as this sets expectations that are not sustainable.

5. Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? (a) There is insufficient time to agree and establish a whole set of new regulations that have to be judged and analysed by the market. It is also expected that they will be wrong given the difficulties associated with this sector. A centralised procurement agency would have the flexibility to respond and adjust on a continuous basis as issues arise and circumstances change. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w3

6. Will market reform increase political risk for investors or create certainty? (a) Uncertainty will still surround what plant will actually get built. Claims by DECC and the Scottish Executive about the proportion of renewable energy in the future plant mix are fanciful. However, they do deter investors because of the potential impact on the utilisation of their conventional generation. There is also uncertainty about how the REFIT will vary in future. Investors prefer an unbiased market where real costs affect market potential rather than price ﬁxes and subsidies and attendant regulatory risk that cannot be predicted. There is also uncertainty as to what new directives may emanate from the EU.

7. Will the Government’s proposed package of carbon price floor, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? (a) Offshore wind is unlikely to be built without a subsidy of 2 ROCs or an equivalent feed in tariff resulting in wholesale prices three times equivalent gas and coal. In addition off shore transmission will increase the capital cost around 50%. They will contribute very little to the security of supply because of their intermittency, with only 10% of their installed capacity being regarded as firm. There are also hidden costs in managing intermittency and ensuring backup capacity is available through capacity payments. Given the scale of developments in Asia the UK contribution to climate change amelioration is likely to be minimal. (b) The government should make its goals clear in terms of how they expect the target to be met. What is the optimum mixture of technology that would meet the requirement at minimum cost? How is it expected the intermittency of renewable sources will be managed and what will be the added cost to consumers? It is not acceptable to state that it will be less than otherwise would be the case without evidence. What scenarios have been advanced and studied. What assumptions have been made about fuel prices, demand side management, energy efficiency, CCS, imports/exports and electric vehicles? These require detailed analysis given the potential impact on consumers and industry and should be preceded by a statement of strategy.

8. What synergies and conﬂicts will there be between proposed mechanisms and policies already in place? (a) The EU has set a number of Directives aimed at promoting the development of renewable energy sources. Most countries in Europe use feed in tariffs to promote renewable development. What is proposed to ensure that the optimal level of transmission is in place to ensure timely connection?

9. Will a carbon floor price be feasible in the context of EMR and at what level should it be set? (a) It is difficult to see how this proposal is supposed to operate alongside the European Emission Trading Scheme designed to achieve least cost abatement. There will inevitably be public and political outcry from attempts to distort the market. There will be a particular problem if alternative abatement options around Europe lead to lower costs and carbon prices. The carbon price should not be fixed but developments should be promoted through a centralised competitive market for low carbon sources able to establish power procurement contracts on case by case basis.

10. What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets? The development of a European wide EHV super-grid is essential to promote the pan European market and offers the best defence against the abuse of market power. It also offers the best option to accommodate renewable energy sources enabling advantage to be taken of flexible European wide hydro sources. This should be actively promoted through the EU with the North Sea as a starting point. If wind is to be built in Europe it makes sense to build it where it is windiest. The added CCL to fuel used to support generation exports will be counter-productive to encouraging trade and unlikely to be acceptable to the EU. It is likely to encourage more imports and external dependency. Why should European generators generate in the UK when they can generate abroad with no CCL charge but benefit from higher UK market prices? The EMR proposals appear ill considered and will result in billions of pounds of extra costs to consumers and industry during a difficult financial period. More in depth analysis is required to determine the optimum strategy and then propose how it might be implemented. I would be pleased to provide oral evidence if it is considered that the Committee may derive benefit and can confirm that I have no vested interests outside of being a citizen. December 2010

Dr Barrie Murray Electricity market Services Ltd. Barrie is a chartered engineer with more than 30 years' experience working in the electricity energy sector and is the managing director of Electricity Market Services Limited. He has worked around the world on consultancy projects since 1998. He specialises in the provision of consultancy services to major players in cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w4 Energy and Climate Change Committee: Evidence

deregulated electricity markets including market operators, regulators, investors and traders. Skills include the development of business processes and procedures necessary to support electricity trading and system operation, including regulations and commercial agreements associated with the Independent System Operator (ISO) function. He also analyses market operation and develops models and forecasts to support trading and investment appraisal and market development. Prior to working as a consultant, Barrie gained over thirty years' experience in the electricity supply sector having worked in senior positions with ABB, the Central Electricity Generating Board and the National Grid Company plc (NGC). He was the Senior Manager in NGC responsible for establishing the processes and systems necessary to support system operation at the National Control Centre. Barrie played a lead role in enabling restructuring in the UK, having been involved since the inception of the market in 1990, and was responsible for developing systems to support market operation and pricing. He has advised the Regulatory and Consumers Groups on the review of pricing and trading in England and Wales, Belgium, Oman and Ireland. He has advised on electricity restructuring and market development options in South Africa, Abu Dhabi, Sri Lanka, Namibia, Ireland, Bosnia and Hertzgovina and the UK. He has also advised banks, generators and electricity suppliers in the UK, Czech Republic, Holland, Norway, Italy and Ireland on market development and investment opportunities in Europe and Eastern Europe. He has undertaken some 50 consultancy projects around the world and has established an international reputation. He has a ﬁrst class honors degree in electrical engineering, a PhD in Energy Markets, he is the author of two books published by J Wiley on Electricity Markets (Power Markets & Economics 2009, and Electricity Markets 1998), and is a Fellow of the Institution of Electrical Engineers.

Memorandum submitted by Swanbarton Limited 1. Swanbarton Limited is a specialist energy storage consultancy, based in the United Kingdom. Our main area of professional work is the development of commercial electrical energy storage in projects in the UK and abroad. We have taken a leading role in the proposed development of a number of project proposals, and have first-hand understanding of the technical, regulatory and financial thresholds required for the successful implementation of energy storage projects. 2. Today, storage technologies are based upon electro-mechanical, hydro-electric, thermo-electric and electro- chemical processes. While pumped-storage technology might be considered the only mature technology today (in the context of electricity networks), the technical development of the other technologies is at the point where, if revenue uncertainty can be reduced, they could enjoy useful and environmentally-beneficent operation. 3. Swanbarton Limited has contacts with a large number of storage developers and users throughout the world, and is an active member of the Electricity Storage Association. We are responding to this call for evidence to make particular reference to the need for the future electricity market to include the application of electrical energy storage, at all scales. We would be pleased to submit further explanation of our evidence if required.

Main Points 4. There is a body of opinion, nationally and internationally, that storage capacity is vital in the provision of a flexible and low-carbon electricity network. Our business brings us into contact with national and international manufacturers, developers and operators of storage technologies, National Grid Company (NGC) and the regional electricity companies. We strive to solve the economic barriers that these technologies face, today. 5. The benefits of using storage technologies on the power network include: — The ability to provide power for peak demand from energy secured from low-carbon sources rather than peaking plant (which is often, for economic reasons, the most inefficient generation in the whole fleet). — The ability to reduce price spikes, by virtue of energy arbitrage functions. — The capability to address, at least in part, the issues surrounding lulls in wind output. — The capability to integrate an increased proportion of renewable generation onto the network. 6. There are three main barriers to the greater adoption of storage in the UK today: — a lack of demonstration projects, at sufficient scale, which are required to drive down technology costs, provide learning and ready the technologies for widespread use in the coming, decarbonisation years; — an electricity market, with advantages for existing energy resources compared to new entrants; and — the regulatory framework, which limits the opportunity for distribution and transmission licence holders to own and operate electricity storage. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w5

7. Taking into account National Grid’s prediction of the requirement for Short Term Operating Reserve to rise from 4 GW today to 8 GW by 2020,1 the expected increase in negative prices for electricity, and continued demands on the network to incorporate renewable generation and electric vehicles, we see a significant technical requirement for storage, which could be satisfied if the right commercial and regulatory framework was in place. 8. There are a number of UK and EU-based companies in these fields that are at a significant disadvantage compared to US-based companies, which are deploying many practical projects under the US Department of Energy stimulus funding packages (a list of these projects is available for examination).2 The effect has been to support several large-scale projects to demonstrate technology and commercial operation. Allied with these, has been the successful realignment of market rules which started with FERC Order 8903 and rule changes for the New York Independent System Operator and the New England Independent System Operator. FERC Order 890 provides for open access for non generation resources to sell ancillary services (this means that storage and demand-side measures must be treated in the same manner as generation), and the ISO rule changes allow electricity storage to be considered either as a business within the regulatory framework, or to provide an enhanced tariff for storage applications.4 9. With particular reference to the questions contained in the call for evidence our responses are as follows:

What should the main objective of the EMR project be? 10. We should secure environmental stability for the future population. The scale of the change required is enormous and it is vital that the electricity market, as a conduit for energy revenue, is fit for this purpose. Market trading, at present, determines which generation plants are run, scheduling not on the basis of emissions, nor of efficiency but of least cost. The risks are that environmental costs are not properly represented and that new technologies, which might be widely used, are not introduced progressively and there is no action until a critical threshold is reached. Evidence from case studies where storage has been used in conjunction with both conventional and renewable generation, shows considerable reductions in primary fuel use.5 11. The EMR should consider all energy resources, whether or not they are traded on the market today. Examples of energy resources include smart grids, storage units and demand-side responses, as well as the traditional fleet of generators (thermal plants, pumped hydro-electric storage and wind generators). Since the last decade, many engineers have been thinking in terms of resource approaches. The International Energy Agency’s ENARD work programme is one group,6 further evidence can be seen in the topics of the energy- related calls of EU Framework Programme Seven7. 12. We are concerned that, in the policy-options analysis which Redpoint Energy undertook for DECC on EMR, only existing generation technologies are considered. Given the scale of change and the need for new low-carbon technologies to replace old, we suggest that the analysis approach is not completely representative. Progressive actions may be missed.

Do capacity mechanisms offer a realistic way of achieving energy security, low carbon investment and fair prices? 13. Not all the generation capacity that is required needs to be replaced on a like-for-like basis, it should be replaced with a mix of low-carbon generation and other measures such as storage, smart-grids and demand- side management. The market should be changed to ensure that these technologies can compete on a basis which allows decarbonisation goals to be met. Whilst availability and utilisation payments (as used in the ancillary services market for frequency regulation and reserve power) would be beneﬁcial in reducing the risk for new, low-carbon generation and storage plants, it must be ensured that the levels and applicability of these payments is carefully set, potentially with respect to particular groups of technology.

What effects will EMR have on the development of capacity for electricity storage? 14. The effect depends on the policy option undertaken. We have considered the options outlined in Redpoint’s analysis:

Capacity Payments for all low-carbon generators 15. In principle we support capacity payments as a more effective means of ensuring that there is sufﬁcient capacity on the system, which is essential in the provision of security of supply. As much of this new capacity 1 National Grid, Operating the Electricity Network in 2020, Initial Consultation, June 2009. 2 http://www.energy.gov/news2009/documents2009/SG_Demo_Project_List_11.24.09.pdf, accessed 4 January 2011. 3 Federal Energy Regulatory Commission, Fact Sheet, Order 890, available at http://www.ferc.gov, accessed 6 January 2011. 4 Energy Storage in the New York Electricity Markets, available at http://www.electricitystorage.org, accessed 4 January 2011. 5 See for example Emission Comparison for a 20 MW Flywheel based frequency regulation power plant, Beacon Power Corporation, January 2009 http://www.electricitystorage.org accessed 6th January 2011 and Metlakatla—Battery Energy Storage System Replacement justiﬁcation for Commerce, Community and Economic Department of State of Alaska TPS Report 48869. 6 IEA Electricity Networks Analysis, Research and Development, see www.iea-enard.org, accessed 4 January 2011. 7 A useful summary is located at http://docs.energiehelpline.co.uk/2011_Call_summary.pdf, accessed 4 January 2011. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w6 Energy and Climate Change Committee: Evidence

would be the provision of reserve, we expect that this could be provided by energy storage, in small or large-scale. 16. Electricity storage investments are long term in nature, as are most other generation assets, because of the high initial capital cost and long operating life. However while traditional forms of generation can be remunerated by a predictable income stream based on the sale of energy, most storage plants will be remunerated by the price differential between peak and off-peak prices, or by tendering for other services, which is much more uncertain. This uncertainty is reﬂected in higher hurdle rates for the investment, which makes project viability less likely. The provision of certainty in the form of capacity payments would, as Redpoint suggested in their analysis, reduce the risk premia and make these long-term investments more viable.

Carbon Price Support 17. Carbon prices have the greatest effect on generators of bulk power. Storage units provide the capability to meet peak power requirements and by their mere availability, enable more efficient operation of networks. Due to their relatively low hours of operation (reserve and/or peak power requirements only, rather than bulk generation) the carbon price has little effect in the transition from carbon-intensive to low-carbon peaking plant. Our calculations show that a £20/tCO2 increase in the carbon floor would add only £1500/MW/pa to the operating costs of a carbon-emitting oil-fired generator in the reserve power market.

Emissions Performance Standards 18. Emissions performance standards would be designed to affect new fossil-fuelled generators, encouraging the use of CCS, for example. These should not affect storage plants, except for possible applicability to CAES generators. By virtue of their low-carbon generation, these plants are not likely to qualify. On the other hand, the use of CCS to enable fossil-fuelled plants to operate in a low-carbon manner would likely result in less renewable and nuclear generation capacity, hence somewhat reducing the need for storage units in the future.

Fixed Payments for low-carbon generators 19. Provided that storage units are given similar treatment to other generators, a system of ﬁxed payments (in terms of availability and utilisation) could reduce investment uncertainty. To enable investment, long-term contracts should be available. In the case of storage units, the payment system and method of operation of storage units needs to be considered to ensure the most beneﬁcial operation.

Contracts for Difference for low-carbon generators 20. The complexity of a CfD could be a barrier to entry, when compared to a capacity or ﬁxed-payment system. As in paragraph 18, the payment system needs to be carefully considered so that the best use can be made of demand-side and storage units, which can substitute a reduction in load for an increased need for generation.

Feed-in-tariffs 21. The use of feed-in-tariffs is often seen as an inhibitor to storage, as the renewable producer claims an income from selling into the network, and leaves the problem of management of any surplus electricity to the system operator or central buying agency. If a self-producer of renewable energy feeds directly into their own storage device, the FIT mechanism needs to be based on the amount of energy fed into the store, rather then the output of the store (the difference is due to the inherent inefﬁciency of the storage device). An alternative is to create a special FIT allied with a storage device, which remunerates on the output, but at a higher rate. By remunerating the output, it provides an incentive for the storage operator to increase efﬁciency above that expected by the storage FIT. January 2011

Memorandum submitted by Ecolateral Ltd Synopsis This response is submitted on the basis that thinking on this subject has been too narrowly defined by current and previous Administrations, particularly in relation to the potential contribution from carbon based waste material flows in the economy. As a consequence thinking in terms of supply and demand side financial instruments has tended to distort technology preferences, inhibited innovation and created longer lead times than necessary due to the absence of more holistic approaches to renewable carbon feedstocks and their ability to displace fossil coal or gas. These current tendencies in energy threaten a repeat of the intellectual opportunities squandered over the last 10 years in relation to waste and the Committee needs to be mindful of those mistakes. In part this is due to poor understanding of macroeconomic material and energy flows.UK energy demand consumes c60 million tonnes of coal (40 million tonnes of oil equivalent),plus an estimated 70 million tes. of cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w7

LNG (93 mtoe) whilst the UK generates c60 million tes. of carbon based waste each year. This has a calorific value of 8–9 Gj per tonne, 60% of that of coal and 15% of that of LNG. Of 60 million tonnes of waste carbon from households, commerce and industry (this does not include ploughed in farm produce) around 55% is simply landfilled (or piling up in the streets in the case of Birmingham and elsewhere as this response is written!). The balance is used for recycling, soil conditioning and energy (5 to 6 mtoe). Large tonnages to recycling are not a forward certainty in coming years, despite possible complacency in DEFRA. The Chinese are reported to be investing substantially (up to £1 billion) in Material Recovery Facilities in central European Accession states. This is probably to reduce their dependence on increasingly cheap UK materials (due to the 25% devaluation of sterling in the last four years) that apparently represent the UK’s largest single export category to China by value. This movement in sterling has also firmed up dollar denominated oil linked energy costs for UK pulp and other material reprocessors with mixed impacts on recyclate values. The electricity market review is thus germane to the future of this 25m tonnes of material because of forward relative valuations of a tonne of (say) plastic as electrons, material feedstock, gas, heat or transport fuel joules. Indirectly this also impacts the rising costs/income streams of the c12 million tonnes of Local Authority household arisings currently shunted overseas as recyclate to offset £100 per tonne landfill gate fees.

Credentials of the Respondent I have over 20 years experience in the waste sector, most as an Executive Director of a major PlC involved in all aspects of “scrap carbon” management. From 2000 this has involved energy conversion potential from all forms of waste to synthetic fuels, heat, biogas and electricity involving investment of over £100 million in operational facilities. I Chaired a sub group of the SCP Taskforce looking at opportunities for Distributed Energy from waste sponsored by DEFRA and DECC in 2006–08 and am currently Chairing a “virtual” group of energy, waste and energy user companies examining the potential of Gas to Grid systems from large scale anaerobic digestion complexes facilitated by WRAP (Waste and Resources Action Programme). On behalf of Advantage West Midlands I have also facilitated the development of a consultative planning tool to evaluate critically the optimal location strategy for Distributed Energy from Advanced Waste facilities . This tool is currently shortlisted for an Award from the Royal Town Planning Institute .I am also the Mayor’s nominee on the London Waste and Recycling Board. My primary ﬁelds are Economics and Logistics.

General Comments The current Consultations issued by DECC and HMRC on the Carbon floor price and EMR are, taken together, a significant step forward but the reality of their separateness—underpinned by arbitrary distinctions of roles within internal Government Departments—is reflective of the probability that holistic, one stop shop integrated Central Government policy development on energy is still some way off. Economic reality confirms that Government has no cash to fund the £350 billion. Energy infrastructure gap over the next 15 years so why does it continue to carve up the policy goose between DECC, DCLG, Treasury and DEFRA? In the case of the 50 million tonne waste carbon (3GwE minimum capacity equivalent) sector this policy carve up definitely delays private sector investment by increasing implementation uncertainty risks. This is most notable at local level as well with one committee agreeing technology solutions and another in the same Authority refusing planning (Oxford, Worcester, most recently). Such thinking is backward and not energy solutions oriented. From a risk perspective if this investment is to come from private sector balance sheets, (as operators, banks, venture capitalists or pension funds) then investors will demand certainty . Certainty in terms of economics, sound science (in relation to carbon impact assessment), consistency and longevity in terms of support or punitive policy instruments on fossil carbon fuel prices. (in relation to Planning and Economics). In reality the disjointed consultations suggest a continued wish to “divide and rule” the Carbon Dioxide challenge. In terms of ECONOMICS this administration has admittedly inherited yet continued a regime whereby weaknesses in evaluation and risk assessment have created appallingly poor value for money in relation to subsidy/transfer payment support for low output wind turbines which seem to be costing £8 million per MwH capacity or substantially more in terms of on line delivered MwH. Online availability in December of 1.3% suggests that the thinking that went into shaping the support mechanisms was lacking in sound science, intellectual rigour or cross technology market testing. Whilst waste to renewable energy systems (not just thermal but biological and thermo-chemical as well) have investment ratios of £5 to 6 million per Mw E capacity they also convert 15 to 20,000 tonnes of scrap carbon per Mw at an economic income value of at least £1.5 million per MwE. Regrettably this message has been clouded by the waste sector when arguing their case from a narrowly based, low efficiency, incineration platform rather than a more broad based approach to Energy substitution. That position is now shifting as more advanced technologies gain credibility and the majors provide investment in more advanced technologies such as plastics to synthetic fuels. In terms of sound science the profusion of ROCs, FITs, EUTs, and CRCs developed in the absence of an overarching framework of carbon footprinting of the enlarging options on technology has meant that, lemming like, investment has poured into solutions which are economically rather than technologically appropriate. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w8 Energy and Climate Change Committee: Evidence

Turning to Your Speciﬁc Questions (i) Main objective Put simply—“the displacement of fossil carbon fuels by available “scrap” carbon (in the form of waste), wind, wave, renewable gas or heat) at minimum ﬁnancial cost per avoided tonne of carbon dioxide.

(ii) Capacity Mechanisms Given that demand side management is unlikely to deliver the whole rebalancing required at the peak the shift in emphasis to distributed generation is to be welcomed. In the case of waste a forward capacity auction will be a welcome development given that outputs tend to be consistent and regular, albeit with a potential to meet little more than 6 or 8% of mean electrical demand (plus a similar amount for heat depending on technology selection). These advantages are dependent on the qualifications associated with the carbon floor price development (q.v.). Rather than include or exclude specific generation technologies it would be simpler to set a baseline current emissions level (which seems to be around 0.75 m tonnes of carbon equivalent per MwE based on electricity at 30% of total UK emissions for 80 Gw Capacity or 700–750 kt/TwH). There is a need to regulate a new wave of generators in the current way (in terms of operating standards) of course. As to simplification of the support regime all should be charged a carbon tax on total emissions with a rebate on the avoided emissions (700 tonnes per MwE less their audited performance emissions subject to the tax). Rebates at carbon rates of £70 or more per tonne on the gap between actual and target average emissions nationally across the energy mix (a reducing cap) would operate as with other traded pollution permit regimes.

Such an approach also obviates the current spurious distinction between “bad” fossil CO2 and “good” renewable CO2, one which has always been a practical nonsense. All emitted CO2 is bad. The tax may be as per the Treasury CRC linked floor price whilst the rebate could be much higher, (regardless of technology) and recovered from the proceeds of the tax .In the early stages of the mechanism the tax to rebates ratio will be 25 to 1, reflecting the renewables content in total supply (at 4%). This will act as a far stronger carrot to private sector investment in a simple format and will drive the two simple pre- requisites for maximising added value: (a) low overall net carbon footprint for new conversion process systems; and (b) the greatest thermal conversion efficiency from a given tonnage of feedstock input from the selected technology(which is often the major share of the overall footprint). These points are particularly relevant to waste because, whilst they are mechanically reliable and safe, large scale thermal incineration without CHP is barely more energetically efficient compared to clean coal without CCS. CHP is an essential precursor to lowered carbon footprint of course. The difficulty is that heat (which comprises 50% of national energy load with over 70% of that in business and the public sector) is generally only needed in 3 to 5 MwH loads at single points for non household applications. In the absence of heat pipeline networks therefore distributed energy CHP plants powered by waste represent a formidable opportunity in the 1 to 5 Mw load range (20,000 to 100,000 tonne of feedstock). Large scale waste to hydrogen plasma systems sit at the upper end of this efficiency scale and offer storage capability for energy too. Equally direct conversion to transport fuel feed stocks is another option. The higher Capital investment per process tonne coupled to (UK) absence of proven track records is an issue for the Green Investment Bank /Fund to consider in relation to Performance Guarantees from Government- despite firm track records in more advanced economies for these low carbon packages.

(iii) Feed In Tariffs The suggestion above emphasises energy neutrality. Technological evolution is rapid and continuous and defies bureaucratic attempts to shoehorn credit/subsidy based frameworks into chosen exit routes. Such incentives should be based solely on carbon dioxide emissions compared to current overall averages. The rush to anaerobic digestion of waste is appropriate example given that it is without doubt better than the equivalent impacts from landfills. However the financial framework is far more advantageous than the corresponding CO2 reduction impact of the technology from that suggested in the academic literature. Such plants may thus, in the longer term, prove less competitive due to their greater exposure to CO2 emissions taxes compared to more advanced technologies with the possible exception of direct feed of their gas to the gas grid rather than to the electricity grid via IC Engines. (q.v.)

(iv) Speed of Implementation Operationally there is a need to protect Grandfathering of the current jumble of half ROCs, full ROCs, double and 1.5 ROCs plus all other incentives but setting a start date for a single compliance framework is essential. The option for Grandfathered rights to be switched (if based on the DEFRA cost of living indexed £70 per tonne carbon price rebate value as outlined above) might achieve such a streamlining. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w9

In the case of waste as more energy intensive users of energy add up the cost of CRC equivalent charges they become interested in medium sized, low carbon co-located waste to energy CHP plants to supply energy via ESCO type Special Purpose companies rather than be reliant on a (probable) near capacity grid. The proposals in relation to so called negawatts are particularly to be welcomed as a stimulus to this process which will presumably apply to large energy “sinks” such as data centres, docks, airports, hospitals, industrial complexes, food processing centres and the like.

(v) Political Risk

Reform is needed but political risk is exacerbated when the Treasury want to control money flows, DECC wish to control energy flows, DEFRA seek to manage carbon dioxide flows and DCLG seek to control geographic/siting and locational flows.

(vi) Package and Deliverabilty

No. A more comprehensive market approach is called for based on a single measure of CO2 emissions per MwH compared to the national average “cap”. The selected outcomes are far from certain for 2020 in the case of waste because the delivery cycle for much of this infrastructure is at least 30 months or more. Suggestions from the CCC that by 2030 reductions of CO2 need to be of the order of 60% make deliverability even more challenging.

(vii) Synergies and Conﬂicts

The new proposals from the old. On the one hand the old is complex, distorting and scientiﬁcally questionable and the other simple, easy to administer and technologically neutral. An option to sacriﬁce grandfathering on an optional basis could overcome resistance to change. (qv)

(viii) Carbon ﬂoor Price and EMR

At 4% renewables to energy the exposure to transfer payments being onerous for fossil based generators in the early stages is slight (although the implications in terms of fuel poverty policies may be signiﬁcant). As a consequence this suggests a bullish stance on the rebated carbon price which, at levels of £70 per tonne or more, would act as a strong accelerant to investment. Using the Treasury proposals of a £1 per tonne supplement to the current c£13 per tonne price from 2013 and rising to 2020 in annual increments suggest a “refund pool” of almost £1.6 billion for the current achieved/claimed avoided emissions of around 60 million tonnes for early stage movers. As the .renewables switch gathers pace the trend to lowered ratios of actual to avoided CO2 emissions falls and thus will the incentive price as well.

(ix) Energy Storage

Reference has already been made to the pace of innovation and technology change. Nowhere is this more graphically identified than in the case for very large scale (400,000 tonnes per annum) anaerobic digester complexes possibly utilising organic municipal, food chain, commercial and agricultural produce waste to feed gas to grid systems where network losses are a fifth of those on centralised electricity energy grids. “Low carbon” molecules of energy can also be delivered to the home heating network via a store in the form of the gas grid without extensive trench digging. Similarly there is a plant in Planning in the North East for Air Products which is designed to take waste to hydrogen (as a hydrogen/carbon monoxide rich syngas) for use in a combined cycle gas turbine and (in the future once the system is proven) as a road fuel or industrial gas capable of storage at systems efficiency levels of 65% or more.

At a sunk cost of 300 million dollars these are more than mere pipedreams and any future reforms need to be sufficiently holistic to take account of their impact and potential—presumably involving the Treasury and the Green Investment (non) Bank. These storage options are almost certain to achieve lower carbon footprints than pumped water or thermal storage systems. Equally the EMR promises little for interconnector flexibility. Also, as your December report on the Emissions Performance Standard indicated, the design of the EPS needs to be scientifically and critically peer reviewed. Failure will result in a trader’s paradise and unintended technology outcomes. This will be beneficial on a wider platform- there are alledged to be over 50 UK methodologies for carbon footprinting and Corporates are known to cherry pick different ones for different parts of their activity when producing CSR Reports. January 2011 cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w10 Energy and Climate Change Committee: Evidence

Memorandum submitted by CHPA Summary and Introduction 1. The Coalition Government has recently published its consultation on reform of the electricity market. Whilst Government has a clear overarching objective; affordable secure, low carbon electricity, there is an absence of a clear narrative of how the Government will seek to achieve this. The consultation sets out four “tools” for reforming the electricity market but does not set out the detailed issues which it is seeking to address through the EMR. The CHPA recommends that the scope of the EMR be clariﬁed with Government identifying the key issues within the market that it wants to see addressed. Once these have been identiﬁed, the Government can then determine how the chosen policy measures (tools) can be deployed for delivering the energy system that Government envisages for the future. 2. The key issues of market performance that need to be considered in greater detail are:

Demand Side Response — What is the scope for demand reduction, embedded generation and actively managed network infrastructure to take excess power at times of negative power prices, to provide cost-effective system services and limit the requirement for the construction of additional generation and network capacity? — How does the market currently value these services and what changes (if any) need to be made to ensure that these services can play a role where they are cost effective. 3. The CHPA believes that there is a signiﬁcant potential role for new business models that can respond to emerging system requirements and arbitrage opportunities, and that through encouraging the development of this market the Government could limit some of the cost increases associated with a move to a low carbon economy. Whilst the consultation mentions demand-side measures there is a strong focus on new generation which may lead to the potential for demand response from being underexploited.

New Market Entrants — What are the barriers to new market entrants both on generation and supply? What changes to the market are necessary to facilitate new market entry. — What are the key points of contestability in the current market—are these sufﬁcient or should the reform facilitate greater contestability. — Is low market liquidity limiting new entrants through an inability to determine forward prices? 4. The CHPA believes that the current market structure limits the ability for both new market entrants and smaller, independent parties to compete effectively with the established market participants. Although experience suggests that the greatest impact has been upon new suppliers, the scope for generators existing outside of the highly-insulated, Renewables Obligation-subsidised market has been limited since the NETA and BETTA reforms of the early 2000s. The principal barriers to new market entry in the UK market today arise from: — a lack of liquidity and transparency in forward wholesale markets; — considerable and unpredictable imbalance risk; — the two factors noted above combine to inhibit the formation of a reliable reference price for both investment and operational dispatch decisions; — a competitive advantage in addressing these risks for vertically-integrated market participants; and — high regulatory costs and overheads, which afford considerable economies of scale to larger market participants.

The Role of the Energy Consumer 5. The Government’s consultation mentions new support options but makes limited mention of the mechanism by which these would be funded or administered. It is vital that the political acceptability of the move to a low carbon economy is retained and strengthened as increasing prices and new generation assets will inevitably cause some concern. The CHPA believes that there is a need for a clear narrative for consumers about the impact of these actions on their energy bills. More importantly, there should be greater focus upon those mechanisms that will help to insulate customers from the increased costs of new generation investments, most notably through improved energy efficiency and enhanced competition at appropriate, contestable elements of the supply chain. For example, aggregating demand response and small scale- or micro- generation through Energy Services Companies (ESCos) may provide a mechanism for consumers to become more actively engaged with energy issues and help them to benefit financially from the services they can offer. A fundamental commitment to encourage these options within the scope of the EMR may help to limit future public concerns over the costs of the low-carbon transition. 6. An EMR process occurs once every 10 to 20 years and it is vital that Government seizes the opportunity to examine the successes and weaknesses of the current market before proposing how it will facilitate a change cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w11

in the generation mix. The CHPA would encourage the Committee to examine the options for reforming the market fundamentals to help crystallise some of the issues that need to be addressed

Responses to Speciﬁc Questions from the Committee What should the main objective of the Electricity Market Reform project be? 7. The Government has correctly set out overarching objectives for the future of the electricity market; affordable secure, low carbon electricity. Whilst this is helpful, it is too broad to inform the range of interventions that may be needed to deliver on those objectives. The EMR consultation moves from this suite of high level objectives and lands upon the focused target of facilitating new investment in low carbon generation assets, without considering the wider structural market issues. 8. The CHPA recommends that in taking forward its programme of reform, the Government should adopt a more forensic and comprehensive approach in addressing the barriers or limitations that are evident in today’s electricity market place. This should include consideration of: — Price transparency and the availability of a recognised “reference price” against which new investments can be appraised. — The openness of the market to new entrants on both the generation and supply sides of the market. — Wholesale electricity market liquidity. — Imbalance risk. — Consumer engagement. — The pricing signals for demand-side measures and embedded generation. — Practical points of contestability in the supply chain. 9. Whilst the consultation mentions some of these issues, there is an absence of a clear in-depth analysis of what issues exist and, vitally, how structural market reforms could address these. By placing these issues as the central point of market reform, the Government would be better placed to develop proposals for new interventions, such as a Feed-In Tariff. The need for the scale of the interventions proposed may be due to areas of market failure. Addressing the causes of any points of market failure ﬁrst will clarify what additional tools may be needed to ensure that the overarching objectives are achieved.

Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? 10. A capacity mechanism is simply a tool for ensuring that generation assets or demand reduction are available to provide net changes in power demand during a given time period. A capacity mechanism cannot deliver the overarching aims of the EMR. The CHPA believes that Government needs to identify better any market issues and what may be a barrier to energy security, low-carbon investment and fair prices and use the evidence from that to determine what further tools are needed to ensure that the overarching aims are met. 11. A capacity mechanism that incorporates demand response, embedded generation and transmission connected generation within the suite of options to manage grid imbalance (both excess demand AND excess generation as is likely to happen with increasing renewables penetration) will probably be a necessary tool to manage the anticipated future power generation mix. Well designed, a capacity mechanism can contribute to limiting price increases (through demand management services and embedded generation) and carbon emissions (by dispatching capacity services on an emissions based mechanism). Furthermore, by opening up capacity services to embedded generators and ESCos, it may be possible to access an existing market of operators who are able to offer capacity services but for whom the current market arrangements do not offer value on this area.

What is the most appropriate kind of capacity mechanism for the UK? 12. Any capacity mechanism needs to be considered within the context of wider reforms to the market and in particular the approach taken to the wider incentivisation of low-carbon generation. 13. Given the deterministic approach to encouraging low-carbon generation proposed by the Government, with contracts struck with individual generators and with baseload or “must-run” generation dominating the new build, consideration should be given to a focus on availability to dispatch power rather than a mechanism simply based on installed capacity. A system base purely on installed capacity may see payments to generators who are unable to offer capacity services, or who are rewarded twice for providing the same service. 14. Furthermore, in the interests of stimulating competition and encouraging the lowest-cost market response, any capacity market should be opened as widely as possible to allow the full scope of demand response options to play a part in the market. A simple mechanism on generation assets may lead to the development of signiﬁcant numbers of open cycle gas turbine units which would be unlikely to contribute emissions reductions and may not be a cost effective solution. A mechanism that facilitates the use of existing assets, such as CHP units, as well as demand reduction may deliver far better value to consumers for the same impact on gird balancing and frequency. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w12 Energy and Climate Change Committee: Evidence

15. In the future, it is likely that negative electricity prices will be part of the wholesale market. In cases of excess generation, services which absorb excess generation and use it usefully, such as charging electric vehicles and storing energy as heat for use in heat networks, may be required. A capacity mechanism should be designed to provide the ﬂexibility for both excess demand and excess supply.

Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology- based view? 16. The proposed contract for difference feed in tariff (CfD FiT) is an appealing mechanism for delivering low carbon generation and with the right design can facilitate wider market participation, with the corresponding benefit of increasing capital flows. Recognising that there are significant technology, construction and operating risks associated with each of the principal generating technologies which the FiTs regime is targeting it will be vital to ensure that each of these technologies, alongside a wider range of demand-side measures are incentivised under the new arrangements. At the same time it will be necessary to avoid excessive rents, in order to maintain the acceptability of the policy to UK consumers. These considerations would tend to favour an approach where differentiated tariffs are offered to different technologies or measures. The interaction of the new CFD FiT with the current FiT also needs to be considered. 17. A further design consideration will be the determination of the level of capacity contracted under the FiT regime, and the corresponding extent of the capacity market. The more FiT contracts in place, the fewer periods over which participants in the capacity market may be required to operate, so restricting their opportunities to recover costs through generation.

Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? 18. The reform process will take several years. Whilst this may appear a problem, a clear timetable and narrative of what is sought by Government will be able to provide the necessary clarity to prevent a collapse of investment or confidence. Whilst it is important for Government to aim for a quick and efficient resolution of the EMR process, it is vital that appropriate time is taken to develop and examine all proposals. The EMR is a process that occurs every 10–20 years and, as such a long term reform, sufficient time needs to be given to ensure that it will deliver what Government wants. The time spent in designing and implementing a robust and enduring market framework will be rewarded through fewer interventions to correct design flaws once the new arrangements become operational. In this respect, the 2020 timeframes adopted in EU legislation may be acting to compromise prospects for efficient, long-term decarbonisation pathways by encouraging short-term, expedient actions. 19. There has been much focus on the need for certainty for new investors, which is appropriate, but the impact of a rushed reform process could be long term damage to key aspects of a successful market such as liquidity or barriers to new entrants. In the absence of a comprehensive approach the EMR, the CHPA is concerned that the process may become overly-focused on bureaucratic detail, whilst losing sight of the bigger picture.

Will market reform increase political risk for investors or create certainty? 20. It is inevitable that reforming the market will create some degree of uncertainty but it has become clear that the current market arrangements are unlikely to deliver a cost effective decarbonisation of the UK electricity generation mix, in line with UK targets, whilst maintaining security of electricity supplies. As a result, the Government should develop a strategy for minimising uncertainty in the form of setting out a detailed set of metrics to be addressed in the reforms and a reasonable timetable. The lack of clarity for the direction of the EMR and the confused nature of the consultation document has already had a direct impact on the liquidity of the traded market.

Will the Government’s proposed package of carbon price ﬂoor, EPS, FITs and capacity mechanism provide sufﬁcient transformation to achieve goals on climate change, security of supply and affordability? 21. No. The consultation does not comprise comprehensive analysis and steps for market reform. As set out earlier, the fundamentals of the market need to be reviewed and examined. Based on the analysis of the function of the market fundamentals, Government needs to determine what reforms need to be implemented to ensure that the market will function both now and in a low carbon generation scenario. Once these have been established that Government may best consider what additional interventions are required to secure low carbon investment and security of supply.

What synergies and conflicts will there be between proposed mechanisms and policies already in place? 22. There is the opportunity to develop synergies between new policies and existing structures but it is not possible to define these (or the potential conflicts) without greater detail. 23. The most significant interface issue is that which lies between the contracted FiT market and the proposed capacity market. The greater the level of volumes potentially contracted for under the FiT regime, so the smaller the volumes traded in the capacity market and the greater the prices that will need to be offered to cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w13

capacity market participants to make capacity available and respond to system requirements. In an extreme situation, with excessive volumes of “must-run” FiT-rewarded generation, the capacity market will be dominated by ﬂexible generation reducing output and by energy storage. A major challenge for the Government will lie in achieving the optimum balance between incentivising low-carbon generation and low-cost response.

24. The proposed level for an emissions performance standard will have limited, if any, impact on the status quo. The interaction of the CfD FiT and any capacity mechanism will be vital to the effective operation of the market and delivering value for money to consumers but this is not examined by the consultation.

Will a carbon ﬂoor price be feasible in the context of EMR and at what level should it be set?

25. The proposed carbon ﬂoor price is a feasible mechanism for Government although it has several key issues that need to be considered.

— As a mechanism for providing a minimum carbon price that passes through into the wholesale electricity market, it is appropriate that only fuels used to generate power pay the carbon price levy. This may appear self-evident, but it is the case that the Government’s proposals for Carbon Price Support include proposals to impose the carbon price levy on fuels used to generate heat in combined heat and power plants. This situation creates an unmanageable cost risk for CHP operators which may cause them to cease operating in CHP mode, leading to a direct increase in UK emissions.

— The interaction of the proposed mechanism with the EU Emissions Trading Scheme may create signiﬁcant issues for future interconnections with the continent as there will be a carbon price disparity. This could lead to an increased drive to import power as it may have a lower cost.

— A carbon support price mechanism will only lead to cost pass through (to the wholesale market) during periods when fossil ﬁred plant is the marginal (price setting) plant. With a predicted increase in power generation from low carbon sources, it is likely that there will be periods when non-fossil plant operates as the marginal plant. The result will be no carbon cost pass-through to the market and the loss of the intended signal from the carbon support price.

What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets?

26. The EMR proposals set out by Government set out the value and theoretical options for both interconnectors and storage but there are no detailed proposals on how new capacity in these two areas will be brought forward through the EMR. In addition, the discussion of storage is primarily limited to pumped storage for which there is limited opportunity for expansion.

27. The CHPA believes that storage both pumped storage and other means such as thermal storage will have an increasingly important role to play within the electricity market but there needs to be a clear examination of the role that it can play and what value it can contribute. The fourth chapter of the Government’s consultation sets out a range of options that can be considered for managing the change in generation mix but there is an absence of analysis as to the value that these options present, the saleability of these options and what (if anything) in the market needs to change to ensure that these services are valued sufﬁciently for them to be provided.

28. The CHPA recommends that the Government commissions an examination of the potential for the fullest range of demand side response measures (including embedded generation, demand reduction, use of excess generation and localised balancing services) and a cost beneﬁt analysis of what these may offer a more diverse and unpredictable energy mix. The CHPA notes that opening up of the Danish district heating market to provide services to accommodate variable power generation has dramatically smoothed power prices and facilitated much needed system balancing. As part of such a review, the potential costs and beneﬁts of moving to a system of actively managed electricity distribution networks (DNs) should be examined. The CHPA believes that there is substantial opportunity to save costs by reducing the level of infrastructure development required for DNs by moving to a system of active management. Such cost savings may be key to limiting the rise in customer energy bills and hence, retaining vital political acceptability for energy decarbonisation. January 2011 cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w14 Energy and Climate Change Committee: Evidence

Memorandum submitted by Westinghouse About Westinghouse Westinghouse Electric Company, a group company of Toshiba Corporation, is the world's pioneering nuclear power company and is a leading supplier of nuclear plant products and technologies to utilities throughout the world. Westinghouse supplied the world's first Pressurised Water Reactor in 1957 in Shippingport, Pennsylvania. Today, Westinghouse technology is the basis for approximately half of the world's operating nuclear plants. Westinghouse is headquartered in Pittsburgh Pennsylvania and employs around 15,000 people around the world—around 30% of them in Europe. The company has three core business areas—nuclear fuel, nuclear reactor services and nuclear power plants. Four Westinghouse AP1000 reactors are currently under construction in China—two on the Sanmen site and two on the Haiyang site. Construction on all four plants is on schedule and the first of these plants, at Sanmen, will send its first electricity to the Chinese grid in late 2013. Additionally, six AP1000 plants have already been ordered by customers in the US, with more in the planning stage. UK regulators are currently in the closing stages of assessing the Westinghouse AP1000 in detail to determine if it meets the UK’s safety and environmental requirements. Westinghouse has recently moved to a Regional organisation, reflecting the growing importance of business outside the US. One of the three regions is Europe, Middle East and Africa, and within that region, the UK is a key market. In the UK Westinghouse runs the Springfields site in Preston, Lancashire (where around 1650 people are employed), and the company recently agreed a 150 year lease to operate the site on behalf of the Nuclear Decommissioning Authority. The vast majority of the UK’s nuclear fuel has been made at Springfields, over a period of more than 50 years.

1. What should the main objective of the Electricity Market Reform project be? The electricity market reform should be designed to deliver an electricity market which balances reliable supplies, low carbon emissions (throughout the full lifecycle of generation) and affordable electricity prices— both for domestic and commercial users. In practice, this means giving clear signals to potential investors that selecting options which are low-carbon and/ or capable of providing reliable supplies will be rewarded in the future market framework. The mechanism adopted must recognise that many potential investments are long-term in nature (for instance nuclear projects will not generate electricity for 8–10 years, and then will operate for 60 years or more). They therefore need to offer policy stability over a period of decades. However it is not necessary to have speciﬁc detail on the exact level of market incentives out this far ahead—simply the conﬁdence that the market framework itself will prevail and an indication of the levels of incentive being proposed. A market-based approach within these constraints is important—so that whilst low carbon generation is prescribed by the market, it should then be left for the alternative low-carbon options to compete as far as practicable. In this way the technologies selected should represent the most cost-effective means of achieving the desired outcomes.

2. Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? Capacity mechanisms are certainly helpful in delivering electricity security, which itself is an important component of the wider energy security objective. It is ultimately the level of payments made under such a scheme, coupled with the balance between capacity mechanisms and other market features, which will determine whether the overall approach can deliver the combined objectives of security, low-carbon and affordability.

3. What is the most appropriate kind of capacity mechanisms for the UK? We have no strong views on this matter—except that the mechanism adopted must be sufficient (along with others) to give confidence to investors that the benefits of large-scale, low carbon generation will be recognised and rewarded.

4. Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology-based view? We have no strong views on this matter—but we believe that UK interests are best served by having a balanced mix of low-carbon technologies, and so the system should not preclude the development of any low- carbon technology which could—in time—become a cost-effective part of such a mix. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w15

5. Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? We have no strong views on this matter. However the approach taken must be sufﬁciently clear that investors may have the necessary conﬁdence in the future shape of the market to proceed in the short term with development plans and, in due course, investments to bring forward suitable generation capacity. In many cases—where the plants will not themselves be on the grid for 8–10 years, the actual timing of market mechanisms themselves is less important than the strong signalling of their future existence.

6. Will market reform increase political risk for investors or create certainty? We believe that electricity market reform, if carefully planned and developed with cross-party input, is an important cornerstone of the work to deliver a 21st century energy market in the UK, which balances secure supplies, affordable prices and substantial reductions in carbon emissions. If developed in this way, we believe that it will provide a strong level of conﬁdence to potential investors, which in turn will help them to make the right investment decisions to bring forward that outcome. With that in mind, we welcome the ECC Select Committee’s work to bring cross-party insights to this important issue.

7. Will the Government's proposed package of carbon price floor, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? The mechanisms are all important, and will all be helpful in allowing potential investors to have confidence that reliable, low-carbon generation will be rewarded in the future. The extent to which the mechanisms are sufficient to impact on decision making will depend not just on the shape of the mechanisms but on the associated numerical values. A carbon floor price, for instance, is largely worthless if the price itself is trivial. That said, we note that these mechanisms are all typical of the suggestions which potential utility investors have discussed as being helpful, so we have confidence that the direction being mapped out is sensible. We also note that some utilities have talked of a reformed Renewables Obligation—to become a “low carbon obligation”, and again we can see value in such an approach if carefully implemented to ensure that a good number of renewable projects are still brought forward. For instance a “Low-Carbon Obligation” within which some segment was “ring-fenced “for renewables only, and some of which was opened up to any low-carbon technology, would be an option.

8. What synergies and conflicts will there be between proposed mechanisms and policies already in place? We believe that it is possible to implement the proposed measures without undue conflict with existing ones. In this respect, there are two important areas: Firstly—care must be taken in bringing forward the carbon floor price to ensure a smooth fit with the existing European Emission Trading Scheme. It is important neither to destabilise the ETS, nor to render the UK an unattractive location for investment. Secondly—existing power generation projects, and those which are already well advanced, must not find themselves “stranded” in the move to a new regime. Such a situation would not be conducive to inspiring confidence in future investments (particularly those with long timescales for payback). We believe both of these issues can be managed if carefully considered.

9. Will a carbon ﬂoor price be feasible in the context of EMR and at what level should it be set? Westinghouse are not aware of any reason why a carbon ﬂoor price should not be feasible in the context of EMR, if carefully implemented. The level of such a price—and how the price will vary over time for years to come—is a matter for Government, having due regard to the insights of the utilities and other market experts. January 2011

Memorandum submitted by the Nuclear Industry Association The Nuclear Industry Association (NIA) welcomes this opportunity to provide written evidence to the Committee on this issue. The NIA is the trade association and information and representative body for the civil nuclear industry in the UK. It represents over 250 companies operating in all aspects of the nuclear fuel cycle, including the current and prospective operators of the nuclear power stations, the international designers and vendors of nuclear power stations, and those engaged in decommissioning, waste management and nuclear liabilities management. Members also include nuclear equipment suppliers, engineering and construction ﬁrms, nuclear research organisations, and legal, ﬁnancial and consultancy companies. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w16 Energy and Climate Change Committee: Evidence

Some of our members, particularly those participating in the UK nuclear new build programme, will be making their own detailed responses to the Committee. The purpose of this NIA response is to make some higher level points on the key issues identiﬁed by the Committee.

What should the main objective of the Electricity Market Reform project be? The electricity market reform should be structured to produce market conditions which incentivise and reward those generation characteristics it is government policy to deliver. To reﬂect the long-term nature of the investments it should provide policy stability over an extensive period. The key outcomes should be the incentivisation of new plant, including low carbon, reliable and secure generation, at the necessary capacity to help maintain the UK as a modern cutting edge economy. It is important that the reform should continue a market-based approach, where strong competition will lead to the least cost to consumers.

Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? Capacity mechanisms are one of the possible ways of creating a ﬁnancial incentive for utilities to develop the large scale generating capability which the government wants the private sector to provide for the UK. The proposals put forward by government are one possible way of achieving this, and NIA will comment more on those issues in our response to the DECC consultation on EMR.

What is the most appropriate kind of capacity mechanisms for the UK? This is more an issue for the relevant utilities and Government than for the NIA.

Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology- based view? Again this is more an issue for the utilities and Government than for the NIA. Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? This will depend on the model of measures selected, and again is more an issue for the utilities and government. Nonetheless it is important that the measures chosen are consistent and compatible, and implemented in a way which does not negatively impact on certainty, market conﬁdence or clarity. It is particularly important, as mentioned above, that the package should provide policy stability over an extensive period.

Will market reform increase political risk for investors or create certainty? A properly conducted and effective EMR is an essential pillar in the government’s work to create a market framework where investors can have certainty that their investments will be proﬁtable in the long-term. It is also critical to meeting the government’s goals on carbon emissions and security of supply.

Will the Government's proposed package of carbon price ﬂoor, EPS, FITs and capacity mechanism provide sufﬁcient transformation to achieve goals on climate change, security of supply and affordability? These are all valid measures and will play an important role in delivering these key aims. Whether they alone are enough is a matter for government to discuss directly with relevant utilities.

What synergies and conflicts will there be between proposed mechanisms and policies already in place? Whichever mechanisms are ultimately selected, they must be structured to avoid conflicts with new or existing mechanisms. It will be important that the carbon floor price works properly with EU ETS. The EMR must result in a market where government aims are properly rewarded in the market framework and there is certainty and clarity for investors.

Will a carbon ﬂoor price be feasible in the context of EMR and at what level should it be set? There is no reason in our view why a carbon ﬂoor price should not be feasible. The level at which it is set is a matter for government, utilities and economic analysts to decide as appropriate.

What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets? This is not an issue for the NIA. January 2011 cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w17

Memorandum submitted by the Renewable Energy Association 1. Introduction 1.1 The Renewable Energy Association is the largest renewable industry body in the UK, with over 650 corporate members. These companies are active across the range of renewable electricity, heat and transport technologies. The core membership we seek to represent is renewable energy producers, fuel providers, energy equipment manufacturers, installers and project developers. We also have many corporate members with interests in these areas, but whose core business lies elsewhere. 1.2 We are grateful for the opportunity to give evidence to the Environment and Climate Change Select Committee. We have not addressed each issue in turn. Most of our focus is on the Feed in Tariff Contracts for Difference proposal, but we also comment to a limited extent on the capacity mechanism and the need to harmonise with Europe in the context of paying for networks. 1.3 Due to government’s consultation only having been published on 16 December, we have not had time to consult our members on the proposals and the members have had limited opportunity to comment on this written evidence.

2. Objectives of the Electricity Market Reform Project 2.1 We welcome government seeking a secure, low carbon and low cost energy future. The UK has been a laggard in deploying renewable energy and our uncertain policy environment has increased costs to the consumer. Government needs to set out a clear path to a decarbonised power sector by 2030 and end the discrimination against investment in efficient local electricity generation. The transition and maintaining investor confidence is all important in any proposed reforms. 2.2 From the renewables perspective, the main objective of the EMR should be ensuring that the contribution from renewable electricity is sufficient for the UK to meet its overall target of 15% of energy from renewable sources by 2020. This is a legally binding target and forms the UK’s share of the overall EU-27 20% renewable energy target. The previous government and the coalition government anticipate a contribution of around 32% of renewable electricity is required8.

3. Revision of the Renewables Obligation and the Feed-in Tariff system 3.1 The Renewables Obligation is the main mechanism for increasing deployment, and this has been relatively successful since its introduction in 2002. It has undergone significant changes since then, and is currently facing a particularly challenging period in the run up to the first review of banding levels. Banding was introduced in April 2009, and prior that each MWh of electricity earned 1 Renewable Obligation Certificate. From April 2009, different technologies have been placed in bands which earn more or fewer ROCs per MWh according to their estimated levelised electricity generating costs. DECC employed consultants to advise on banding levels initially, and consultants are now looking at whether these need revising according to a set timetable of review every four years. 3.2 The intention is that new bands will come into effect on 1 April 2013. Many generators are experiencing difficulty financing their projects at present, due to uncertainty about future banding levels.

Transition 3.3 A transition away from the Renewables Obligation to a system of Contracts for Difference for Feed-in Tariffs is a dramatic change, and whilst the industry has had some months to come to terms with the concept, which was announced in the coalition agreement, there is considerable wariness. 3.4 The concept of a stable 20-year contract for difference for renewable generators is not unattractive. Indeed it has a great deal of merit, both for generators and for the public. DECC's reasons for wanting to make this move are commendable. The REA’s concern is how the change is implemented. Project developers must have certainty in the process leading up to the awarding of these contracts as well as in the contracts themselves. Indeed it is the difﬁculty of achieving the process certainty rather than the contract certainty that concerns us more.

Feed-in Tariff Contracts for Difference proposal 3.5 The Government’s lead option is for a feed-in tariff with a contract for difference (CfD) on the electricity price. There are a number of design and implementation issues which need further consideration. If the proposal is to deliver the beneﬁts set out in the document getting the detail right will be essential. 3.6 The proposed feed-in tariff is a move towards general low carbon generation support, as opposed to speciﬁc renewable support mechanism. It is vital that a banded and wider technology based view is maintained, in order to ensure delivery of the 2020 renewables target. 8 Renewable Energy Strategy, DECC, July 2009 (http://www.decc.gov.uk/en/content/cms/what_we_do/uk_supply/energy_mix/ renewable/res/res.aspx) cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w18 Energy and Climate Change Committee: Evidence

3.7 Under the proposals set out in the EMR, either the contract prices are to be set by competitive tendering (auctioning) or will be ﬁxed by government (seeking the advice of consultants). The auctioning approach is favoured by Chris Huhne. Under either method process certainty for developers is essential. We outline below issues that must be taken into account.

Process certainty if CfD prices are ﬁxed through consultation

3.8 Some Renewables projects take 3—5 years (occasionally more) to develop. Once a price is set, Project developers need to have confidence that the process will see them right through the period to commissioning and that the goalposts will not be moved before they get there. If prices are reviewed on a timetable that does not allow projects sufficient time to be confident of commissioning, the support regime will be totally ineffective.

3.9 We are beginning to see this problem now with the Renewables Obligation (RO). The RO has been in place for 8 years and not one year has gone by without it being tinkered with. We enclose a paper on “grandfathering” that sets out the particular problem faced by generators with long lead times.

3.10 The Government has acknowledged this and has brought forward the timetabled review of banding levels for technologies under the RO, so that the results will be known by summer 2011. If developers are conﬁdent that the prices signalled next summer will become reality in April 2013, then they will have a window to develop their projects lasting from July 2011 to 2017, which should be sufﬁcient. Given previous experience of the Obligation, however, may lead them to be more cautious and wait until the legislation is actually in place, which gives only a 4 year window.

Process certainty if CfD prices are ﬁxed through auction

3.11 Prior to the RO, the policy for the deployment of renewable electricity generation was the Non-Fossil Fuel Obligation (NFFO). This was a competitive tendering regime, having many similarities with the new proposals. It ran from 1990 to 1998, during which there were ﬁve tendering rounds in England and Wales and three in Scotland. Many of the REA’s members have experience of tendering for contracts under the NFFO.

3.12 The climate was very different in the 1990s: — We did not have the beneﬁt of a large, legally binding renewables target to meet. — There was no sense of being on a trajectory whereby renewables are set to become a mainstream component of the electricity market; therefore. — Each round of the NFFO felt to the participants that it might well be the last.

3.13 Despite this, the NFFO gives some very important lessons on auctioning contracts, some of which are outlined below. — Auctions must be frequent and regular, with a timetable stretching out years—preferably decades— in advance. And generators need to be confident that the regime will be stable. — The pre-conditions need to be set out clearly. If the rules require projects to have all consents in place prior to bidding, (ie only those that are ready to go can enter) then companies will only engage in the auction if they are confident of winning a contract in due course. If little is needed in advance, then there must be mechanisms in place to clear out speculative bids that have no likelihood of reaching fruition. — If the projects do need to be well advanced prior to bidding, there is the danger that there would be few of them participating in the early rounds, which could lead to price distortion. — It would be unworkable to also have penalties for non-compliance, as funders would not be willing to accept additional risk of penalty for non-delivery on the contracts. — If bidding took place in bands, eligibility would have to be wide in order to not stifle innovation, yet precise in order that any competition is fair. — Developers would need to know that the band they are bidding in to be likely to award enough capacity for them to feel it worthwhile bidding. — A mechanism would have to be found to prevent speculators, or those with the malicious intention of sterilising the process, who have no intention of building projects, flooding the bidding. — The mechanism would have to cater for a wide range of technologies, at very different stages of commercialisation. The needs of established technologies are very different from emerging technologies. The mechanism would need to span innovative marine renewables, where devices are still being developed (and where the UK has a lead which must be nurtured) to mature renewables such as onshore wind. This would be challenging. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w19

3.14 It is essential that the lessons of the NFFO are heeded, if the UK is to return to a competitive tendering process for the allocation of contracts.

4. Capacity Mechanism 4.1 Government is consulting on introducing a capacity mechanism to explicitly reward the provision of capacity, this mechanism should also be designed to reward demand-side response. 4.2 Firstly, the renewable element of the value stream is likely to be of significantly more value than the capacity payment, and secondly there is very little detail in the consultation document. Therefore our comments are limited. 4.3 We support renewable generators having access to capacity payments, and we would expect them to benefit to the extent that they can control their generation. Those that are flexible and can choose when they generate will benefit more. With the exception of biomass projects, most renewable generators are limited in their extent to do this, those that depend on variable energy sources cannot be relied upon beyond a statistical degree to be able to generate at any particular moment; those that generate electricity from wastes streams can usually be relied upon to generate, but have limited flexibility as they will have a continual stream of material that they must deal with. We would support cost-reflective capacity payments, and want to see those renewables that can benefit from them, doing so.

5. European context 5.1 In order to facilitate the transition to a low carbon energy future and to achieve this at reasonable cost, it is widely acknowledged that increased interconnection throughout Europe is desirable. In addition the EU objective of a common European energy market is making progress and a number of European Codes covering all aspects of the electricity and gas markets will be developed over the next few years. 5.2 It is therefore extremely important that UK electricity trading arrangements are compatible with whatever common arrangements emerge throughout Europe. If the European dimension is ignored there is a risk of giving unfair advantage to low carbon generation in elsewhere of Europe at the expense of those in the UK, where the natural resource may be better. 5.3 An example of the systematic disadvantaging of generation in Great Britain compared with most other parts of Europe is the proportion of the network costs that are borne by generators as opposed to demand customers. When considering all network related charges (including Transmission Network Use of System Charges, Distribution Network Use of System Charges, connection charges, charges for transmission and distribution losses and Balancing Services Use of System charges) it is clear that the charges in Great Britain are on average considerably higher than elsewhere in Europe. This systematically disadvantages generators in Great Britain and renewable generators in particular. January 2011

Memorandum submitted by ESB International

1. ESB International (ESBI) welcomes the opportunity to provide views in response to the Committee’s inquiry on electricity market reform. The challenges facing the energy markets over the forthcoming years are signiﬁcant and the structure of those markets will play a major role in achieving Government policy objectives. The points raised in the Committee’s call for evidence are therefore timely and particularly pertinent. 2. This response provides a brief introduction to ESBI and a summary of our views, followed by more detailed responses to the speciﬁc questions posed by the call for evidence.

ESB International 3. ESBI has been a developer and operator of independent Combined Cycle Gas Turbine (CCGT) generation projects in the GB market for over 15 years. We currently have equity interests in Corby power station and in the 850MW development at Marchwood, which commissioned late last year. We are highly advanced with our latest 860MW development at Carrington which is intended to become commercially operational in 2014. We are also developing further large-scale CCGT developments at other locations across GB.

4. In addition to increasing our conventional generation ﬂeet, we continue to grow our position in the UK wind market. We operate the 24MW West Durham Wind Farm in Northern England, as well as the 20MW Hunters Hill and 15MW Crockagarron projects in Northern Ireland. We are currently also constructing what will be England’s largest onshore wind farm, at 66MW, at Fullabrook in Devon. Further, we expect to start construction of our 38MW Mynydd y Betws Wind Farm in South Wales later this year. We are also active in the tidal energy sector. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w20 Energy and Climate Change Committee: Evidence

Summary of Views 5. This section is a high-level summary of the views expressed in the more detailed responses to the Committee’s specific questions. — The proposals contained in DECC and Treasury’s consultation documents comprise fundamental changes to the operation of the GB electricity market. The introduction of a package comprising of a FiT, EPS, carbon price support and a capacity mechanism will support the delivery of the Government’s energy policy objectives, however the success of the package will depend on its specific structure. — The delivery timescales are challenging and come at a time when investment needs to be made, if environmental and security of supply targets are to be met. In order to limit investor uncertainty, Government must provide clarity on the intended solutions at the earliest opportunity, clearly define transitional arrangements and must demonstrate consistency of purpose over the long-term. — There remain questions as to how the new arrangements would work in detail and also interact with existing market mechanisms. In particular, we are uncertain as to how the tariff levels would be set under a new FiT mechanism and how any new mechanism would interact with a grandfathered RO mechanism in support of low-carbon generation technologies. — ESBI welcomes the Government’s commitment to maintaining competitive wholesale markets and its recognition that the market reform proposals need to be underpinned by significant improvements in wholesale market liquidity. We would seek for Government or Ofgem to publish further thoughts and proposals at the earliest opportunity. — Any market intervention must be introduced to remedy specific market deficiencies. Each element of the package must be developed and introduced as a compatible and complementary suite in order for the high-level objectives to be achieved. For example, capacity mechanisms should be used to ensure future security of supply and should not be used to drive low-carbon generation development.

Responses to Questions This section provides ESBI’s views on the speciﬁc questions raised in the Committee’s inquiry.

What should the main objective of the Energy Market Reform project be? 6. Energy market mechanisms should be designed to facilitate the achievement of Governmental policy objectives. As such, the aims of the Energy Market Reform (EMR) project should be consistent with Government’s stated objectives of affordably meeting the legally binding carbon reduction targets, whilst ensuring security of supply. We are strongly of the view that, wherever possible, this should be done within the context of competitive markets which provide opportunities for independent and new entrant players, hence minimising the overall cost to consumers.

Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? 7. Capacity mechanisms, in varying forms and to varying degrees of success, have been used in electricity markets across the world and are generally adopted on the premise of securing supply. This is by providing specified price and/or investment signals to generators to provide appropriate levels of capacity in the future. The Committee’s question suggests that it is perhaps of the view that a capacity mechanism could be used to deliver a range of policy objectives, rather than focus on security of supply. We strongly believe that the purpose of each policy intervention should be well-defined and focused. The call for evidence discusses other market interventions such as Feed in Tariffs (FiT) and Emission Performance Standards (EPS) which are more appropriate tools for reducing carbon intensity. 8. The low carbon generation technologies that will deliver the required reduction in carbon emissions will be primarily renewable (in particular onshore and offshore wind), new nuclear and carbon abated forms of thermal generation. Although these technologies are low carbon, they are all also inherently inflexible and therefore unable to react to demand variations. An effective capacity mechanism could ensure that sufficient flexible generation is available to meet peaks in system demand in a market providing significant support mechanisms to low carbon technologies. By this role, an effective capacity mechanism can facilitate the objectives of lower carbon generation, security of supply and affordable prices.

What is the most appropriate kind of capacity mechanism for the UK? 9. Were a capacity mechanism to be introduced, it must provide appropriate signals for capacity that is required to meet peak system demand in the future market containing significant amounts of inflexible, low- carbon generation; the signals would need to be sufficient to support investment in new capacity as well as for retention of relevant current capacity. As such, we are strongly of the view that any mechanism must recognise fully the value of flexibility, as well as capacity. Further, it must provide sufficiently long-term and secure cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w21

financial returns to generation developers. Investment decisions would be affected if the signals were short- term or if the signals contained any inherent instability. As a company with existing generation and development projects, we would be particularly concerned if the capacity mechanism eroded the vital role that flexible, high efficiency, lower-carbon, gas-fired generation plays in the generation mix now, and in the future.

10. The GB energy markets are some of the most liberal in the world. We believe that any GB capacity mechanism should be complementary to the current liberalised bilateral market arrangements and, wherever possible, better promote liquidity in the wholesale energy markets.

11. We welcomed the Government’s initial proposals in the EMR consultation regarding its preferred option for a future GB capacity mechanism. In general, given the current GB market design we see merit in the Government proposals for a capacity payment mechanism that: — is targeted, rather than offering payments to all generators; — is based on a market derived price for a given volume of capacity, rather than a price established by a regulatory body; and — contains a volume for capacity that is derived by a coordinated administrative process.

12. In order that a competitive, bilateral wholesale market can thrive, we welcome Government’s preference to keep the generation contracted within the capacity mechanism separate from the existing wholesale and balancing markets. We recognise that this option will require careful market design but believe that it could be a workable option. The Government’s EMR consultation does not specify what types of plant the mechanism would incorporate. We are of the view that the mechanism should be open to both new and existing generation plant and would seek for Government to provide clarity on this point at the earliest opportunity.

13. The so called “last-resort” model, whereby the capacity mechanism is only called upon when all other market options have been used, would preserve market-based investment signals and would produce more efﬁcient, economic outcomes. To this end, we very much welcome Government’s recognition of the existing problems with liquidity and its requirement for Ofgem to address them in timescales consistent with the EMR. We would, however, seek that Ofgem or Government provide proposals as soon as possible, in order that respondents to the EMR consultation are able to take a more informed view on the full range of possible reforms.

Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider-technology- based view?

14. In our view, Feed-in Tariffs (FiTs) should contain technology differentiation. The level of each FiT should be determined by the costs speciﬁc to each type of low-carbon technology being supported by the subsidy. They should not, however, be further differentiated by location as this could result in less efﬁcient outcomes by promoting yet higher cost generation at the expense of more economic outcomes.

15. In setting the FiT for each technology, we would seek that Government undertakes a transparent and robust process. We are concerned that an opaque process for determining the FiT, undertaken between Government and generators, could lead to inefﬁcient and costly outcomes whereby the FiT produces inappropriately high rewards for certain technologies or for speciﬁc projects. This is particularly the case for technologies in which there is currently uncertainty in the development and operational cost bases, due to the nascent nature of those technologies (such as the next generation of nuclear plant and offshore wind generation).

16. Whilst the EMR documents contain some information on the Government’s views of which FiT it believes would best suit the requirements of the GB market, there is a further level of detail required before industry is able to decide on the most appropriate model. In particular we look to Government to further elaborate on how the FiT strike price or premium will be set. In particular we would recall the experience of the later rounds of contract auction under the Non Fossil Fuel Obligation process, which led to undeliverable projects securing contracts and hence precluding deliverable projects from securing contracts. We would therefore seek for the Government to give careful consideration to the methodology for deriving the strike price or premium for whichever FiT model is chosen.

Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time?

17. We envisage the changes to be delivered by EMR to be wide-ranging and fundamental. If the goals of the reform are to be met (ie the delivery of an affordable, secure and lower-carbon generation mix), the changes must be completed as soon as possible, in order that investors have the clarity and stability they require. As such, we would seek that the EMR be introduced in one go or at the very least against a clear and defined timetable which matches the requirements of Government and industry. If phased, Government could choose to recognise the build processes and timings for new technologies, such as the new nuclear fleet and deployment stage of carbon capture and storage. However, Government must ensure that an expeditious timetable does not compromise the integrity and rigour of the final model. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w22 Energy and Climate Change Committee: Evidence

Will market reform increase political risk for investors or create certainty? 18. If political risk is to be deﬁned in terms of political intervention in the market, then EMR has introduced material, albeit hopefully short-term, political risk. As previously stated, we would seek that Government introduces any reforms quickly and for those changes to be robust and able to deliver the challenges the energy markets face over the forthcoming years. If these requirements are met, we would expect the risk of future political market intervention to be signiﬁcantly reduced. 19. We note, and welcome, that there are elements of the Government’s proposals that (if implemented) would reduce the amount of risk associated with investments recently and currently being made. In particular, statements made on the grandfathering of RO arrangements for existing and soon-to-be developed projects and the non-retrospective application of EPS provisions were especially welcomed.

Will the Government’s proposed package of carbon price, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? 20. The package is both wide-ranging and fundamental. The proposals have the scope to deliver sufficient change to facilitate the delivery of Government’s goals for carbon reduction and security of supply. We are uncertain, however, whether they will result in a more affordable energy future. The amount of investment required to deliver the carbon reduction necessary to achieve Government’s objectives, is significant. It consists of both generation and infrastructure investment, which will have to rise to unprecedented levels, widely estimated to be in the region of £200billion. Coupled with this are the support mechanisms proposed within the EMR, which will result in increasing wholesale prices resulting from additional energy taxation and consumers having to fund various direct subsidy payments. We are of the view that Government should further address affordability as the EMR process continues through its various stages. 21. For the package to deliver its goals, Government must state what its intentions are for each element of the EMR and ensure that those intentions are not confused or diluted. Each element of the package (carbon price support, FiT, EPS and capacity mechanism) must be developed and introduced as a compatible and complementary suite in order for the high-level objectives to be achieved. We would seek that Government ensures this happens as a priority. 22. Further, there is a significant level of detail that must be developed before we are able to judge whether the reforms will deliver the intended outcomes. We welcome Government’s commitment to implementing changes by April 2013 but would urge for more details of the mechanics of the proposals to be published at the earliest opportunity, along with well-defined implementation timescales. This will reduce uncertainty investor uncertainty and ensure help ensure there is no investment hiatus.

What synergies and conﬂicts will there be between proposed mechanisms and policies already in place? 23. As discussed previously, we strongly support the maintenance of the liberalised, competitive wholesale market. Government rightly raises liquidity in the wholesale market as an issue that must be addressed for its proposals to be successful. As an independent generation company, we are acutely aware of the impacts that low liquidity brings and welcome Government’s statements on improving it within the timescales of the EMR. The “FiT with contract for difference” mechanism that is favoured by Government relies on a transparent and robust wholesale price, driven by generation cost. We would support any initiatives that help deliver this and believe it is a key interaction/requirement of the Government’s proposal. 24. We welcome Government’s intention to grandfather the arrangements for existing and current development projects that are accredited under the RO. However, for this to work, thought needs to be applied to how projects receiving support under the RO interact and are kept “whole” relative to those that will be supported under a future FiT. It is essential that these arrangements are clariﬁed as quickly as possible to ensure that uncertainty is minimised for projects negotiating, and entering into, power offtake agreements now. 25. The carbon price support proposals (based around the removal of Climate Change Levy exemptions currently applied to fossil fuel generation) must be compatible and consistent with the existing EU ETS arrangements. We would seek that Government ensures that the levels of taxation within the new levy on fossil fuel generation are consistent with the price of carbon being targeted.

Will a carbon ﬂoor price be feasible in the context of EMR and at what level should it be set? 26. The proposals for supporting the carbon price contained within in the Treasury consultation published alongside the EMR appear feasible. 27. It is for Government to determine the level of carbon price support that will encourage investment in low-carbon technologies. It is crucial, however, that the aggregate level of support from all the reforms is considered, in order that inappropriate levels of ﬁnancial support are not granted to developers. We would also seek that the process for determining the level of support is transparent and robust. 28. We note Government’s proposal to introduce carbon price support through taxation, by removing existing exemptions from the Climate Change Levy, and as such will impact generation in both GB and Northern cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w23

Ireland. Northern Irish generation participates in the Irish Single Electricity Market and we will be monitoring Treasury’s proposals with interest to better understand the consequent impacts on both UK and Irish generation.

What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets? 29. We welcomed Government’s recognition of the possible role that increased interconnection could play in the future generation mix. Interconnection between markets has been shown to deliver significant benefits to other European markets. These benefits relate in particular to security of supply in areas of high renewables penetration and economic price discovery as price arbitrage occurs between the markets. As a company with generation assets in other European markets, we are particularly interested to explore how interconnector flows into and out of the GB market will be treated under the envisaged GB capacity mechanism. 30. I hope the Committee finds these comments useful. Should you have any questions or wish to discuss any of the issues raised in more detail, please do not hesitate to contact me. January 2011

Memorandum submitted by the Association of Electricity Producers Executive Summary — The Association welcomes the Government’s recognition of the issues surrounding investment decisions in the electricity industry and its efforts to address them. We are still in the process of assessing the beneﬁts and risks of the wide-ranging proposals presented by the Government on 16 December 2010 in its consultation on Electricity Market Reform (EMR). — The EMR work must provide clear, stable and achievable proposals that will demonstrate that the UK offers an attractive environment in which to make energy investments. The aim should be to reduce political risk and create greater long term certainty for investors. — The Association wishes to see the continuation of a robust, competitive and liquid wholesale electricity market, which should provide a reliable and credible wholesale price where the investments required to meet the Government’s energy policy objectives are fully rewarded. — The Committee is aware from our evidence to its recent Inquiry that the Association is not convinced of the beneﬁts of introducing an Emissions Performance Standard, which it believes would further undermine the EU Emissions Trading Scheme and add to investors’ risks.

Introduction 1. The Association of Electricity Producers (AEP) represents the many different companies, both large and small, that make the electricity upon which the UK depends. Between them, AEP members account for more than 95% of the country’s electricity generation capacity and embrace all generating technologies used commercially in the UK—coal, oil, gas, nuclear power and a range of renewable energy technologies. A list of our members can be found online at www.aepuk.com 2. Members accept the principle that, to achieve longer-term carbon reduction ambitions, short and medium term investment decisions have to be on the low-carbon path. However, the sums of money required to replace ageing plant and, more significantly, to meet the requirements of the Renewable Energy Directive and the UK’s own target for the reduction of carbon emissions mean that the energy industry has to attract significant new investment—£200 billion for new power production and networks and gas infrastructure by 2020 and another huge sum in the following decade. In the present financial climate, there is a serious risk that this investment will not be available if investors do not have confidence in the UK electricity market arrangements. If these huge sums are to be attracted to the UK, there must be a clear, credible and stable political and regulatory environment which delivers appropriate rates of return. We do not have that today, because a) the current design of the electricity market will not bring forward the full range of low carbon technologies needed to meet the UK’s highly demanding low carbon agenda in an economically efficient manner and b) the emission limits applied by the EU Emissions Trading Scheme do not offer the visibility and confidence of longevity beyond 2020 that would help to bring forward the diverse low carbon investment required to meet those UK targets. There is a fundamental need to align the policy framework with the investment timescales and payback periods for large scale low carbon technologies. 3. We welcome the government’s recognition of these issues and its efforts to address them. The changes proposed in the Electricity Market Reform (EMR) consultation would be the most significant to the industry since privatisation and could have a substantial influence on the unprecedented level of investment required to achieve a transition to a low carbon electricity supply industry. It will also be important to ensure that investments already made in the industry are appropriately protected. The Committee is asked to note that the Association is still in the process of evaluating the impact of the proposals which were announced by the Secretary of State on 16 December 2010 and that this evidence should be treated accordingly. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w24 Energy and Climate Change Committee: Evidence

Process 4. Our hope is that the EMR work will provide clear, stable and achievable proposals that will demonstrate that the UK offers the best environment in which to invest. Whatever the conclusions of this review there should be an assessment of whether a speedy and radical implementation delivers the best result, compared with an option which delivers a number of quick wins followed by slower more evolutionary change. 5. This reform will be, in effect, the fourth set of trading arrangements (the Electricity Pool, NETA, BETTA) to be applied to the electricity industry since it was privatised and liberalised in 1990–91. The industry has considerable experience of change, but, it is not yet clear at which stages it will have the opportunity to contribute to the work developing the proposals further. The Electricity Market Reform consultation envisages the publication of a White Paper in the late spring of 2011 which is expected to include ﬁnal proposals. We assume that there is to be a period of activity when industry expertise will be put to good use and the Association would like to make clear that its members would be willing to input to any Working Groups that may be established to develop and assess the various proposals. 6. The Committee will be aware that, for many years and with few exceptions, the Association has been consistent in its support of market principles and in the importance of market-driven prices. Although the EMR presents the Association with difﬁcult issues, many of which we have not yet been able to resolve, it is already clear that members want to see the continuation of a robust, competitive and liquid wholesale electricity market, which should provide a reliable and credible wholesale price where the investments required to meet the Government’s energy policy objectives are fully rewarded. We have also stated consistently that, given a clear and stable policy and regulatory framework, the industry is capable of managing risk.

Response to Speciﬁc Questions Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? 7. Our members have different views on the need to reward capacity. Some can see merit in such an approach while others will reserve judgement until further detail is available about the design of such a mechanism and there is greater clarity about which plant would be affected among existing plant and/or plant yet to be commissioned and about how to avoid potential distortions to wholesale prices. Members note, however, that the consultation states that “... because of the increasing risks to security of supply arising from the transition to low-carbon generation, the Government is consulting on introducing a capacity mechanism to explicitly reward the provision of capacity ...” The implication could be that the problem is seen as the potentially large amount of wind power which will be on the system when the EU target is met (requiring more “back-up” than other plant), but, the consultation is not entirely clear about which problem the government is attempting to address (eg. peak demand, ﬂexibility, or both) and we shall therefore seek clarity on the rationale behind the proposal.

Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology- based view? 8. The Government wishes to accelerate the transition to a low carbon electricity industry and “low-carbon generation revenue support” appears to be a key facilitator of that. Experience of the Renewables Obligation suggests that there is a need for support to be banded by technology in order to incentivise a wide range of technologies. 9. Greater consideration of the practicalities of a CfD feed-in tariff is required, including who would act as the counterparty to a CfD contract and how a tendering process could work, in particular in relation to the discovery of a meaningful price and the difﬁculties of ensuring planning consent. We also note that a tender process does not necessarily ensure that the appropriate levels of support are guaranteed. For example, Government may be targeting support for particular technologies; however, the vagaries of a tender process do not necessarily ensure the required outcomes are achieved. The government will need to be mindful of the potential burdens that participating in an auction/tender could present to generators, in particular smaller renewables plants.

Will market reform increase political risk for investors or create certainty? 10. It would be a very unhappy outcome for the industry and its customers if EMR increased political risk. While the outcome of some of the proposed reforms is unclear at this stage, the aim should be to reduce political risk and create greater long term certainty for investors. There are, however, elements of the package which could increase political risk. The Committee will be aware from our evidence to its recent inquiry that the Association is not convinced of the beneﬁts of introducing an Emissions Performance Standard, which it believes would further undermine the EU Emissions Trading Scheme (EU ETS) and add to investors’ risks. Similar risk could arise if the carbon ﬂoor price were to become important in terms of Government revenue. We should make clear that most of our member companies want to operate in a competitive market and that relying entirely on government direction of the market would not necessarily reduce political risk to investors— cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w25

it might well increase it. Members consider that there is a need to maintain the elements of the current market that work and to protect existing investments as well as encouraging new low carbon plant.

Will the Government’s proposed package of carbon price ﬂoor, EPS, FITs and capacity mechanism provide sufﬁcient transformation to achieve goals on climate change, security of supply and affordability? 11. The Committee is trying to establish whether this package of proposals will work without there being a serious imbalance between the long-standing political objectives for the industry. The Association is also interested in this question, not least because failure could lead to further changes in public policy and new political and regulatory risk. We shall be discussing the proposals with Government. In the meantime, it is probably fair to say that, whereas a transition to a low carbon electricity industry should be compatible with security of supply, it is less clear whether, with reduced reliance on a competitive market, this can be achieved at an acceptable price—the judges of which are ultimately the customers, domestic and commercial.

What synergies and conflicts will there be between the range of proposed mechanisms and policies already in place? 12. The implications for the Renewables Obligation of the transition to a new support mechanism for renewables, including the proposal in the EMR consultation to fix the price of a Renewables Obligation Certificate, will need to be carefully considered. The tensions between the carbon floor price and the EU ETS are also an issue. Finally, it is paramount that the industry has certainty on grandfathering options and the length of time that “interventions” are to be applied.

Will a carbon floor price be feasible in the context of EMR and at what level should it be set? 13. A carbon floor price is feasible, but there are differences of opinion between members on the necessity of a having a carbon floor price in addition to a two-way CfD FIT for low carbon generation, when it should be introduced and the appropriate level of the floor price. The Association will discuss with the Government the impact of the EMR proposals on the relationship between the GB electricity market, the electricity markets of the EU and the development of the single market in electricity. The impact of capacity payments and a floor price for carbon on cross-border trading demands careful examination. We wonder, for example, whether a carbon floor price in the UK could encourage increased emissions elsewhere in Europe. We shall ask the Government to continue to press for a robust, long term carbon price signal across Europe, the absence of which is a factor behind the proposed EMR.

Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? 14. An initial examination of the EMR proposals led the Association to consider whether the entire package of reforms should be delivered in one step or whether it should be phased. Our preliminary conclusion is that it may not be necessary or even desirable for all aspects of the package to be implemented at once. Sufﬁcient time will be required to implement changes to the industry codes in a robust and lasting manner and it is desirable that a clear, holistic plan be drawn up, even if it is to be implemented in stages.

Other Matters to be Addressed 15. The Association notes that the Committee on Climate Change has indicated that it would prefer there to be rapid deployment of low carbon plant ahead of any increase in electricity demand (arising from the decarbonisation of other sectors, such as home heating and transport) rather than allowing the market to determine the mix of generation to be built to fill a generation gap. The Select Committee and the Government, however, should be conscious of the potentially negative outcome of a surplus of generation capacity being forced on to the system. Current levels of capacity compared with demand have led to wholesale prices being depressed and in the last decade, when generating capacity greatly exceeded demand, companies were put out of business. With existing and future investment in mind, careful consideration should be given to the possible impact of the Climate Change Committee’s proposal and the mitigation of risk to investors. 16. The impact of European legislation and its application to the UK must be taken into consideration. There are a number of emerging energy-related European codes due for development in the near future. Early sight of the extended scope of a pilot connection code, for example, has caused widespread concern among our membership. We shall urge the Government to consider carefully the potential impact of European regulations on its proposals for electricity market reform. 17. We find it difficult to assess the impact of the proposed reforms on market liquidity. While we support initiatives which deliver increased liquidity, we cannot see any specifics within the proposals which will promote this. Indeed for the CfD element of the proposals to work, liquidity is paramount. There is no “correct” level of liquidity, yet poorly considered design could actually result in reduced liquidity. We believe that additional focus on this area would be of benefit particularly around the development of longer term options. 18. We are also aware of the Government’s review of the future focus for Ofgem and we look forward to the outcome and clarification of Ofgem’s future role and responsibilities with regard to electricity market cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w26 Energy and Climate Change Committee: Evidence

reforms. This includes clariﬁcation of where current Ofgem initiatives such as Project TransmiT and review of market liquidity would be relevant to the outcome of these reforms. 19. Finally, we should like to emphasise that a timely and business-like planning process and signiﬁcant grid investment remain vitally important if the transition to a low carbon electricity supply industry is to be achieved. January 2011

Memorandum submitted by Welsh Power Group Introduction 1. Welsh Power Group (WPG) is a privately owned energy company with a strong track-record in development, in both conventional and renewable energy. In August 2009 Welsh Power submitted an application to develop Wyre Power, an 850MW CCGT (combined-cycle gas turbine) power plant near Fleetwood, Lancashire, with an investment of some £600 million. In January 2009 the Company commenced the development of a 49.9MW biomass plant at Newport Docks through its wholly owned subsidiary Nevis Power Limited. We also own and operate an OCGT, Leven Power, on a STOR contract to NGC. 2. Formerly, WPG owned and operated Uskmouth Power until its sale last year to SSE. It also developed Severn Power, a new 850MW CCGT plant in South Wales, which it subsequently sold to DONG Energy. WPG also started its own retail business, Haven Power, in 2007, but this has subsequently been bought by Drax. 3. WPG has signiﬁcant experience of the problems experienced by small independent players trying to operate in the GB electricity market and we welcome the Committee’s inquiry into the proposed reforms. Outlined below are our comments on the areas outlined in the terms of reference, along with a few other observations. We would be very happy to talk to the Committee about any of these issues if that would be helpful

Issues Not Addressed by Electricity Market Reform Proposals 4. WPG believe that the GB electricity market is fundamentally broken with illiquid markets, dominated by six large, integrated companies, and significant barriers to entry to each part of the market. WPG has significant experience of the problems caused by the illiquid GB power and they have shaped the way that our business has developed. It is extremely disappointing that the DECC document pushes resolving the problems back to Ofgem, who have been ignoring the issue for years. 5. Concerns about market liquidity have been raised by traders and suppliers for years, and Ofgem’s own corporate strategy in 2005 recognised that vertical integration needed further consideration. The Select Committee on Business and Enterprise in December 2008 said: “We welcome Ofgem's decision to take action to improve liquidity in the wholesale electricity market.” We therefore feel that Ofgem must have recognised two years ago that action was required and they should now be seen to do something rather than focus on monitoring and reporting. 6. As there is now wide recognition that the market is not liquid action is required to fix it. DECC outlines proposals Ofgem has put forward, but progress needs to be made. Ofgem’s “wait and see” attitude is simply not likely to deliver timely changes to the market. Furthermore Ofgem seems to push ahead with projects that the smaller players do not value, such as a full review of transmission charging, rather than concentrate efforts and resources on key problem like market liquidity. 7. In terms of some of the claims made by the big 6 about their level of trading, we would be interested to know if Ofgem has audited the trading of one or two of those companies to see who they trade with and how. We would be concerned that their “trading” is very limited, in terms of volume, products and counter-parties. 8. WPG believe that Ofgem should also ask to see the financial models that justify some of the new build projects (notable new nuclear) proposed by the big 6, as we cannot see how with current prices, and no liquid forward curves, these utilities are justifying any new investment. As developers ourselves we know that the forward curves make justifying new projects extremely difficult, so is it that the big 6 can hedge the power price risk directly into their supply business? 9. Ofgem seems very focused on cash-out prices, with a proposal to undertake a significant code review in this area (see comments below). We do not believe that there is any evidence that cash-out causes any greater problem than incentivising the suppliers to be long to manage their cash-out risk. The wholesale market does not reflect the cash-out prices, nor should it, and the market does not want to use cash-out as an index to trade around. There is no easy answer to cash-out calculations and compared to the lack of liquidity in the market it is a minor issue. Ofgem needs to be careful not to tinker with balancing rather than address the more fundamental, structural issues. 10. WPG would like to see the government or Ofgem refer the big 6, or the sector as a whole, to the Competition Commission for a full structural review. The only way that the generators will bring more power to market is if they do not own supply business or they are not allowed to sell to any supply businesses with which they have any shared ownership. We believe a licence condition to stop generators selling directly to cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w27

their supply businesses would be a quick and easy step towards changing trading requirements. WPG would propose that Ofgem bring forward draft licence changes with their remedies document later in the year or the government could implement changes with the legislation that is likely to follow this market review.

The Objectives for Reform 11. WPG recognises that the government’s drive to low carbon electricity market does require some consideration to be given to the way the market is structured and operates. We feel that there are specific elements of the market that face new challenges with the emergence of increasing amounts of intermittent generation and new, larger, nuclear power plants. That said we are not convinced that the main problem is the structure of the rules so much as the existence of dominant players who create barriers to entry and gain commercially advantage from their integrated nature. We are extremely disappointed that structural remedies are being left with Ofgem to pursue at their leisure. 12. The objectives of the reform should be: — To address the dominance of the big 6; — To check that the current rules (Balancing and Settlement Code and Grid Code) will treat all plant equitably while facilitating the roll out of lower carbon generation; — Not create further complexity unless it alters the incentives on players to significantly change their behaviour; — Put in place a stable market framework for the future where the regulator will not push for further radical change in the medium term; — Better define the role of Ofgem and government in setting future energy policy; and — Stop yet another cash-out review until Ofgem can demonstrate there is a problem.

Capacity Mechanisms 13. WPG believes that the GB market already has a mechanism for delivering new capacity in the form of the National Grid STOR contracts9. These contracts, now they are being made for longer periods (up to 15 years), offer the market a way to encourage new build at competitive prices via an open tender process. WPG agreed with National Grid that there is a longer term requirement to increase the reserve on the system. But in terms of a supply demand balance the market should be competitive enough to respond. There is significant evidence10 that enough capacity will be built to meet general demand levels, replacing aging plant, what seems to be missing is the reserve element in the market. 14. National Grid needs reserve to manage the pick-ups in demand where fast response is required, for example at lighting up time, when wind farms lose the wind, or a large plant has a technical problem and drops off the system. The increasing amount of intermittent generation requires additional capacity be held in reserve to manage these real time system issues. The larger nuclear plants will also mean National Grid requires additional reserve as the new plants will be the largest plants on the system, so back-up must exist for when they trip off. These two factors are combining to require additional reserve is held by the system operator. 15. WPG will therefore be supporting the tender for targeted resource (TTR) option proposed by DECC which can operate just like STOR. We believe that any other form of reserve market creates the risk of the customers being forced to buy and pay for capacity that the market should deliver in a competitive manner. Customers at the last electricity market review in 2000 argued strongly against any mechanism that paid generators simply for being available. This was because all generators got paid, even if the system did not need them, and it could be argued that this lead to the excess generation capacity seen at NETA go-live in 2001. 16. This type of reserve capacity must be fast responding, but will only run for limited periods. The nature of the plant with low running, high wear and tear costs through peaking, and the only counter-party being National Grid, will not simply be built by the market backed by these long term contracts. Even if suppliers were required to show they had contracted for enough generation to meet their customers’ demand, they would not purchase these reserve style generators output. It is only the system operator who requires such services and it is more economic that they are purchased centrally as their benefit is spread over all customers. 17. National Grid in trying to extend the length of STOR contracts has recognised that without these longer term agreements financing such new build will be extremely difficult. However, the development of these longer term reserve contracts needs some further work. Notably: — National Grid must structure a long term contract that works in the context of energy markets that will change in future years, i.e. they must be flexible; — National Grid must outline what capacity it requires for reserve purposes and where it wants stations to locate, so the tenders are more likely to deliver the capacity that the system operator wants; 9 Short Term Operating Reserve—and Ancillary Service 10 See National Grid Transmission Entry Capacity Register cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w28 Energy and Climate Change Committee: Evidence

— Ofgem must agree with National Gird that the prices the capacity is bought at will be passed through in the years to come, i.e. a commitment to allow cost recovery in future price control periods/incentive schemes; — If the government only wants capacity of a certain type (for example gas rather than fuel oil) for environmental reasons it needs to place that statutory requirement onto National Grid in a transparent manner; and — National Grid needs to better understand the costs of this type of generation to ensure fair treatment of small providers facing a monopsony. 18. WPG would note that DECC believes that increasing customer participation in the market (as “negawatts”) would be beneﬁcial. While WPG welcomes all forms of competition in the market, the government must be realistic about how much demand wants to participate. Large customers currently respond to the TRIAD system, where their consumption in the three winter peak half hours dictates their transmission charges. This is an extremely effective mechanism and should be maintained. However, more active customer participation was one of the NETA design criteria. The customers do not seem to want to participate in the type of market created. This may be overcome with changes in market design, but we suspect the problem of managing their primary production while participating in the market will be extremely difﬁcult to overcome.

Feed-in-Tariffs 19. WPG supports the introduction of feed in tariffs (FITs) as a more efﬁcient mechanism that the current RO regime. However, it is the level of the FITs that will determine if it is a mechanism that will deliver larger amounts of renewables in time to meet the various government targets. 20. The technology banding has been a relatively successful way to try and reward renewable generators enough to get their technologies off the ground and to build up experience on the capital and operating costs of some cutting edge technologies. What matters most to developers however is the stability of the support mechanisms. 21. There was a hiatus of investment while DECC put out a decision on grandfathering ROCs for some technologies last year, notably biomass, and now there is concern that the banding review will alter the RO support in 2013. So developers who waited for the grandfathering decision may now have left it too late to ensure completion of a build by April 2013, so have to wait to see what support levels will be in 2013. While DECC have announced they will bring forward the banding review, such indecision and lack of understanding about the nature of these investment decisions is clearly hampering the roll out of additional capacity. The market will then move towards the FIT regime and again developers will want more details on FIT levels, cut over policies, grandfathering, etc. before progressing projects. 22. WPG would also note that we see no reason why Ofgem run these types of schemes. We recognise that Ofgem has ended up with the role of administrator, or delivery agent, of various policy tools such as the Renewables Obligation and FITs schemes. In the case of the FITs scheme we were disappointed that there was no competitive tender to select the most efﬁcient and cost effective administrator. We believe such roles are best done by an organisation that delivers high quality IT solutions and government could consider hiving the E-Serve function off for sale, into HMRC or another existing body.

Delivery of New Market Rules 23. Experience with NETA suggests it is perfectly possible to deliver a whole new market in one go if the political will is there. The personal involvement of Ministers in pushing NETA forward was instrumental in forcing players who did not support change to go along with it. That said there may be some system changes that would be best phased in, notably any larger systems changes.

Market Risk 24. WPG believes that the government’s announced reforms could easily be seen as largely incremental changes. It has been unfortunate that so much has been made of the scale of change as this has clearly created uncertainty for developers and investors. The lack of detail in the policy proposals is also adding to risk, so the sooner the proposals are worked up the better. 25. WPG feels that the reviews being carried out by Ofgem, while getting less press coverage, actually represent a bigger market risk. The changes we are most worried about are: — Project TransmiT11, with the potential to change all transmission charges and connection fees; — The still yet to be implemented EDCM12 charges in the distribution networks and the associated treatment of pre-2005 generators; 11 Ofgem has already announced the hiring of three sets of academics and another set of consultants for this project (Ofgem letter 10/10/2010). If they cannot resource the work we are not sure how small players are meant to participate. 12 The charging methodology for customers connected at extra high voltages (22kV or more) in the distribution networks—due 1 April 2010. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w29

— The proposed review of cash-out prices; and — The new powers to alter industry codes that Ofgem have given themselves13. 26. We are therefore very pleased that DECC is reviewing the role of Ofgem. WPG feels that it is right that government can propose change to the policy framework, but the role of Ofgem has become so unfocussed that it is now probably the greatest risk to our business. 27. WPG believes that Ofgem’s remit today should have three key roles: — The management of the price controls and associated price regulation of the monopoly networks; — The awarding of licences; and — The administration of the codes that under pin the technical rules associated with the market operations and associated dispute resolution. 28. WPG believes that the government should abolish the GEMA (the Authority) style of governance. The Authority members have created several problems: — Direct accountability of the CEO of the regulator has been eroded; — Decision making is opaque (with Authority minutes being anodyne and published late and no papers available); and — Costs have increased for no perceived beneﬁt. 29. A good regulator acts in an open, transparent and engaging way, with all interest groups. A strong and constructive partnership with those being regulated would be helpful and the Authority is too far removed for this to be possible or practicable. 30. We hope that DECC will ask questions about how regulation of regulators is achieved and by whom. This is fundamental to a better structure of regulation going forward. Independence is one thing, but a regulator that is unchecked simply creates regulatory risk, thereby adding to costs and limiting market entry. Witnesses to the House of Lords Select Committee investigating Regulators stated that “there is a crucial need for greater parliamentary oversight … over regulation bodies”. We recognise that the government needs the regulator to be independent, but that is not incompatible with rights of appeal and accountability of regulators to elected members of Parliament. 31. Once DECC has set out the details of the new regime in the power market and a new regulatory regime then the reforms could provide greater certainty than we have experienced in recent years. However, while Ofgem can continue to undertake policy reviews without any demand for change (from the market players or the customers) then signiﬁcant risks remains.

Synergies and Conflicts 32. Of the policies announced the government some pose more problems than others. Taking each in turn: 33. Floor price for carbon —this does represent a major change in taxation, but its implementation does not look obviously problematic. There are some definitional issues that need to be considered, such as where generators are not supplied fuel by “suppliers” who are meant to collect the tax. The government must also brace itself for the price rises that will follow the new tax. The HMT figures (based on no analysis, but market knowledge) look low given it is the marginal generators (coal and gas) that will face a significant increase in their costs. 34. Feed-in-Tariffs—This is a significant change, but the timescales look achievable and the use of FITs rather than ROCs is likely to deliver efficiency gains in the longer term. The conflict will arise when parties are unclear how the move to FITs will occur. Some questions we would have are: can we elect to go to FITs not ROCs; how will the supplier obligation work as ROCs phase out; what are the support levels; is there going to be grandfathering; etc… The sooner these details can be worked out and communicated to developers the better. 35. Of the design options outlined, WPG believes that the CfD related FIT will offer the best value for money. We will need to wait and see the details of the strike price and how the scheme will be administered, etc. before we will know how difficult the implementation will be. As the RO will be maintained until 2017 there is no obvious rush to get the FITs in place, though most developers may welcome an early rather than late introduction. 36. Capacity Payments—As noted above, WPG believes that a mechanism could be delivered that simply builds on the existing market arrangements. This would be the TTR mechanism in the DECC consultation. If the government goes further, for example dictating the quantity, or even the specific types, of generation to be built there are far greater changes and the concept of free, open markets is being abandoned. 37. Obligations on Suppliers require licence changes and then some time for compliance. A capacity payment on all would require changes to, we assume, the BSC to create the payment and that will need significant system changes. 13 Significant Code Reviews are to be conducted by Ofgem where they appear to act as judge and jury. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w30 Energy and Climate Change Committee: Evidence

38. Emissions Performance Standards (EPS)— If we assume that this is a mechanism that will operate under the environmental regulations and be overseen by the Environment Agency, it would seem to fit into the current regulatory regime. While the setting of the EPS itself may have significant impact on investment decisions, implementation of the regime itself would appear to work with current monitoring and reporting. 39. WPG is concerned that the EPS principle will be applied to large plants initially and then to smaller plants later. If this is the government’s intention, then it needs to say so now. As noted above, the types of generation that best act as reserve capacity often run on fuel oil and therefore have relatively high emissions, though only for short periods, when compared to say a gas plant. While there is debate around what emissions levels of all plants should be that creates uncertainty for investors. If smaller plants, such as reserve plant, needs to be gas plant the government should state that clearly. It will cost consumers dearly if new fuel oil plant is built that must later been abandoned. That said, we note the government’s intention not to apply the EPS to existing coal plant, so similar rules could be outlined for any future change in emissions standards. 40. Further proposals—WPG has serious concerns about the review of cash-out. This is an exercise that has been undertaken by Ofgem on a number of occasions. There have been numerous changes to the BSC altering cash-out since 2001 and endless industry meetings on the subject. There are two conflicting problems that Ofgem has raised and DECC mentions: — The level of cash-out—is it cost reflective? The issue being how to allocate the cost of energy and the system service (frequency response, STOR, etc.) costs. — The impact on competition—with suppliers claiming the price is penal and therefore they are likely to buy more power than they need to limit cash-out risk. 41. WPG feels that there is no “correct price” for the imbalance prices. The cash-out regime we have today has been subject to much review and the possible regimes outlined by DECC (single cash-out, marginal, change in reserve cost allocation, etc.) have all been considered. We can see no evidence that the prices are wrong unless DECC wants to set different incentives on the players. For example, a marginal price is likely to be higher so make suppliers go longer into each balancing period. 42. WPG is concerned that there is some misconception about the role of cash-out in sending investment signals. We have heard Ofgem say that the prices are not high enough to encourage investment in reserve plant. However, reserve is not built based on cash-out. Plants being built to provide STOR type reserve are built based on their contracts with National Grid. Conventional, usually larger scale, plant is most often backed by longer term sales contracts. It can be argued that the cash-out feeds into the forward curve, which is the price that should underpin major capital expenditure on new build. But the forward market is so illiquid that there is no robust forward curve for cash-out to impact. 43. WPG feels that the latest cash-out review looks like job creation by Ofgem. Unless they have something new to discuss then the market has been round these arguments enough times to have well informed opinions. It is then a matter of policy choice if you want the design to result in, on average, higher or low prices. We would recommend that a review of cash-out is not undertaken unless evidence of the “incorrect” prices can be provided. Cash-out prices in any given half hour can vary widely, but do they allocate cost in a way that incentivises balancing? Yes. 44. On balancing services, while we have sympathy with the idea of better cost allocation, the costs are so small in relation to delivered prices that the work may not be worthwhile. It may simply be easier to make cash-out more penal if it is energy shortfalls the system operator wishes to discourage. Reserve costs may not relate specifically to a supplier being short of energy, but the way the energy is consumed. For example the reserve used to cope with a pick-up in demand from a TV event. Within a half hour the supplier may have enough generation being delivered, but the shape of the delivery profile may not meet the shape of demand. 45. It is a regular mantra from Ofgem that all costs must be correctly targeted. WPG supports this principle, but believes that it is general thrust of the incentives that market players respond to. The rules of electricity trading are already very complex. Changes could shift costs between players, but if the general incentive is to balance that is what they will do. Changing systems and adding complexity simply drives up costs and creates barriers to entry. Government should urge Ofgem to remember the 80:20 rule; if 80% of the incentives target costs correctly players will respond.

Carbon Floor Price 46. WPG believes that the proposals from HMT provide a good basis for setting a carbon ﬂoor price. The issue is how to link the new “CCL carbon price support rates” to the price of the EUAs under the EU ETS scheme such as to achieve the desired price of carbon. We do not believe that linking the price on a daily or weekly basis is either feasible or desirable given the volatility it will add to generation costs for marginal plant. Such volatility is highly likely to feed into electricity prices as generators seek to hedge the carbon risk. 47. WPG believes that setting the new CCL rate annually, while creating some stability, risks over or under achieving on the target price. A ﬁxed escalator may lead players to believe that the government is highly likely to alter the costs if they can see their target value is going to be missed. It may be better to set the target rate and adjust the CCL rate annually to meet the rate. With a forward price for carbon generators should have clearer idea of what the CCL rate will be if they know the target price. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w31

48. As a generator we would prefer to have a rate that we know is ﬁxed (with the known escalator). However, the political risk would appear to be less with a ﬁxed target rather than an escalator as there would be less chance of sudden change if the rate set ended up a long way off target. If the government goes with its proposed CCL start rate and known escalator it should commit to hold to that formula for say the life of the Parliament.

Storage and Interconnectors 49. WPG does not have any speciﬁc views on these two technologies. However, we would note that it is vital to maintaining a competitive market that any new technology, additional capacity (located in the UK or imported power) is treated in a non-discriminatory way. While the government subsidises speciﬁc fuel types, in terms of market rules, transmission access arrangements, etc. all players should be treated equitably.

Conclusions 50. WPG continues to believe that it is structural reform of the market to create a competitive, transparent and equitable market for all players that will deliver the greatest beneﬁt to customers. The signals that the FITs regime, carbon ﬂoor price and EPS will send should help the market to move towards low carbon generation. 51. However, WPG remains concerned by how much of the market is up for review and how the focus is not on the big picture issue of structural reform. We also continue to believe that Ofgem is simply piling regulatory risk on the market by undertaking work that simply does not need to be done. The majority of the government’s proposal can be made with incremental change, and adapting policy instruments already in place, but it is vital they set out some long term principles and policy details as soon as possible. January 2011

Memorandum submitted by Scottish Renewables Scottish Renewables is the representative body for the renewable energy sector in Scotland, representing the interests of more than 300 members from all technologies and their supply chain. As the members of the committee will be aware, Scotland accounts for more than two-thirds of all renewable electricity generation capacity in the UK. I am writing with regard to the Committee’s call for evidence as part of the inquiry into the Electricity Market Reform proposals. We welcome the Committee’s commitment to look at the Department of Energy and Climate Change’s proposals, given that this will be the biggest shake up of the electricity market since privatisation. The proposals could have a massive impact on returns on investment in electricity generation, and it is no exaggeration to say that these have the potential to make or break progress towards Scotland's and the UK's 2020 renewable energy targets. If the reforms and the ongoing review of grid charges are to meet their objective of substantial growth in low carbon electricity generation, the clear focus must be the delivery of a stable and long-lasting investment framework that reduces uncertainty and risk but that provides a sound business case for investors. For these reasons it is imperative that the proposed changes are subject to detailed and expert scrutiny at this initial stage and during their further development. Scottish Renewables has begun a process of detailed consultation and engagement with our members to ascertain their views on the opportunities, risks and relative merits of the proposals in order to come to an agreement on the optimal outcome for the industry from this process. We will submit a formal response to the UK government consultation by 10 March 2011 deadline. Until this process is complete we are unable to give a definitive position on the EMR process. However, at this stage we believe that the key areas that the Committee must focus on are: — Encouraging new investment while supporting current plans for further increases in renewable electricity generation, both on and offshore, as well as protecting investments that have already been made. — Cross over with Project TransmiT and the opportunity to create complementary regulatory frameworks for incentives and charges associated with renewable energy generation — The devolution of powers to the Scottish Government and other devolved nations — The transition to any new framework and the need to ensure that changes to existing financial support mechanisms for renewable electricity do not destabilise the market by reducing investor confidence or creating unsustainable impacts on the economics of renewable energy projects. If you would like further information or any clarification on the points above please contact Grant Thoms, Public Affairs Manager at Scottish Renewables. We would also be happy to give oral evidence at any point in the Committee’s deliberations. January 2011 cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w32 Energy and Climate Change Committee: Evidence

Memorandum submitted by InterGen UK Executive Summary 1. InterGen welcomes the opportunity to respond to the Energy and Climate Change Select Committee’s enquiry into the future of Electricity Market Reform (“EMR”). InterGen fully supports the Government’s commitment to achieving its climate change, security of supply and affordability targets. InterGen believes this can only be achieved by encouraging a diverse generation mix operating within a truly competitive environment in order to protect the interests of consumers. 2. InterGen would sincerely welcome the opportunity to give oral evidence in front of the Committee, given it is one of the few truly independent generators left in the UK which has significant investment plans for flexible generating technology in the UK in the next five years. 3. InterGen believes that: 3.1 Large-scale reform of the electricity market is required to support the Government in meeting its long- term three-fold objective of delivering a low carbon future, maintaining security of supply and ensuring affordability for consumers. 3.2 The current market arrangements are not sufficient to encourage significant investment in low carbon generation and the flexible back-up capacity required to support the anticipated changing generation mix in the UK. 3.3 At the conclusion of the EMR consultation process, the Government must announce a complete and coherent package of measures which will deliver its objectives, which are robust and flexible enough to work in a wide range of demand and fuel-price scenarios and are broadly supported by the industry and mainstream political parties. This will provide a stable and durable regulatory environment which is essential to secure long-term investor confidence. 3.4 The Government’s proposed package of carbon price support, FITs for low-carbon generation and a capacity mechanism could form the basis of a stable environment in which its low-carbon objective can be delivered. Such a package must include support for flexible and efficient gas fired generation given that InterGen firmly believes that it will give the desired flexibility to meet peak demand and also demand requirements when renewables cannot generate. 3.5 Long-term security of supply and the lowest costs for consumers can only be delivered if a truly competitive, liquid, rational and transparent wholesale market also exists. InterGen welcomes Ofgem’s continued focus on electricity wholesale market liquidity and believes that action to improve liquidity is an essential precursor to EMR. InterGen believes that vertical integration is not compatible with a competitive and liquid market and that steps must be taken to require vertically integrated companies to trade all of their generation through the wholesale market. 3.6 Carbon price support needs careful implementation and long-term clarity to ensure that market participants can continue to manage carbon and electricity market price risk and that there are no unintended consequences from interactions with the EU ETS. 3.7 The capacity mechanism should: — address the issue of intermittency of renewable generation by rewarding the provision of flexibility, rather than just the additional capacity required to meet peak demand; — ensure sufficient, though not excessive, returns for existing flexible capacity, and; — provide price signals to attract investment in new flexible capacity. 3.8 The proposed FIT regime should: — Allow low-carbon generation to be financially supported in a transparent manner. — Ensure such generation retains exposure to short-term price signals in order to encourage efficient generator behaviour and hence provide value to consumers.

About InterGen 4. InterGen is the UK's largest and most successful new entrant independent generator, having invested £1.4 billion in the UK since 1995. InterGen owns and operates three highly efﬁcient gas ﬁred power stations in the UK totalling 2,490MW and actively trades in the prompt and forward wholesale power and gas markets. InterGen is currently pursuing a number of development opportunities in the UK including two further 900MW CCGTs, representing a further £1.2 billion of investment.

Question 1: What should the main objective of the Electricity Market Reform project be? 5. Electricity Market Reform should principally support the Government in meeting its long-term three-fold objectives of delivering a low carbon future (and meeting its legally binding 2020 and 2050 targets), maintaining security of supply and ensuring affordability for consumers. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w33

Question 2: Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? 6. An estimated 20GW of flexible fossil-fired plant will close by 2020 due to age and environmental regulations. As the penetration of intermittent renewable generation increases (assisted by proposals to support investment in low-carbon generation), existing low-carbon gas fired assets along with a significant amount of new flexible back-up generation capacity will be required to achieve an acceptable level of security of supply. Under the present market arrangements, volatile cashflows at the reduced load factors anticipated make the economics of existing and new flexible generation uncertain. In these circumstances, existing environmentally acceptable flexible plants are likely to retire early and new build is unlikely. 7. New thermal generation such as gas-fired power stations can deliver carbon savings by replacing older, less efficient coal plants in the UK. 8. It is possible that the Big 6 vertically integrated companies could build new generation without change to the wholesale market, relying on revenue from elsewhere in their value chain (eg some of the companies look at the whole value chain, effectively subsidising generation investment through the value achieved from their retail operations especially during periods of depressed wholesale energy prices when retail margins often increase). However, it has been widely reported that the Big 6 companies do not themselves have sufficient resources to construct all the new generation capacity required in the UK. Independent generators will also be required to construct some of this capacity and bring much needed competition to the electricity market, ensuring better value for consumers in the long term. However, the current wholesale electricity market currently does not provide the long-term robust price signals necessary to encourage independent generators to invest in back-up flexible generation with low load factors. To address this, major reform is required in the manner in which generation capacity is remunerated to ensure that the UK remains an attractive place for industry to invest. InterGen believes that a capacity mechanism is an essential part of this reform and if appropriately structured can support the security of supply objective.

Question 3: What is the most appropriate kind of capacity mechanism for the UK? 9. InterGen is still considering the relative merits of differing capacity mechanisms, and will address this fully in its response to DECC’s Electricity Market Reform consultation. InterGen’s initial view is that a market- wide scheme, in which the volume of required capacity is centrally calculated but the price is determined via a competitive process, is likely to provide the best value to consumers in the long-term. Due to the predominantly intermittent nature of renewable generation, the capacity mechanism should reward the provision of flexibility rather than just that additional capacity required to meet peak demand. 10. To prevent market distortion and ensure existing plant can compete effectively with new plant, capacity payments should be paid to both incumbent flexible capacity as well as new plant. If capacity payments only apply to new plant, existing flexible capacity will be forced to retire early due to the anticipated reduced long term prices in the market as the proportion of low carbon generation increases. Such artificial displacement of existing plants by new build is inherently economically inefficient and would undermine investor confidence in the UK electricity market through impairment of existing plant investments. Hence InterGen believes that capacity payments must be made to all flexible generation whether existing or new.

Question 4: Should the system of Feed-in Tariffs be focussed on particular technologies or maintain a wider technology-based view? 11. InterGen believes that any low-carbon support mechanism (such as FIT’s) should be designed to allow such generation to be financially supported in a transparent manner whilst promoting maximum wholesale market liquidity. To encourage efficient generator behaviour the support mechanism should ensure that intermittent generation retains its exposure to prompt price volatility through full participation in the wholesale market, as the preferred FIT with CFD option provides. 12. It is appropriate to support a wide range of low-carbon technologies to ensure a diverse generation mix: making access to Feed-in Tariffs open to any low carbon technology will have the effect of a market which prioritises the most cost-effective technologies, to the benefit of energy affordability.

Question 5: Will it be feasible to deliver EMR all in one go, or will regulations and implementation be spread over time? 13. It is appropriate for the implementation of the reforms to be delivered in two or three rounds. Support of the all-in carbon price, essential to improve the investment case for low-carbon generation, and steps to improve wholesale market liquidity can both be implemented in isolation and should be introduced relatively quickly. The remaining reforms are likely to take longer to design and implement and would best be implemented together.

Question 6: Will market reform increase political risk for investors or create certainty? 14. There is broad consensus, backed-up by the quantitative analysis undertaken by Redpoint, that the current market structure is not capable of delivering adequate investment in low carbon generation capacity and cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w34 Energy and Climate Change Committee: Evidence

sufficient security of supply in a cost effective manner over the long-term. As a result, there is already a widespread expectation that large-scale reform of the market will be forthcoming and this has created an investment hiatus. Accordingly it is important that, at the conclusion of the current EMR consultation, the government announces a complete and coherent package of measures which will deliver its objectives, are robust to a wide range of demand and fuel-price scenarios, are broadly supported by the industry and mainstream political parties and have a firm timetable for implementation. This will provide a stable and durable regulatory environment which is essential to secure long-term investor confidence. 15. The Government needs to ensure that in delivering EMR it not only supports investment in new generation, but also does not undermine the value of flexible and efficient assets currently operating (or in construction) within the UK. 16. Many generation assets in the UK have associated long-term electricity off-take or tolling contracts which will require adaptation to account for the proposals under EMR. Furthermore the government should be aware of the burden a regulatory change of this magnitude will place on smaller, independent market participants. An increase in administration costs will have a bigger impact on small players; who are also likely to have less resource available to participate fully in the development of the EMR proposals. InterGen urges DECC and The Treasury to continue to consult fully with all industry participants to ensure a smooth transition from the current arrangements.

Question 7: Will the Government’s proposed package of carbon floor price, EPS, Fit’s and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? 17. The Government’s proposed package, if broadly supported by all types of industry participants and mainstream political parties, would form the basis of a stable and robust regulatory environment in which its low-carbon objectives can be delivered. However long-term security of supply and the lowest costs for consumers can only be delivered if a truly competitive, liquid, rational and transparent wholesale market exists. 18. New players will be encouraged to enter the market if the current low levels of liquidity are improved. Improved liquidity will make long-term price signals more robust and transparent which will assist smaller players who rely on project finance and investment from banks. InterGen is pleased that Ofgem have committed to continuing their work in this area to complement the EMR proposals. 19. Vertical Integration is not compatible with a competitive and liquid market. InterGen believes that a self- supply licence condition should be introduced requiring vertically integrated companies to trade progressively increasing percentages (ultimately 100%) of their generation via the wholesale market, coupled with progressively greater separation between the wholesale and retail supply businesses. InterGen believes that a fully competitive and liquid electricity market will be achieved only once this process is complete.

Question 8: What synergies and conﬂicts will there be between proposed mechanisms and policies already in place? 20. InterGen is currently considering the interaction between new and existing mechanisms and policies and will address this more fully in its response to DECC’s Electricity Market Reform consultation. InterGen’s initial concerns are that carbon price support needs careful implementation and long-term clarity to ensure that market participants can continue to manage carbon and electricity market price risk simultaneously and that there are no unintended consequences from interactions with the EU ETS

Question 9: Will a carbon floor be feasible in the context of EMR and at what level should it be set? 21. InterGen supports the concept of a carbon price floor to promote increased investment in low-carbon generation and drive fuel-switching from higher to lower carbon emitting plant. 22. The all-in price floor range of £20/t to £40/t by 2020 is broadly in line with market commentators views on the price needed to prompt sufficient change in operational and investment behaviours to deliver the government’s long-term climate change targets.

Question 10: What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets? 23. InterGen has no speciﬁc views on this question.

Conclusion 24. InterGen acknowledges that there are many challenges for both the Government and the industry in addressing the three-fold objective of ensuring security of supply whilst meeting climate change and affordability targets. InterGen believes that support of the all-in carbon price, Feed-in tariffs which are structured to ensure low-carbon generators participate in the market and capacity payments for all ﬂexible cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w35

capacity are the key elements of market reform needed to deliver the targets. InterGen are keen to be given the opportunity to give oral evidence to support the views expressed here. January 2011

Memorandum submitted by RES 1. RES (Renewable Energy Systems) is a privately-owned British renewable energy project developer, active across Europe, North America and Asia-Paciﬁc. We have been in the renewables sector for over 25 years and have built more than 5GW of wind energy capacity worldwide. We seek to retain as many of the projects we develop as possible. In the UK we retain around 50% of the projects we develop. We therefore have strong interests in the long term viability of projects and the market for renewables more broadly. 2. The RES Group works in a range of technologies: onshore and offshore wind: solar PV and solar thermal; biomass power and on-site biomass heating; and ground source energy; and offers strategic advice to businesses on carbon reduction. 3. Despite the current economic situation, we continue to expand, with staff numbers rising sevenfold since 2002. We now employ over 300 in the UK and Ireland and almost 900 worldwide. With a broad portfolio of renewable technologies, RES is a good example of a successful British company in the international renewables sector, supporting UK industry and skills growth. 4. We welcome the opportunity to provide written evidence to the Committee’s forthcoming inquiry and will respond to each of the questions posed in turn.

Executive Summary 5. We consider that the Government’s preferred proposals as set out in the Electricity Market Reform (ERM) consultation in December 2010 are unworkable and undermine the position of renewable electricity generators and developers. Our key concerns are: (a) The removal of the obligation on suppliers to source renewable electricity removes one of the key drivers for increased deployment. It is likely that the contracting terms renewable generators will be able to negotiate will deteriorate if the obligation is removed. (b) The Contract for Difference (CfD) does not beneﬁt wind generators as they would remain exposed to short term price risk. Wind generators are likely to realise substantially less than the contract ‘strike price’, yet this lower level of realisable revenues would be largely hidden. (c) The proposal to use auctions to set support levels is unworkable and would increase development risk signiﬁcantly. 6. We believe that the Government’s alternative proposal for a premium type feed in tariff for all low carbon generation could, however, be made to work. Under such a scheme it would be vital that suppliers were incentivised to source renewable generation. Under current premium FIT proposals suppliers would not have any incentive to source low carbon generation. This is likely to lead to deterioration in Power Purchase Agreement (PPA) terms and negatively impact low carbon generators’ position within the market. 7. RES has developed an alternative feed in tariff mechanism which we believe addresses the government’s objectives for reform and, crucially, does not undermine renewable generators’ position in the market. The alternative proposal, and a paper outlining our concerns with the EMR proposals, is included as an annex to this submission. We have circulated these papers widely within the industry.

What should the main objective of the Electricity Market Reform project be? 8. Meeting the carbon and renewables targets should be the primary objective of the EMR. A second but important objective of the EMR should be to ensure that these commitments can be met at least cost whilst maintaining secure supplies.

Do capacity mechanisms offer a realistic way of achieving energy security, low-carbon investment and fair prices? 9. A capacity mechanism is one way of achieving energy security. 10. Recent developments in Germany have shown, however, that the market alone can deliver secure supplies without dedicated capacity payments. In Germany there is 26,000MW of wind capacity installed, 17,000MW of solar, of a total system capacity of around 150,000MW. In 2009 there were 140 negative price periods in the market. Negative prices occurred when generation was greater than demand, usually during time of high wind and solar output. By 2010 there were no negative price periods. The reduction was largely due to nuclear plant being operated much more ﬂexibly than had previously been anticipated. Nuclear stations are now turned down in periods of high renewable output. This demonstrates that the market can react rapidly to new market conditions and deliver robust and low cost solutions. Plants operating more ﬂexibly could reduce the amount cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w36 Energy and Climate Change Committee: Evidence

of highly ﬂexible peaking plants required to complement variable generation at much lower cost than a capacity mechanism.

What is the most appropriate kind of capacity mechanisms for the UK? 11. Initially a capacity mechanism is likely to be needed to support the continued operation of existing fossil fuelled plants rather than the investment of new capacity. The mechanism should enable such an outcome. 12. In the longer term, if a capacity mechanism is pursued it must be able to deliver a long term signal, upon which investment decisions can be made, if necessary.

Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology- based view? 13. Low carbon technologies are at very different stages of maturity. It is therefore not appropriate to have a single level of support. The level of support should be set so as to get the most low carbon generation at minimum cost. 14. If a system of FITs is introduced it is vital that incentives remain on suppliers to source low carbon or renewable generation. One of the key drivers in renewables deployment to date has been the obligation on suppliers to source renewable output. As a result renewable generators have been able to secure PPAs with supplier relatively easily. There is a very real risk that if suppliers were no longer incentivised to contract with renewable generators, that the terms of PPAs would deteriorate, threatening projects’ ﬁnances.

Will it be feasible to deliver EMR in one go, or will regulations and implementation be spread over time? 15. We believe that EMR should be delivered over a number of years. This would enable sufficient visibility of the changes to occur. The current EMR, combined with Ofgem’s proposals on improving liquidity, have not been sufficiently thought through, and nobody appears to have a full understanding of how the changes will interact. This exacerbates the risks facing investors and will lead to a investment hiatus until the regulations have come into effect and shown to work. 16. Additionally, the scale of the changes proposed risk undermining existing investments by opening up their contracts under change of law provisions 17. Spreading the reforms over a number of years will also allow policy makers to establish whether the market can deliver the requirements of the industry, or whether reform is necessary. For example it is not clear that the market can’t deliver the flexible and responsive generation and demand required to complement variable generation.

Will market reform increase political risk for investors or create certainty? 18. Market reform is likely to substantially increase political and investment risk. 19. Replacing the Renewables Obligation with another support mechanism such as a FIT would substantially increase political risk associated with renewable investments in the UK. The RO is working, there are mechanisms in place to ensure that the level of support awarded to new projects is kept in line with their needs, and there is very little uncertainty over the long term value of support. The RO already operates in a way which is very similar to some premium FITs and achieves the same outcome as a premium FIT. There is therefore little beneﬁt to be gained, but substantial damage to investor conﬁdence to be incurred. 20. It is therefore important to minimise the level of change introduced, such as moving to a premium FIT.

Will the Government’s proposed package of carbon price floor, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? 21. RES is broadly supportive of the Carbon Floor Price, EPS and capacity mechanism proposals. 22. We believe a carbon floor price is feasible in the context of the EMR. With a carbon floor price and EPS the level of additional support some low carbon technologies will require will be substantially reduced. 23. Currently there is insufficient information to judge whether the proposed CfD can be made to work, and we have a very low confidence in it.

What synergies and conﬂicts will there be between proposed mechanisms and policies already in place? 24. There is substantial potential for synergies between the proposed mechanisms, but there is also substantial risk that such synergies will be missed due to the various mechanisms being poorly implemented. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w37

Will a carbon ﬂoor price be feasible in the context of EMR and at what level should it be set? 25. We believe a carbon ﬂoor price is feasible as it will enable low carbon technologies to more rapidly reach a point of economic independent. We believe that the level should be set so as to send a clear and decisive signal to investors as early as possible, ie rising to £40/tCO2 in 2020.

What effects will EMR have on the development of capacity for electricity storage and the development of interconnectors between the UK and other electricity markets? 26. It is not currently possible to know the impact of the EMR on electricity storage. We would hope that the reforms enable energy storage to be developed within the market. Energy storage could play an important part in delivering the security of supply objective.

Annex RES BRIEFING NOTE: ELECTRICITY MARKET REFORM The Electricity Market Reform (EMR) proposals published by the Government on 16 December have the potential to cause substantial difﬁculties for the UK renewables sector. Given the scope of these changes RES feels it is very important for the renewables industry to respond decisively to the proposals. In this paper we present our main concerns. The aim is to help provoke and progress a full and informed debate within the industry. We believe that any move away from the Renewables Obligation (RO) could undermine the sector at a point at which deployment and the supply chain are reaching a critical mass. However, there is very strong political pressure for the RO to be replaced with another mechanism. We therefore outline a possible structure for a premium type feed in tariff which could form the basis of a workable replacement to the RO and support all low carbon technologies. Our fundamental concern is:

The reforms are needed to bring on new nuclear, but do so to the detriment of renewables

The Government states that new nuclear investment is difficult under the current market framework. Whilst we acknowledge these difficulties, we firmly believe that, because they are specific to nuclear investments (and possibly Carbon Capture and Storage (CCS)) but not renewables, they should be addressed in a way which does not negatively impact the renewables sector. We strongly disagree with the headline claims that the reforms will benefit renewables. The cost and disruption to the renewables industry of the reforms will far outweigh any perceived benefits. This is supported by the impact assessment that acknowledges that many of the benefits outlined for renewables are unlikely to materialise, are likely to have been overstated in the modelling or will be outweighed by far larger risks and market barriers. Other important concerns include:

The reforms remove suppliers’ obligation to contract for renewable electricity

Under the proposals suppliers would no longer be obligated to contract for renewable electricity. This undermines the strategy of utilities that have supported Government policy in pursuing renewable development as well as fundamentally undermining competition in the renewable energy market. The PPA market is reasonably liquid at present due to the demand from utilities. If suppliers no longer have an obligation or target to purchase renewable electricity then they will be less inclined to contract. There is a very real risk of the PPA market becoming much less competitive with higher discounts applied to PPA terms. This loss of revenue is likely to signiﬁcantly offset any notional gains from a reduction in hurdle rates and will increase the overall cost to the consumer. Whilst it is vital that that existing projects are properly grandfathered, we believe this is possible. Our concern is for new projects.

Auctions are fundamentally ﬂawed as a price discovery mechanism

The auction structures mentioned in the EMR will not lead to reliable price discovery. In competitive market segments there will be a tendency to bid over-enthusiastically, impairing project delivery whilst in uncompetitive markets there is the potential to abuse market power. In order to mitigate these risks the Government has proposed to enter all low carbon technologies into a single auction and hints at penalties for non-delivery. Neither of these options works. The single auction approach overlooks the fundamentally different ﬁnancing, operational and investment characteristics of different technologies. Whilst the penalty for non- delivery is not suited to the UK’s protracted planning and grid development regimes and signiﬁcantly increases the risk adjusted development cost as well as acting as a barrier to entry to new market players. We do not see how an auction system can be effectively implemented, and an ineffective auction system will seriously undermine the ability to deliver the Government’s carbon and renewable objectives cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w38 Energy and Climate Change Committee: Evidence

Contracts for Difference (CfDs) are unworkable and will provide no beneﬁt for renewables As it is proposed, CfDs will pay the difference between the contract ‘strike price’ and a market reference price (this could be an annual or perhaps monthly price index). Any difference between the renewable generator’s outturn PPA price and the market reference price will not be covered. The CfD does not, therefore, substantially increase revenue certainty for renewable generators as the headline proposal might suggest. Rather generators will remain exposed to short term market price risk (e.g. as a result of intermittency) and any discounts applied within the PPA as a result of suppliers’ market power. We see substantial difﬁculties with basing the CfD reference price on either half hourly or annual prices, making both approaches unworkable. CfDs as proposed are untested. Their complexity will further add to the development hiatus as the increased regulatory complexity is understood by the renewables industry.

CfDs transfer substantial risk to electricity consumers It is proposed that the CfD will transfer price and over-investment risk from low carbon generators to electricity consumers (via a Government agency). The Government appears to be relying on its gas price assumptions to justify the CfD proposal. If gas or carbon prices (and therefore wholesale electricity prices) were low, the amount paid to low carbon generators through the CfD mechanism would increase. This represents a substantial liability faced by consumers which the supporting analysis does not explicitly quantify. The Treasury recently announced that it considers the cost of the Renewables Obligation (RO) to have implications on the UK Government’s ability to raise taxes, even though the cost is not borne by tax payers but electricity consumers. Given that the CfD is expected to cover over 50% of the market in 2030, the potential liability could therefore have serious implications for the Government’s ability to raise taxes. This impact has also not been quantiﬁed.

There are fundamental flaws in the supporting analysis We fundamentally disagree with a number of the assumptions made in the consultation and supporting analysis. Our key concern is that the justification for reform hinges on the reduction in hurdle rates brought about by CfDs, and in particular the way that this applies to nuclear. Nuclear investments are assumed to have a higher hurdle rate than all other technologies in the current market (including R3 offshore). Nuclear then benefits from a 2% reduction as a result of the CfD. This assumption reduces the cost of nuclear, allowing it to be built sooner than would otherwise be the case; the primary benefit of the CfD proposal. We think that the initial hurdle rate for nuclear is too high and as a consequence the potential gains have been significantly overstated. The reduction in the hurdle rate for wind is less extreme, but it ignores the substantial development and regulatory uncertainty created. In reality these are likely to increase rather than decrease return requirements for renewables. There are a number of other issues which we fundamentally disagree with including the assumed inability of investors to forecast carbon price more than five years out and the assumption that nuclear is inflexible. We agree that both nuclear and CCS have a central role in the movement towards the low carbon economy alongside further renewable development. Our concern is that the proposals support nuclear to the significant detriment of renewables. As it stands the RO is working well. The level of support is transparent and, as acknowledged in the proposals, it now has many of the characteristics of a premium feed in tariff. The proposed reforms threaten to derail the renewables sector just at the point when deployment, and the supporting supply chain, is scaling up to really significant levels.

Possible Structure of a Premium Feed in Tariff Our immediate preference is to retain the RO as it stands and to support nuclear as a separate low carbon technology. However, the Government is opposed to creating a specific subsidy for nuclear and is keen to replace the RO. Other reforms of the electricity market are also likely to necessitate changes. In order to constructively engage with the EMR process we are putting forward a mechanism we believe could be workable and deliver the Government’s objectives. In developing this proposal we consider the following to be essential: — Suppliers must have some requirement or incentive to source low carbon generation. — The level of support must be determined through independent analysis and consultation with industry; auctions can’t produce stable market signals and must not be used to determine prices. — The level of support should be transparent. — Low carbon generators should benefit from the carbon floor price with the expectation that the required level of support will be reduced for new projects as wholesale prices increase. — The new arrangements should ensure a smooth transition for existing projects The proposal: — A premium type feed in tariff for all low carbon generation — Projects would receive the Premium FIT based on, but separate to, their output. Generators would continue to enter into PPAs with suppliers for their output, and the Premium FIT would be paid according to metered output by a central agency. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w39

— The cost of the Premium FIT would be recovered from suppliers according to the proportion of electricity that they supply from non-low carbon sources. — By charging the Premium FIT according to non-low carbon supply, suppliers would be strongly incentivised to source low carbon generation to minimise the cost to their consumers. — The reporting structures for this have already been established with Fuel Mix Disclosure. — The Premium FIT would be complemented by a carbon ﬂoor price, targeted capacity payment mechanisms and emissions performance standard as proposed. — The level of the Premium FIT would be differentiated by technology maturity (e.g. established, developing and pre-commercial). Our expectation is that they would last for 20 years and be indexed linked. — At the end of a project’s eligibility for the Premium FIT, the electricity generated would still be considered low carbon in the cost recovery mechanism. — The level of the Premium FIT would be reviewed periodically, with technologies being able to move down to lower bands as the level of deployment increased. Once operational projects’ premium levels would be grandfathered. — If needed, projects could opt to enter into a long term ﬁxed price PPA or CfD for their electricity. Under this proposal there is already an incentive to enter long-term PPAs to protect suppliers from a higher cost burden in later years. Additional measures should be enabled through Ofgem’s proposals for improving the liquidity of the electricity market.

Next Steps RES feels very strongly about the proposed EMR and we have prepared a more detailed critique of the proposals which we would be very happy to share it with you. However our objective is to move rapidly to establish an industry position around an alternative proposal. Our view is that it would then be useful to employ external advisors to develop this proposal further and evaluate the beneﬁts relative to the Government’s preferred option. January 2011

Memorandum submitted by the Low Carbon Group 1. About Low Carbon Group 1.1 Low Carbon Group was established in 2010 as a renewable energy developer of solar, wind, hydro and tidal projects and as an investment management group offering individuals and pension funds access to long term investments in renewable energy. 1.2 The directors of Low Carbon have developed, financed and sold over 2500MW of renewable energy projects prior to forming Low Carbon Group. The directors have managed over £1,850 million of capital dedicated to renewable energy and infrastructure prior to forming Low Carbon Group. 1.3 The team has a background in wind, biomass, waste to energy and solar and have developed or financed renewable energy projects in UK, Germany, France, Spain and Italy. 1.4 Low Carbon Group was established with a vision of giving individuals and communities the opportunity both to invest in local large-scale renewable energy developments, including green field solar projects, and to realise long term revenues from these opportunities. 1.5 We connect people to renewable energy projects through small and low risk investments, and over the next 18 months we hope to invest in 200MW of renewable energy in the UK with £500 million of funding. 1.6 Based in Cirencester, Low Carbon Group currently employs 40 people and expects to employ up to 70 by mid-2011. 1.7 Low Carbon Group welcomes the opportunity to respond to the House of Commons Energy & Climate Change Committee inquiry on the government’s Electricity Market Reform programme. 1.8 Our primary concern is to see Government maintain a reputable, consistent and trusted feed-in tariff policy against which we can spend high risk development capital. 1.9 The Feed in Tariff (FIT) is the framework by which we offer investors, big and small, certainty of returns and the confidence that should we get planning permission on a site, we know what revenues will arise. 1.10 Our position as a large-scale, leading renewable energy developer and investor and our collective experience in the sector over the last 9 years means that we are well placed to comment on the consequences of government policy on investor confidence in relation to FiTs. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w40 Energy and Climate Change Committee: Evidence

1.11 To that end, in this submission we will respond to the following questions: — Should the system of FITs be focused on particular technologies or maintain a wider technology- based view? — Will market reform increase political risk for investors or create certainty? — What synergies and conflicts will there be between proposed mechanisms and policies already in place? — Will the Government’s proposed package of carbon price floor, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability?

2. Executive Summary 2.1 In this response to the Committee’s call for written evidence, Low Carbon Group makes the following key points: 2.1.1 That all renewable energy technologies should be included in one Feed in Tariff mechanism that builds from the current FIT for sub-5MW renewables. 2.1.2 That FITs are expanded to include wave and tidal and energy efficiency. This will allow investors to make long term investment decisions that allow them to invest cashflows from one technology (eg green field solar parks) into tidal, wave and energy efficiency projects. 2.1.3 To attract the investment necessary to deliver energy infrastructure, the Government must act to provide transparency, long term tariff delineation, clear timetables, and a commitment to consistency of policy, in order to minimise political risk. 2.1.4 Institutional investors, seeking long-term, low-risk returns from investment in energy projects, are particularly susceptible to political risk. Low Carbon’s development activity, such as the launching of our People’s Pension fund and our marketing of renewable energy investments to very large pension funds, all require certainty. 2.1.5 The Government’s overall strategy must be to build credibility amongst the investors with an interest in the UK’s energy infrastructure. All reform to the electricity market must trust long term, transparent and clearly defined FIT policy so that long term investment decisions can be made in stable timeframes.

3. Should the system of Feed-in Tariffs be focused on particular technologies or maintain a wider technology-based view? 3.1 Low Carbon believes that a full system of FITs should deliver the following: 3.1.1 Sufficient support for ground mounted solar to enable 3GW of capacity installed. 3.1.2 Sufficient support for onshore wind to enable 7GW of capacity of onshore wind to come forward. 3.1.3 Continued support for building integrated or building associated micro renewables. 3.2 An extension of the FiT to cover wave and tidal such that an initial 500MW of marine renewables can receive favourable returns in order to kick start the market before a series of degressions to the tariff. 3.3 As a general comment, the Committee should note that many investors, including Low Carbon Group, are currently focussing their support on specific technologies as part of a wider, long-term business strategy. Low Carbon Group will re-invest surplus cashflow from current FIT projects into new tidal and hydroelectric power projects and will widen its fund offerings to include wind, hydro and eventually tidal. Solar green field projects are enabling us to drive the take up of the other long term, necessary renewables that have great potential but require further development and will require us to take profits from solar to kick start wave and tidal deployment. Groups such as ours, seeking to grow the next, but sustainable versions of the large FTSE petro chemical giants, require the ability to bring enough capital into the market at an entry risk level to be able to transition that capital to higher risk renewables. 3.4 A full FIT system should offer clear consistent transparent and long term support for all renewable energy technologies. We believe each technology has its procurement, environmental impact, planning and financing challenges, but that in driving investment towards developing these technologies FITs have the capability to resolve them. As a result of the Government’s existing FIT scheme, high calibre management teams are now starting to enter the renewable energy arena, as a result of investment attracted by the certainty that FIT provides. That transformative human capital needs to be allowed to migrate to whichever renewable it finds most attractive. 3.5 RECOMMENDATION: Low Carbon strongly supports the inclusion of all technologies, including nuclear, under FITs, so long as all associated costs are made transparent. We strongly support this inclusion as a means of providing a level of transparency that will enable both investors and the public to understand the benefits and costs of renewable energy and nuclear technology. We believe that through a wider system of FITs, the Electricity Market Reform should create platforms but not pick winners. 3.6 Low Carbon is currently at a critical stage in the convincing of institutional investors to allocate to renewable energy as part of their investment strategy. This comes at a time when European Governments will cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w41

have to attract about £870 billion of investment to meet targets for developing renewable energy and cutting greenhouse gas emissions over the next 10 years, while also replacing ageing infrastructure. As a result, we believe that it is imperative that all technologies have their FIT banding to suit different investor tastes and the opportunity for their market take up to be as large as possible, such that costs come down and nascent economic sectors made robust. 3.7 FIT tariff banding needs to be sufﬁcient to offer long term pension and individual investors the ability to achieve project level returns of 8.5–9% which is the market level return offered by other infrastructure assets such as ports, airports and toll roads. We strongly believe that the next three years are critical to the re setting of asset allocations within pension funds and insurance groups. We also believe that Government must maintain clarity for investors during this period of transition from allocations to equities, gilts, bonds, property to a signiﬁcant allocation from institutions to renewable energy. 3.8 RECOMMENDATION: That FIT tariff banding levels are varied to suit the range of investor interests, with new, higher-risk technologies attracting a better tariff level to reward the risk taken on by the investor. At the same time, lower-risk, proven technologies should aim a return of c. 8.5%–9% to mirror other similar infrastructure projects.

4. Will market reform increase political risk for investors or create certainty? 4.1 Low Carbon believes that the EMR project has the potential to do either of the above, but that it needs to achieve the latter. The use of FITs to drive investment into energy infrastructure is the first and essential step to bringing investors on the journey of trust into UK Government, trust into the energy sector and trust into those few organisations, such as Low Carbon, who have managed money for some time in this area. 4.2 Low Carbon would like to draw the Committee’s attention to the recommendations of the Stern Review of the Economics of Climate Change, which is still regarded as the single most in-depth, authoritative piece of work on this matter. In that report, Stern concluded: “Investors need a predictable carbon policy. Businesses always have to take uncertainties into account when making investment decisions. Factors such as the future oil price, changes in consumer demand, and even the weather can affect the future profitability of an investment. Business decision-makers make judgements on how these factors are likely to evolve over time. “But unlike many other uncertainties that firms face, climate change policy is created solely by governments...Serious doubt over the future viability of a policy, or its stringency, risks imposing costs without having a significant impact on behaviour, so increasing the cost of mitigation. Creating an expectation that a policy is very likely to be sustained over a long period is critical to its effectiveness.14 4.3 FITs, if implemented in a long-term, transparent fashion that provide investor certainty, are more than capable of helping the UK meet its future energy needs. FIT schemes are purposely designed to attract institutional investors, such as pension fund and insurance companies, who seek long term, guaranteed returns from their portfolios. It is for this reason that the Government’s existing FiT scheme has been designed to deliver a return on investment rate of between 6% and 8%; which can be finessed up to 8.5%, an ideal rate for institutional investors. As well as leveraging finance, this helps reduce capital costs, which will inevitably be passed on to the consumer, and the EMR consultation document recognises this, outlining how FITs can reduce the Weighted Average Cost of Capital for energy projects. 4.4 The Government believes that a transparent approach to its energy strategy will help minimise the political risk attached to projects, and whilst this is welcome, this alone is not enough for the investment community. If the Government is intent on using FITs as the key vehicle for its plans, then it needs to understand that those investors with an interest in them are more likely than any other part of the finance industry to be deterred by any element of additional risk. Political risk is often hard to quantify and highly unpredictable but Low Carbon Group believes the Government should do more to address it. 4.5 Low Carbon’s recent experience of the Government’s handling of existing FITs provides a vivid example of our concern about the political risks in the energy arena. The recent Comprehensive Spending Review (CSR) was ambiguous in the news that the Government, for the first time, had decided to place cost constraints on FiTs. Then followed a period of uncertainty and it was only sometime after the CSR announcement that it emerged that the Government had decided to do so. This news came without any formal, public announcement and challenged investor confidence. 4.6 Recent Ministerial comments about the use of FITs to finance solar greenfield sites have posed a further threat to investor interest15 in the UK’s energy infrastructure. Initiating an early review of FIT tariffs could threaten the revenues necessary to get the business operational and significantly hinder the ability of companies like Low Carbon’s to attract investment. Low Carbon Group would like to see a greater understanding at all levels of Government of the real and serious impact that this type of uncertainty creates. 14 Chapter 15, Stern Review of the Economics of Climate Change, 2006. 15 “Clampdown pulls plug on march of solar farm speculators”, Daily Mail, 12.11.10. See: http://www.dailymail.co.uk/news/article-1328894/Clampdown-pulls-plug-march-solar-farm-speculators.html cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w42 Energy and Climate Change Committee: Evidence

4.7 Banks are reluctant to finance projects for 15 years or more without a certainty that the cash flows are valid. These judgements are supported by Government statements on policy. In other jurisdictions where Government policy on renewables has wavered, the investment community as a whole has downgraded their assessment of the countries robustness in the face of discontinuity, elevating the cost of funding for all government enterprise. To meet the need for £200 billion of investment by 2020, the Government will rely on major institutional investors (such as pension fund backers) for the funding for all technologies, including offshore wind and the green deal bonds. Those same investors have given us commitments for the first time via investment in UK solar under the sub 5 MW FIT scheme that current exists. Through this scheme, FIT supported solar is the perfect low risk entry level renewable for new investors just starting to show an interest in renewable energy investment who can then transition through to fund the other renewables. 4.8 As investors are buying cashflows to match against long term liabilities, they by necessity begin with the most well understood and least risky renewable. Once comfortable with it, they will move allocations from equities and property into renewable energy. Low Carbon has held conversations with two of the largest pension funds in the UK who cannot deploy less than £100 million into this sector and need to know that the sector is big enough, certain enough of receiving returns above an agreed hurdle rate and not subject to any political risk. 4.9 To address these concerns, Low Carbon believes that the Government should return to the recommendations of the Stern Review, which concluded: “Three essential elements for an effective policy framework are credibility (belief that the policy will endure, and be enforced); flexibility (the ability to change the policy in response to new information and changing circumstances); and predictability (setting out the circumstances and procedures under which the policy will change).” 4.10 RECOMMENDATION: If the Government is determined to provide transparency, longevity and certainty for investors,16 then it should consider what legislative means it has at its disposal to do so. Low Carbon believes that enshrining FIT policy objectives (size, scope and characteristics of projects supported), the review process and that process’s timescales in primary legislation would be one effective way of doing this. Tariff levels would understandably need to be dealt with under secondary legislation, to provide Ministers with the flexibility to amend them in line with technology development, but clearly setting out the full process by which they are determined would significantly decrease levels of political risk.

5. What synergies and conflicts will there be between proposed mechanisms and policies already in place? 5.1 The Government’s lead option to replace the Renewables Obligation is a new FIT scheme, called “Contract for Difference”. Whilst this mechanism differs from the UK’s existing FIT scheme in that it accounts for larger generators who sell electricity to the wholesale markets, it nevertheless seeks to create greater long- term price certainty by guaranteeing a tariff payment to a certain level. As the Government recognises: “With a FIT contract the investor gets certainty about the level of support when the contract is signed. This is better than currently under the RO where an investor will not be sure of the number of ROCs they will receive until their installation is built and connected to the grid (accredited).”17 5.2 With this certainty at the heart of this mechanism, it is absolutely vital that a degree of trust exists between investment community and the Government so that large, low-risk investors are provided with the certainty they feel they need to support schemes. At present, many investors are considering investing in projects, but are closely watching Government behaviour before doing so. We are currently in a period when it is absolutely vital that the Government builds its credibility amongst the investment community. 5.3 Existing FIT policy will be viewed by many in the investment community as a litmus test for this credibility. A failure to provide that certainty risks undermining investor confidence, which the Government will need to instil to generate investment in energy projects via the Contract for Difference. We believe that within this context the Government should tread very carefully when approaching the FiT scheme that is currently in place and not hold an early review for the scheme, as it has previously suggested. 5.4 To date, the political risk around FITs stems from Treasury concerns around the level of costs passed through to consumers and the impact on their ability to pay tax rather than recognising the large scale upfront investment that provides an instant fillip to the national economy and the various tax takes it then benefits from in future years. 5.5 RECOMMENDATION: The Government has yet to clarify how the costs of a new Contract for Difference, if introduced as intended in 2013–14, would be viewed by the Treasury. We believe it should move to do so at the earliest opportunity, The recent uncertainty around the current FiT scheme originated from that Department’s decision to place a cost constraint on the scheme for the first time despite the fact that the ROC system has worked well for years with no constraint on it The Government has not clarified whether the Contract for Difference would have a similar constraint placed on it and, if it did, how those costs would be 16 “Energising the Big Society—the role of industry in the local energy revolution”, Greg Barker speech to the Micropower Council, 23.11.10. See: http://www.decc.gov.uk/en/content/cms/news/micro_council/micro_council.aspx 17 P. 48, Electricity Market Reform Consultation, 16.12.10. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w43

accounted for. Introducing a new cost constraint after launching the scheme would severely undermine the Government’s investment agenda and wider EMR programme.

6. Will the Government’s proposed package of carbon price floor, EPS, FITs and capacity mechanism provide sufficient transformation to achieve goals on climate change, security of supply and affordability? 6.1 Low Carbon will restrict its comments to the role of capacity mechanism in this section of its response. 6.2 Within the context of capacity payments, the Electricity Market Reform project proposes the use of “negawatts” to help improve energy efficiency through demand side management. The cheapest renewable energy by far is energy efficiency at a cost of £60,000–£300,000 per permanent MW removed. This can take the form of lighting management control, building management control, motor replacement, waste heat recovery and the like. It is simple to baseline and report against ongoing performance. Performance will need to be monitored annually and metered just like the production of power. It is important that energy efficiency gets a weighting via the Electricity Market Reform. This will enable investors to unlock the impediment to the deployment of energy efficiency initiatives which is the low priority energy costs have in any corporate organisation. 6.3 The investment community is able to remove this obstacle by the creation of infrastructure financial products. Energy Efficiency Infrastructure Funds can own capital items that reduce energy use and can take the benefits from a negawatts payment and from electricity savings to deliver their 12% IRR hurdle rate. Low Carbon is able to offer the Committee examples of potential projects. 6.4 RECOMMENDATION: We believe the above use of negawatts is an essential part of the EMR. Investors need a clear year one baseline to invest in negawatt projects, and then a negawatts pay out for negawatts decrease in a buildings output.

7. Conclusion 7.1 Low Carbon Group has made 230 presentations to pension funds and institutions in the last three years raising capital for renewable energy technology and projects. Our CFO has financed over £1 billion of renewable energy projects. Based on this experience, our Group is very clear on the levels of certainty that investors require. We believe that the investment community requires the UK government to adopt a clear, transparent pricing table for renewable energy generators per technology per annum for the investment community to choose to invest in UK projects. Critical in this regard is to build in rolling three year reviews of tariff levels and also to have in primary legislation an absolute commitment to the uptake of renewable energy and energy efficiency. With such legislation, we are confident that each company such as ours will be able to bring £billions of new capital into this sector. 7.2 Low Carbon would like to see the EMR embrace all renewables, including allowing the large take up of solar power. We would like to see it envisage a well rewarded initial pricing for wave and tidal technology in order to kick start what can become a homegrown and large export industry. Low Carbon would like to see the EMR advocate the transparency of tariff levels for all energy sources and clear and long term pricing for the various renewable power choices. 7.3 Low Carbon believes that as long as incentives for the various renewables can deliver a return to investors of in excess of 12% post tax equity IRR in the next three years to then track down to 11% and on down to commercial property rental levels once the sector is large and accepted that the EMR will have met its objectives. 7.4 Finally, Low Carbon believes the EMR has the real potential to deliver the radical change to electricity markets that the Government has said that it wishes to see. The various policy streams have the ability to be transformational for society, enabling individuals to make investment choices into renewables at a local and national level that will really mean society can make a choice about what power it wants at what price. 7.5 We would be delighted to give oral evidence on the challenges of raising finance for our sector and the challenges of development in our sector. January 2011

Supplementary memorandum submitted by Low Carbon Group This paper provides supplementary evidence to the Committee’s inquiry on Electricity Market Reform, speciﬁcally in relation the Government’s cap on Feed-in Tariff payments following the 2010 CSR and the announcement of a fast-track review of Feed-in Tariffs for large scale Solar PV in February 2011. This short paper demonstrates the impact of earlier than expected government intervention on investor conﬁdence of this nascent industry and the wider consequences to the future renewable energy infrastructure. Impact of the CSR cap and fast-track review of the FiT for large scale solar. The following changes have taken place within the UK Solar market since the £360 million cap was,imposed during the 2010 CSR and the announcement of the fast-track review in February 2011: cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w44 Energy and Climate Change Committee: Evidence

Businesses and Investment Impact — The following Independent Power Producers are being restricted from delivering their business plans of circa 100MW per company of renewable power this year to the energy mix of the UK. These are the new class of independent UK power producers who have a serious intent to deliver the low carbon energy mix the country requires: MO3 Power, Low Carbon Solar, Lumicity, Element Power, Cornwall Power, WRS, Alectron.18 — No senior lender is currently willing to lend capital to UK solar power projects. This list includes West LB, Nord LB, RBS, the Cooperative Bank and Rabobank. Without senior lending it is virtually impossible to finance a renewable energy project.19 — Banks such as the Coop have invested for over a year in getting up to speed with the solar market and can now not benefit from this preparation.20 — Ingenious Ventures has suspended two solar energy VCT funds—equivalent of £30 million investment. They have lost six months of time and cost, but more importantly were introducing new investors to renewable energy for the first time via the IHT, VCT, EIS annual tax wrapper investment market. — Triplepoint has shelved its interest in solar projects, suspending the launch of its planned £100 million Solar Income fund and is now awaiting “greater clarity” on the future of the feed-in tariff scheme before moving forward with its renewable energy investment plans.21 — Matrix has suspended its clean energy fund.22 — Low Carbon Investors (LCI) shelved all investment plans for large solar photovoltaic projects until the fast-track review is finalised.23 — Triodos Bank is reconsidering whether to continue with solar farm investments.24 — County Council pension investors looking to invest in UK renewable energy infrastructure for the first time have had to re allocate their monies elsewhere and are temporarily / permanently lost to the industry—work that took three years to build them to a position of being willing to invest in the first place.25 — Countless rooftop schemes, thought to amount to the creation of 5000 new permanent jobs in the UK, are now in limbo, unable to draw down funding.

Low Carbon Solar has invested £several million to date optioning potential brownfield and green field land, hiring 30 staff, building a design and survey capability and taking forward a series of planning applications. It now finds that it cannot get a return on its investment following the government’s announcement of a premature review. Typical costs incurred to date per site are: £150,000 for design, planning application and land options, £150,000 for Grid connections.

Community Invested Projects have been Suspended

It is proposed to build a community owned solar farm under the Westmill windfarm on the disused WW2 airﬁeld in Oxfordshire. The planning decision is due on 23 March.

Energ4All, in collaboration with site owner Adam Twine and Low Carbon solar, will put in place the legal, organisational and ﬁnancial basis for a local co-operative and will sponsor a public share offer approved by the FSA, to raise capital from individuals and organisations in the area. The share offer to raise capital for community ownership (of 75% of plant) will only happen if planning consent is granted.

Once the co-op has paid operating and ﬁnance costs, any surplus is distributed to the members as share interest and can be used to fund local environmental projects at the discretion of members. Anticipated share interest may be between 6–10% p.a.

This project requires a timeline of three months to seek FSA approval for a cooperative share offer once planning is achieved, a month to finalise the prospectus, three months to launch the share offer and reach financial close and then five months to build the site. All of this tightly time framed to meet the previous FiT March 2012 deadline; now impossible to achieve without tariff clarity from the government. 18 Direct discussions between Low Carbon CEO and industry partners as detailed 19 Direct discussions by Low Carbon team 20 Direct discussions by Low Carbon team 21 GreenBusiness http://www.businessgreen.com/bg/news/2029359/investment-funds-shelve-solar-plans-following-feed-tariff- review 22 lbid 23 lbid 24 lbid 25 Direct discussions by Low Carbon team cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w45

Consequences for UK Renewable Energy Infrastructure — The FIT scheme could enable the renewable energy sector to reach a critical mass, allowing for a robust and mixed energy sector. The UK will lose 30GW of electricity capacity by 2016, which needs to be replaced with low-carbon generation if we are to avoid blackouts, brownouts & move toward a low to no carbon future. Investors now feel a premature change to the FIT puts doubts on all tariffs for all renewables. — The fast-track review also places in jeopardy the opportunity for reinvestment from Low Carbon Solar’s development proﬁts into high risk development of tidal and wind energy technologies, underpinning future evolution and growth of the entire renewable energy economy. — The current level of the FIT is acknowledged as requiring some level of review, however this must be undertaken with the future renewable energy market front of mind; making sure there is a tariff which continues to allow for new investment money from pension funds, community ownership and high net worth individuals, thus in time lowering the cost of capital to the industry. — To be able to deliver to our funders and to build conﬁdence with pension funds, we need to be able to initially offer a certain 12% IRR to investors (8.6% unlevered) familiar with infrastructure assets. It will then be possible within a year, to bring in 10% return (7% unlevered) money, potentially digressing further in 2014 to 9% returns. March 2011

Memorandum submitted by the Institution of Engineering and Technology About the IET 1. The Institution of Engineering and Technology (IET) is one of the world’s leading professional bodies for the engineering and technology community and, as a charity, is technically informed but independent of network company, equipment supplier or service provider interests. This submission has been prepared on behalf of the Board of Trustees by the IET’s Energy Policy Panel.

What should the main objectives of the EMR be? 2. The Electricity Market Review needs both to facilitate the rapid move to deployment at scale of new large scale generation to avoid supply shortfalls over the next 10 years and also to enable the transition to a low carbon energy system. It would be undesirable to have to introduce further large scale reform to achieve the latter.

Requirements of Future Electricity Markets 3. In the short term, the main requirements are: (a) to encourage demand reduction; (b) to advance construction of mainstream technologies: nuclear, gas, wind and biomass; (c) to facilitate large scale demonstration of coal (and perhaps gas) with carbon capture, and also newer renewable technologies; and (d) to facilitate the development of low carbon energy solutions at community scale. 4. Key aspects of the longer term requirement of the EMR are: (a) Full participation of all aspects of demand in the market to allow the opportunities for management of demand to balance supply to be fully realised. (b) Anticipation of massive scale-ups of controllable demand (such as heat pumps, electric vehicle charging). (c) Incentivising reduced demand through efficiency and time shifting of loads. (d) Providing sufficient clarity to allow a smart grid to be deployed with confidence. (e) Dealing with a much more volatile generation market with large amounts of highly variable wind generation, and potentially significant contributions from sources such as solar and tidal barrages. (f) Dealing with increasing amounts of both nuclear and carbon capture-fitted thermal generation, whose dynamic performance is currently untested. (g) Moving renewables and other low carbon technologies from special support regimes towards the mainstream as carbon becomes properly valued. (h) Enabling the build of significant amounts of low cost peaking generation to provide cover for renewables shortfalls and exceptional demand peaks. (i) Being adequately robust to both improvements and further degradation in the funding climate. (j) Enable the wider integration of storage in the electricity supply chain. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w46 Energy and Climate Change Committee: Evidence

(k) Adequately incentivise new interconnectors with other European states where these can be shown to be economically attractive. (l) Delivering all this at costs acceptable to consumers and in ways that give sufﬁcient conﬁdence to investors.

Capacity Mechanisms 5. Capacity mechanisms are used successfully in many countries to provide incentives for the construction of power plant, and give confidence to investors by reducing or eliminating dispatch risk.26 The plant typically earns enough money to pay its fixed costs, service its debts and produce a commercial return simply by being available for service. Rewards for actual operation are typically scaled for the marginal costs of so doing (typically fuel plus hours-dependent maintenance). 6. This arrangement works best when the requirements for capacity are centrally determined such that an optimal amount of plant is built. The disadvantages of such a capacity mechanism are (a) that it limits the extent to which competition can bring innovation into the types of plant built and their operation in a market, and (b) potentially also provides capacity payments to fully depreciated generators who do not really need them. 7. The proposals currently being consulted on by DECC seem to see a more limited role for capacity mechanisms. They are to be used only when a proposed central body foresees a shortfall of capacity being provided by the market, thus avoiding the costs of making payments to all generators. The risk of this arrangement, recognised in DECC’s consultation document, is the distortion it could introduce into the rest of the market. (For example, will owners close plants deliberately to precipitate a decision to make capacity payments available for getting new plant built quickly?). The subject is complex and more work is clearly needed. However whatever arrangement is adopted needs to be transparent and sufficiently simple to send clear signals.

Feed-in Tariffs 8. Ideally the market should determine the least cost renewable solution, however there are wider issues to consider such as: (a) technical maturity (mature technologies are cheaper generally); (b) available land for onshore renewables; (c) the desire to create new green industries and employment through supporting certain technologies; (d) the different generation characteristics (for example wind has certain intermittency characteristics, solar different intermittency characteristics, and that biomass is dispatchable); (e) The desirability to pursue solutions at a range of scales (large plants, community energy schemes, building scale schemes), to maximise the opportunity for decarbonisation and to explore alternatives to ﬁnd best options; 9. Given the scale of renewables deployment implied by the EU 2020 targets, all technologies will need to be pushed hard, and as such there seems little alternative to a technology banded approach to the FIT.

Delivery in one go or over time 10. The proposed EMR introduces further uncertainty for investors, who will tend to wait to understand clearly what their project returns would be before committing. A key objective should therefore be clarity over the total package at the earliest opportunity, along with a very clear timeline for implementation. This should be thoroughly “road tested” with investors, noting, of course, their inevitable desire to obtain a more generous result than strictly necessary. 11. Actual implementation of the market reform process should be considered on the basis of a comprehensive risk analysis. There are market conﬁdence reasons for doing most or all of it at once, but the enabling IT and other infrastructure will carry implementation risks that need to be recognised and managed or mitigated.

Political Risk 12. The UK has always been at the forefront of electricity market reform and has over time made a number of major market changes that have created substantial winners and losers, and thus a perception of political risk. This latest EMR proposal is no exception, although there seems to be an industry consensus that change is needed, and cross party support for it. 13. The extent to which the result decreases confidence depends on how it is implemented—avoidance of significant financial loss for disadvantaged market participants is important, as is very clear signalling of intent. 26 Dispatch risk is the risk that a particular power plant is or is not called upon to operate, which depends on the balance of supply and demand at a particular time, and on the marginal costs of operating the plant compared to other plant. As we move forward with considerable uncertainty as to how much renewable and nuclear capacity gets built and when, it is much harder for investors to be able to predict the extent to which their plant will be dispatched and therefore what their revenues will be. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w47

As stated above, it is important that the EMR addresses long- as well as short-term issues to avoid a further revisiting of the rules and additional perceptions of political risk in the future. 14. On the positive side this reform, if carried through well, has the potential to be seen as a global template and to be creating the clarity needed to invest the large amounts necessary.

Will the proposed package deliver the security/carbon goals? 15. This will depend very much on how it is implemented. The right issues are being considered and sensible solutions proposed. The main risks seem to be excessive complexity resulting in a lack of transparency and/or unforeseen consequences. DECC is aiming to strike a balance between giving investors confidence and not over-rewarding them. In the IET’s opinion, the economic and political costs of insufficient capacity to cover times when demand is high and wind and other variable generation low seem to be rather higher than the costs of slight overprovision. We are moving into a technologically uncertain world given the high levels of intermittent renewables, demand participation and other changes and it would seem to us wise to err on the side of caution. 16. Affordability will be an issue into the future, whichever forms of generation are built. All forms of power plant, all fuels and also carbon emission will become much more costly. In addition, network infrastructure will need heavy investment to become smart and to meet new demands from heat pumps and electric vehicles. The only mitigant available is efficient use of energy, which will need continuing strong emphasis.

Storage and Interconnectors 17. Neither storage nor interconnectors seem to have been given strong consideration during the DECC work so far. Both have potentially large roles to play in the longer term, and we would suggest that a range of storage and interconnector scenarios are tested against the proposed reforms before they are firmed up. 18. Storage is essential to the secure operation of the power system and has the potential to play a bigger role in the future. It is recognised that storage can offer multiple benefits to the power system. Examples include helping to manage intermittency, meeting shorter term peak demands, reducing the need for new network capacity and enhancing security of supply. At present there is not a storage technology available that has the price/performance characteristics that will ensure widespread deployment. However, a number of technologies are under development and as the value of the ancillary services that storage can provide increases, they may well prove to offer economic solutions. 19. Storage can supply multiple services to different parties in the disaggregated supply chain. There is therefore a risk that the current market structure may make it difficult for storage owners to be properly rewarded for the services they can provide. This issue should be explicitly addressed as part of the EMR consultation process, involving the key players in the storage community. Hopefully, this will ensure that the market reforms introduced will not present any unnecessary and/or unintended barriers to the further development of storage.

Inter-connectors 20. Under the EU Third Legislative Package on Energy there is a requirement to form a single energy market but one in which the electricity supply systems of each member state will continue to have their own characteristics. Furthermore all members are obliged to signiﬁcantly increase the renewable component of their generating portfolio, UK included. 21. With different levels of security of fuel supply, proportions of intermittency and cost of generation, increased interconnection within the EU seems inevitable. Interconnection with the UK is, of course, a special case because of the need for submarine connections with higher costs. Nevertheless, interconnectors have potentially large roles to play in the longer term and we would suggest that a range of interconnector scenarios are tested against the proposed reforms before these are ﬁnalised. It should be noted that both political and technical risk underlying the development of interconnectors is likely to remain low. January 2011

Memorandum submitted by Grantham Research Institute and Centre for Climate Change Economics and Policy* * Grantham Research Institute and Centre for Climate Change Economics and Policy, London School of Economics. The Institute and Centre are supported by the Grantham Foundation for the Protection of the Environment, the UK Economic and Social Research Council and Munich Re.

Introduction The Energy and Climate Change Committee of the House of Commons has issued a call for evidence for its inquiry into Electricity Market Reform (EMR). The Grantham Research Institute at the London School of Economics is happy to respond to this call. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w48 Energy and Climate Change Committee: Evidence

We welcome the EMR package as an important and necessary step to decarbonise Britain’s electricity sector, which in turn is essential for the UK to meet its statutory greenhouse gas emission targets. The reform package recognises that a sound policy environment, including a strong and reliable carbon price, is crucial to unlock the investments needed over the coming decades and that the regulatory economics of low-carbon electricity are different from those for traditional electric power. It is important that the reforms go ahead.

The EMR proposals rest on four pillars: 1. A capacity-based market 2. An emissions performance standard (EPS) 3. A carbon price ﬂoor 4. Revision of the Renewables Obligation and the Feed-in Tariff system

This response primarily deals with the third pillar, the question of a carbon ﬂoor price. However, we begin our response with two brief observations about pillars two and four.

As far as the second pillar is concerned, the key issues are whether the EPS applies to all generation or only new-build and whether the standards are consistent with the fall in the carbon intensity of power generation required by the UK’s long-run emissions targets. There is a danger that the EPS will be superfluous if the carbon price signal is strong enough. And if it does have an effect at the margin, it may give incumbent firms and existing plants an unfair advantage over new entrants and give insufficient incentive to improve the efficiency of existing plants.

With respect to the fourth pillar, work by the European Commission has suggested that the UK system of renewable energy support has not been as cost-effective as the feed-in tariff systems used in several other countries. The complexity of the Renewables Obligation and the price volatility of Renewables Obligation Certiﬁcates (ROCs) may discourage new entrants in the power supply market. But the risks facing potential renewable energy suppliers can be reduced without switching to a feed-in tariff scheme. In this respect the EMR is right to focus on providing longer-term contracts as a way to reduce price uncertainty. Also, it would be helpful to carry the burden of grid expansion management centrally and to make it easier for new suppliers to connect to the National Grid. ROC allocation rates or FIT premia can usefully be differentiated to give a higher rate of support to less commercially mature technologies, but with the rate declining over time (rather than setting the rates for different technologies arbitrarily or in an attempt to ‘pick winners.’ It is also worth noting that a price incentive for the output of renewable energy does not tackle the problem of inadequate energy (and energy efﬁciency) R&D.

Turning to the third pillar, we wholeheartedly agree with the government’s objective of setting a strong and predictable carbon price. As already set out in the Stern Review, putting a price on carbon (or “internalising the carbon externality”) is absolutely necessary, although not sufﬁcient on its own, to tackle climate change successfully. However, we would argue that in setting a carbon price ﬂoor the policy context (especially, interaction with the EU Emissions Trading Scheme) needs to be taken into account more carefully.

In particular, we make the following four observations on the question of a carbon ﬂoor price: — The ﬁrst-best approach to supporting the carbon price would be an EU-wide tightening of the EU Emissions Trading (ETS) cap, supported by an auction reserve price to protect against price drops — The proposed extension of the climate change levy and fuel duty to power generators is second- best, because (unlike a tighter EU cap) it will depress the EU allowance price and will not reduce EU-wide emissions. — The measure will succeed in strengthening the long-term carbon price signal for UK electricity investors. However, investors may discount the price signal in the absence of more policy credibility. — The proposal is relatively straightforward administratively by removing existing tax exemptions. However it does not noticeably simplify Britain’s relatively complex climate change incentive structures, although this is an explicit (and laudable) objective of the legislation.

To strengthen the carbon price floor regulation, government and Parliament may therefore want to consider: — working more determinedly with EU partners to tighten the EU emissions cap; — ensuring the policy credibility of the carbon price floor; and — exploring further opportunities to simply Britain’s climate change incentive structures (CCL, CCA, EU ETS, CRC and the new floor price).

The rest of the note brieﬂy elaborates on these points. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w49

Further Elaboration The first-best approach to supporting the carbon price would be an EU-wide tightening of the EU ETS cap (e.g. a move from a 20% to a 30% emissions target), combined with an EU-wide reserve price for allowance auctions. A tighter cap is the best and most direct way of supporting the carbon price. In addition to sending a long- term price signal it leads to predictable and immediate EU-wide emission reductions (something the EMR carbon floor proposal does not, see below). Moreover, the market mechanism ensures that these are achieved at the lowest possible cost. However, a rigid cap can lead to unnecessary price fluctuations because the regulator is unable to adjust the supply of allowances (the cap) to changes in demand. We have seen the effect of this during the recession over the past two years, when reduced economic activity led to lower emissions and a fall in the carbon price. The price could have been supported through a reduction in the cap, but EU ETS rules did not allow this. There is a fairly broad agreement in the economics literature that a good way to address the problem is a reserve price on the auctioning of EU allowances (auctioning will become the norm in the EU ETS from 2013). A reserve price provides clear rules for how the supply of allowances responds to the price. It is an intervention that the market understands. Most auctions have reserve prices. (If there is a symmetric concern about price spikes the reserve price may be combined with a “safety valve” to create a cap-and-collar system). However, we recognize that moving to a 30% EU target is difficult politically and that the current auctioning proposals do not foresee a reserve price. The UK should continue to push for these reforms, but in the meantime it is rational to explore second-best options.

Subjecting British power generators to the Climate Change Levy, as proposed in the EMR, is a second best solution, if EU ETS reform is not possible. The proposal is second-best because of certain side-effects not currently acknowledged in the EMR proposal. Three side-effects stand out: — First, any additional emission reductions in the UK will be fully offset by higher emissions elsewhere in the EU, since the EU-wide emissions cap has not changed. Under emissions trading the only way to reduce EU-wide emissions is by tightening the EU-wide cap. — Second, the price for EU Allowances (the European carbon price) will fall because of reduced demand from UK power generators. This will reduce the intended effect of the new floor price and lower the carbon price signal (the incentive to reduce emissions) in the rest of the EU. As a very rough indication, a £10 carbon tax in Britain might reduce the EUA price by perhaps 5% (or about £0.65).27 — Third, the British floor price will reverse some of the gains from trade that the EU ETS offers. Compliance costs will go up and rise non-linearly with the level of the floor. The costs of meeting the UK’s carbon target will still be acceptable, but it does mean a loss in emission reduction efficiency. The carbon floor proposal would be strengthened if complemented by serious attempts to tighten the EU- wide emissions cap. For example, if it were replicated by a group of like-minded countries, Britain’s price floor legislation could be used to soften opposition to a tighter EU-wide cap. Since a unilateral carbon tax reduces the EU-wide allowance price it is possible to construct a package where the effect of a tighter cap (which increases the carbon price) and the impact of unilateral action by some member states (which decreases the carbon price) cancel each other out, so that non-participating member states face the same carbon price as today.

The carbon price floor will succeed in strengthening the long-term carbon price signal for UK electricity investors. However, investors will discount the price signal in the absence of policy credibility. Against the drawbacks of the carbon price floor (in terms of EU-wide side effects) have to be put the positive effect of giving UK investors a strong long-term signal to invest in low-carbon generation. This long-term signal is important. However, the strength of the long-term signal will depend not only on the level of the floor price but also on the long-term credibility of the measure. One reason why the current carbon price is so low is that the market discounts what it perceives to be non-credible commitments to tighten the emission caps. The EMR underestimates the importance of policy credibility in the carbon floor proposal. In other contexts, policy credibility is strengthened by giving a bigger role to independent bodies like the Bank of England (on interest rates), the Committee on Climate Change (on carbon budgets) and the Office of Budget Responsibility (on macroeconomic forecasts). Such institutional options may not be justified for a measure that is politically sensitive and has direct revenue-raising implications (although the CCC is already 27 Fankhauser, S, C Hepburn and J Park (2010). “Combining Multiple Climate Policy Instruments: How not to do it”, in: Climate Change Economics, 1(3): 209–225. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w50 Energy and Climate Change Committee: Evidence

required to advise on new trading schemes, which also raise revenue, and the Bank of England receives revenue from its lending activities and liquidity operations). In the absence of (or in addition to) such institutional options the government needs to maintain policy credibility through consistency and deeds. In that context, it is a concern that the proposed Energy Performance Standards (pillar one of the EMR) are to be set at a level that is wholly inconsistent with Britain’s carbon targets and several times higher than the actual carbon intensity required by 2030. At best, an EPS at that level is redundant (since other policies will push actual emissions further down). At worst, it is counter-productive by sending a mixed signal and creating doubts about Britain’s decarbonisation commitment among investors. The EPS should therefore be strengthened and made consistent with the emission performance standards required by Britain’s decarbonisation targets, as recommended by the Committee on Climate Change.

The proposal does not noticeably simplify Britain’s relatively complex climate change incentive structures, although this is an explicit (and laudable) objective of the legislation. Britain’s carbon policy landscape is relatively complex. It includes the Climate Change Levy, Climate Change Agreements, the EU ETS and the CRC Energy Efficiency Scheme. Hydrocarbon duties are also partly justified as climate-related carbon taxes. These policies overlap and tax carbon at very different rates. The Renewables Obligation, although designed primarily to promote renewable energy, also pushes up the price of carbon-intensive energy, as does the Renewable Transport Fuel Obligation. Some entities are taxed several times (e.g. the service sector will feel the impact of the carbon price floor, the EU ETS and the downstream CCL). Other parts of the framework, like the CCAs, are known to have been ineffective or even counterproductive.28 Government and Parliament may be missing an opportunity not just to strengthen but also to simplify Britain’s climate change incentive framework fundamentally, for example by imposing a broad, single and consistently set carbon tax. January 2011

Memorandum submitted by Professor Michael Grubb, Faculty of Economics / Electricity Policy Research Group, Cambridge University Summary Moving to a very low carbon electricity system is central to meeting the goals of UK energy policy, and indeed to the wider global challenge of tackling climate change. This will require massive investment in low carbon electricity sources. Part 1 of this submission summarises briefly four of the difficulties facing the current mainstream approach of relying on the impact of the EU ETS in the present liberalised electricity market, supplemented with additional incentive mechanisms like renewable obligation certificates and feed-in tariffs. Part 2 offers some observations on some of the alternative or complementary approaches set out in the EMR Consultation document, with a brief look at strategic dimensions of a carbon floor price, and then a more detailed look at the design of long-term contracts. In this, I outline a case for a distinct approach to long term low-carbon contracts, which focuses upon engaging a diversity of potential buyers. The aim would be to retain a greater role for competition on demand as well as supply side, in the form of long-term “Green Power” contracts that operate in a separate, differentiated contract market. It could thereby harness the potential interest and capital of electricity consumers, large and small, directly in funding low carbon electricity investments.

Introduction The UK has been amongst Europe’s leaders on both electricity liberalisation and climate change. In electricity regulation, the UK blazed a trail in unbundling previously centralised systems to inject competition wherever it seemed viable. The short term result was a radical reduction in costs (including unfortunately R& D), a surge of investment in combined cycle gas turbines, and a proliferation of suppliers competing for customers followed by consolidation. Reduction in CO2, driven by the displacement of old coal plants and some increased plant efficiency, was a significant side benefit. The basic idea of liberalisation and competition has spread more widely across the EU, albeit with complex variants. The UK also aspired to be among Europe’s leaders on climate change, pushing to strengthen the EU ETS, together with its ROC scheme to support renewable generation and a strengthening range of demand-side policies. This would seem to a good environmental combination. It is, however, now recognised to be inadequate, for a combination of technical issues in design and implementation—and for more fundamental reasons. 28 See Martin, R and U Wagner (2009), “Econometric analysis of the impacts of the UK climate change levy and climate change agreements on firms' fuel use and innovation activity”, Contribution to the OECD project on Taxation, Innovation and the Environment, COM/ENV/EPOC/ CTPA/CFA(2008)33/FINAL and Martin, R., L. de Preux and U. Wagner (2009), “The impacts of the Climate Change Levy on business: evidence from microdata”, Grantham Research Institute on Climate Change and the Environment, London School of Economics, Working Paper No. 6, August. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w51

PART I: Present Policies and Challenges The situation we now find ourselves in, the UK and Continental Europe, is a mix of carbon pricing, technology-specific support mechanisms and targets for renewable power. The interaction between these instruments and electricity market design can be troublesome, and there are at least four specific challenges associated that arise with this policy mix.

1. Reprise: low-carbon electricity and investment Creating a low-carbon electricity system requires a huge capital investment over the coming decades. The liberalisation of electricity systems has been very effective in driving down the costs and prices associated with operating existing systems, but less effective in attracting new investment, except into low capital CCGTs. Zero carbon sources are very different: most renewables, and nuclear power, are very capital intensive, with relatively low operating costs. The scale of the different shares of investment, O&M and fuel costs between fossil-fuel based generation and some low-carbon options are shown in 1: capital accounts for more than half the levelised costs for nuclear, wind and solar alike, in sharp contrast to conventional options. A move toward any of these low-carbon generation options implies a radically greater capital intensity.

Figure 1 COMPOSITION OF LEVELISED GENERATION COSTS AT 5% DISCOUNT RATE SOURCE: (IEA 2005)29 100% 90% Fuel 80% 70% O&M 60% Investment 50% 40% 30% 20% 10% 0% Coal Gas Nuclear Wind Solar

At the risk of repeating now well-known issues, this has two crucial implications: — Zero carbon sources will tend to operate as baseload, ahead of fossil fuel sources, because they are cheaper to run and need to run as much as possible to recover the cost of capital; and — The cost of capital is all-important to developers and is crucial to determining the cost of, and our ability to move towards, a low-carbon electricity system. Returns to investment in low-carbon electricity generation at present depend upon the electricity price, along with any additional support policies. In competitive wholesale electricity markets, such as that that exists in the UK, the price is set mainly by the marginal unit of generation. In the UK this is predominantly gas or coal- fired generation, as determined by the combination of fuel and carbon prices. Crucially, this means that in the mainstream market the price at which a low-carbon investor can sell its product bears little or no relation to its own costs. It depends instead upon the volatile prices of coal, gas and carbon faced by the fossil fuels generators.30 In the absence of other targeted support, this amplifies risks to investors in low carbon plant and raises the cost of capital—increasing overall costs and reducing incentives to invest, for the very sources that are central to low-carbon futures. Doubling the cost of capital (effective discount rate) from 5 to 10% can increase the cost of nuclear and wind by around 50%, with far less impact on the cost of fossil fuel generation. At 5% discount rate, nuclear and (onshore) wind can compete comfortably; at 10%, they are uncompetitive—and the cost of transforming to a low carbon electricity system would itself be about 50% higher. An investment environment that minimises the cost of capital will be crucial; the current structure does not do this. 29 See also various reports by UKERC for cost structures of different specific UK generating options 30 In economic terms, zero carbon sources are all infra-marginal, but in the absence of other measures will receive a price set at the margin over which they have no control—and limited capacity to predict. In practice, most renewables are covered by other support schemes, reducing the role of the electricity market itself. This submission does not address directly the pros and cons of the UK ROC scheme vs feed-in tariffs, but does argue the need for some vision of when and how to integrate renewables investment into mainstream electricity regulation in the long term. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w52 Energy and Climate Change Committee: Evidence

UK scenarios for decarbonising the power sector imply that the UK system should get about 90% of its electricity from zero carbon sources within 20 years, from a massive investment programme mainly in renewable and nuclear costing potentially over £100 billion. This is a staggering scale of investment, and yet the existing approach implies that this should be ﬁnanced on the basis of future electricity sales at a price that has little to do with the cost of all that investment, but is a function of gas, coal and carbon prices—with added incentives eg for renewables over which the investors limited foresight or control. This is likely to prove a very expensive way of funding £100 billion of investment, if indeed it delivers at all, which is clearly in doubt. Acceptance of this basic insight underlies the EMR. It bears repeating, simply to underline not only the scale of the challenges, but its two distinct components: capital intensity, and the fact that the investments sought would be “price takers”, from fossil fuel and carbon markets. A structure to provide greater stability and security for the long-term infrastructure-type investments required might need to look very different from the spot market system we have today. The main solutions considered to date largely take the incentives out of the hands of any market. Whilst this forms the central challenge, there are three other difﬁculties that also inform the reasoning behind this submission’s approach to long term contracts.

2. Innovation in electricity We require innovation across a range of technologies, yet private R&D expenditure in electricity (per unit turnover) has been just a tiny fraction of that in the most innovative sector of pharmaceuticals and software and computer services (Figure 2).31 Much of the current technology embodied in generation, transmission and distribution is based upon the technology used a century ago. The reasons for this are still inadequately appreciated, but comprise several mutually reinforcing explanations. One is the sheer scale and technological risk associated with the heavy engineering implied in converting large amounts of power. Another plausible factor is that for most of last century, power systems were run as regulated monopolies. It was hoped that liberalisation would inject more innovation. In terms of operating practices, it has; and yet liberalisation has been accompanied by further collapse of R&D expenditure, as investors sought quick returns. Overlaying these is the fact that electricity is the ultimate homogenous good. At the point of consumption, all electricity is the same. This means that there is little product differentiation in electricity: the only differentiator is price. This greatly reduces the incentive to innovate. A new way of generating electricity has to compete purely on price against incumbent technologies that have beneﬁted from decades of development, economies-of-scale, and regulatory adaptation. They might be aided by a carbon price, but that—a price differential, driven and constrained by politics—is the sole basis on which low carbon innovation has to recover all of the costs and risks of its R&D. Thus new innovations in electricity can’t command a large economic margin by offering consumers products with unique characteristics, protected by the monopoly guaranteed by patents (as with pharmaceutical), and/or consumers chasing the latest gadget (as with IT).

31 Although it depends on the deﬁnition of the electricity sector, for example Siemens are classiﬁed in the Electronics sector, yet some of their products may be applicable to the electricity sector. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w53

Figure 2 R&D INTENSITY PER SECTOR (DEPARTMENT OF INNOVATION, UNIVERSITIES AND SKILLS 2008) R&D intensity per sector (Top 10 companies per R&D expenditure)

Pharmaceuticals & biotechnology Software & computer services Technology hardware & equipment Health care equipment & services Leisure goods Aerospace & defence Electronic & electrical equipment Automobiles & parts Chemicals Industrial engineering Travel & leisure Personal goods General industrials Household goods Support services Oil equipment, services & distribution Food producers Fixed line telecommunications Media Construction & materials Banks Electricity Industrial metals Oil & gas producers Gas, water & multiutilities 0% 2% 4% 6% 8% 10% 12% 14% 16% 18%

Ofgem’s low carbon network fund is an ambitious effort to ﬁll the gap, but cannot wholly compensate for the weak market incentives for innovation. Yet innovation on the scale of IT or pharmaceuticals is what we really want for the challenges ahead. The suggestion in this submission offers an attempt to strengthen the potential for consumer-driven innovation for low carbon electricity.

3. Consumer interest in low carbon electricity Some consumers, groups, and companies would value the potential to use low-carbon electricity. Finding ways to harness consumer purchasing power more directly in the transition to a low-carbon electricity system could help drive the innovation required and raise the political acceptability of the undertaking. In the UK consumers have a range of “green tariffs,” but as noted below these are somewhat problematic and uptake has been modest, just 319,000 in 2009 (OfGem 2009). Empirical evidence of the willingness of individual consumers to pay for green energy is mixed. Interest in purchasing “green energy” is however not conﬁned to households. Several major UK companies, accounting for a signiﬁcant fraction of UK electricity demand, have pursued a strategy of wanting to buy green power often for CSR reasons. However in June 2008, DEFRA prohibited companies from claiming credit for purchasing electricity through the present green tariffs in carbon accounting or environmental reporting, due to problems with double-counting given the regulatory structure. This extends to companies under the UK’s Carbon Reduction Commitment (CRC) which have to count all their electricity purchased from the grid at a single emissions grid average. Only on-site renewable generation can avoid this, creating an obvious distortion. The reality is not that all customers treat all electricity the same. There is a diversity of electricity customers, with varied willingness-to-pay for a product they believe to be “environmentally clean”. The present market structure makes it hard and/or unnecessarily expensive for them to exercise that preference.

4. Electricity prices, carbon leakage and carbon attribution Carbon prices increase the cost of fossil-fuel based generation and in competitive markets this passes through to wholesale electricity prices, increasing tariffs for both households and industries. In terms of economic incentives the pass-through of carbon prices is desirable, but gives rise to two kinds of problems. One obviously is the distributional impact on consumers—individual, and corporate—and the political resistance this creates. The resistance may be magniﬁed if they do not have a clear alternative to consider of buying low carbon power that is free from the carbon price. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w54 Energy and Climate Change Committee: Evidence

The other is the concern about “carbon leakage” from impact on industrial costs. The most extreme case is aluminium. Over 80% of emissions from aluminium are from electricity, and they represent about 4% of total emissions from the EU ETS. Aluminium firms could relocate if the indirect cost they face from carbon pricing is high enough. For many energy-intensive industries, these indirect costs from electricity prices are small relative to the direct costs from emitting CO2, but are not insignificant: the electricity-related costs associated with paying€30/tCO2 would add more than 4% of Value Added to the cost of industrial gases, inorganic basic chemicals, paper and paperboard, and steel electric arc furnaces. Free allocation is being used to “protect” most energy intensive industries in the EU. This in itself a highly imperfect approach. Border-levelling of carbon costs (charging embodied carbon on imports, and repaying carbon costs on export) would, from an economic and environmental perspective, be far better. For compensating direct emissions, numerous analysts (including by the present author) have argued that border levelling can be implemented in ways compatible with WTO rules; the WTO itself emphasises that various forms of border levelling can meet criteria to ensure they are compatible with world trade law. However this requires attributing emissions to products, which is much more difficult—to the point of almost impossible—for electricity-related costs. Trying to attribute to a specific product the carbon intensity of electricity drawn from a power grid would be replete with scope for dispute.32 No amount of supply-side incentives—carbon prices, feed-in tariffs, etc—can overcome this problem, they just add to the costs. These four factors—structures that seem inadequate in terms of investment incentives, innovation incentives, consumer engagement or carbon attribution to industrial products—add up to a powerful and difficult set of challenges. A key point of this submission is that alternatives should be evaluated not only with respect to the first, which is driving force behind the EMR, but in relation to all.

PART II: On Pricing and Long-Term Contracts: Preserving a Role for the Buyer 5. Overview: the recentralisation of electricity policy? Part II of the submission considers the challenge of developing investment incentive structures that could rise to the considerable challenges identified in Part I. The EMR identifies several options, and this submission does not attempt to cover the span. It touches briefly upon the role of, and architectures for, a carbon floor price; and then concentrates on the case for a specific approach to long-term contracts. First an important word of context. One effect of the developments during the 2000s is an apparent emerging conflict between the agendas of liberalisation, and the environmental agenda. Fundamentally, it seems the government needs increasingly to try and engineer investment that would not otherwise happen in the short- run, competitive market that it has created, by adding more rules, special incentives, and constraints. There seems to be an increasing risk of the environmental agenda unrolling the liberalisation agenda and pushing us back towards centrally planned power systems (a concern articulated for example by Malcolm Keay among others). When we reflect on the nature of the UK electricity market—aimed to minimise costs and risks on short term financial perspective, driven by shareholder interests, and with rules designed to force competition through regulatory oversight and limiting the scope for long-term consumer commitments (eg through switching provisions)—this is not so surprising. It suggests a deeper level of challenge that needs to be considered. Some, pointing to the environmental and other inadequacies of the current system, welcome this. I “cut my research teeth” in the days of the Central Electricity Generating Board, which clung to coal and nuclear generation as the only serious options. One does not need an ideological approach to free markets to be uneasy about a trend towards greater State determination of energy investment choices. To date, UK efforts to promote environmental goals in the market framework have led to growing complexity, and/or reduced flexibility. The ROCs scheme has evolved closer to central direction, set to operate at the “capped” price and with technology-based banding to support the growth of diverse technologies. “Green power” tariffs have to pass a complex set of assessment criteria to try and avoid double counting of renewable energy with the ROCs support and Levy Exemption Certificates. Obviously, their “additionality” could be ensured if suppliers of green tariffs had to retire ROCs, but the price of ROCs reflects the cap price including the many elements of market risk premium that others have noted, not the actual cost of most renewables— thereby making this approach to “green tariffs” prohibitively expensive. An important option in the debate is to set a floor price to carbon. This submission does not address this in detail, but in my view much depends upon the form a price floor might take. A floor price set by an EU-wide reserve price on allowance auctions is not in itself an interference in the market. In principle, it is a simple mechanism that can reduce the cost of capital, by reducing downside risks in the face of inherent economic uncertainties: it offers an automatic self-correction of the target if events prove the initial level of ambition to 32 The most inherently WTO-compatible approach to border levelling suggests starting with a fixed “benchmark” based on the carbon intensity of the best available technology. However for electricity-intensive products, the best available technology from a carbon emissions perspective would involve zero carbon power, with no carbon costs—negating the point of the border levelling. And for export adjustments, it would be similarly hard or impossible to get consensus on the level of adjustment, unless a producer could plausibly demonstrate direct association with a specific power source and a trail of the carbon costs incurred. This is impossible under our current regulatory structures, because it is impossible to associate a given power source with a given electricity consumer. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w55

have been weaker than expected. However this is different from a floor price that takes the place of an inadequate level of ambition in the EU wide emissions cap. In turn, achieving an EU floor price—whether a genuine hedge against uncertainty or a substitute for an inadequate cap—would be preferable to a UK-alone solution. The current focus on a UK-specific floor price is second-best: it reflects the relatively weak nature of the EU’s current 2020 ambition, the related lack of serious EU debate on a floor price—and the now-limited timespan of EU ETS Phase III. It may be useful for specific UK investment purposes, but will in turn face limitations on the level that may be contemplated, not least arising from concerns about inta-European competitiveness impacts on downstream industry. Against that background a carbon floor price may be useful but does not in itself address all the obstacles to capital-intensive, low carbon investment noted in Part 1 above. Another option set out in the EMR is for long term contracts. Carbon Contracts have been proposed separately for example by both Newbery and by Helm. As initially conceived these would be project-specific contracts in which the Treasury would sign a contracts-for-differences on the carbon price, in effect guaranteeing a minimum carbon price to project investors. The economic logic is impeccable: carbon price risk is driven by politics, it makes sense for the political system to underwrite the risks if it wants private sector investors to assume a particular level of ambition. An extension, which would further reduce market risks, is for direct long-term power contracts. These could take the form of mandated feed-in tariffs, or could be established between the government and investors through some kind of auction mechanism. Such approaches could address many of the obstacles to capital-intensive investment and are rightly now the topic of extensive debate around the EMR. There are implementation challenges arising from the project-specific nature of the “contract-for-difference” proposals, concentration in the power market undermining auctions, and the understandable reluctance of the UK Treasury to take on the liabilities or costs that most contract proposals would imply. The Treasury may desire an adequate price for investors, but not to the extent of being keen to underwrite a price largely outside its control using UK taxpayers money. Moreover, most of these proposals place the government in a much more central position in the power markets. The fundamental tension is that the government would be—rightly in my view—trying to facilitate long-term, low carbon investment by reducing the political risks, for which it seems that placing the government as determining or underwriting the price is the only option.

6. Transferrable long-term, low-carbon electricity contracts Most of these improvements—carbon floor prices / FITs / auctioned contracts, are targeted at the first of four issues surveyed in Part 1: investment. Differentiation between technologies may support “learning by doing” but they do little for innovation per se—a lack of which has resulted in the UK and EU launching major publicly-funded innovation programmes to try and compensate for the lack of private R&D. And they do nothing for the accounting of carbon or carbon costs in industrial products, or engagement of consumers. Indeed, on the last of these most policies have achieve exactly the opposite, leaving the consumer faced with one metric—a cost per kWh—in which suppliers, in their different ways, subsume together all the different kinds of support and incentive costs. This submission, based on a Working Paper published last year with the Cambridge Electricity Policy Research Group, offers a case for a different way of conceiving long-term contracts. The basic proposal is that the emphasis should be on facilitating long-term, low-carbon electricity contracts between private sector producers and consumers. The government’s role would be to create the market structure, which would have to operate alongside the existing (or altered) structure of electricity generation and supplier markets, and to the extent necessary underwrite contracts. One way into this could indeed be for the government to be an initial purchaser, but with the aim of selling contracts on to third party buyers. Specifically, this would require the government to facilitate the development of a market for long-term, zero- carbon power contracts—a specific, regulated contracted “green power” market, which could operate alongside the mainstream conventional power market. A core feature would be to allow final consumers to associate in consistent ways with zero carbon electricity production, from sources that their contracts would help to fund. This would require active regulatory and policy decisions in several dimensions. To secure investment, such contracts would have to be long term; current regulations at the consumer end seek the opposite. However, a long-term contract on the generator side does not necessarily preclude the ability to trade contracts (which might be particularly relevant as an option on the consumer side). Over time, driven in part by a rising carbon price, more investment might be contracted through what might best be termed a “Green Power (GP) Contracts Market”. To be clean, the entire accounting framework would need to clearly delineate such GP contracts from the rest of the power system, including in terms of its carbon intensity. Such a differentiation would allow holders of such GP contracts to claim credit for purchasing low-carbon power in calculating their carbon emissions, either for regulatory (eg CRC) or voluntary purposes. This would increase the incentive for firms to purchase and invest in low-carbon power, and allow those who would like to, to purchase and claim credit for it. It cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w56 Energy and Climate Change Committee: Evidence

could provide a means for those consumers who wish to pay extra for renewable power to make the purchases they desire. It is thus an extension of market principles—not the reverse.33

In some respects this has much in common with established contract proposals: unless and until an adequate carbon price is attained, the government would probably still need to underwrite the contracts. In other respects it is a radical proposal: it would in effect imply creating a separate kind of electricity at point of consumption— one directly associated with zero emissions, high capital and low operating cost plant—and designing contract structures accordingly. The structure might have more in common with mortgages, than with the current spot price, and would not necessarily be per kWh: it could be a ﬁxed payment charge, conferring entitlement to a maximum kW, or a total kWh.

Some consumers might wish to purchase both “kinds” of electricity—a GP contract for a basic level of use, topped up with purchases per kWh (maybe from another supplier) that would reﬂect the marginal operating cost of the system. The combined economic structure would then be akin to a ﬁxed + variable charge, or other “rising block” tariff—except that the size of the “base” component (if any) would be entirely in the hands of the purchaser.

Note that the carbon market remains central to the economics of this approach. As the carbon price rises, the relative value of GP contracts would correspondingly increase. It is this that makes a growing non- governmental role in a GP contract market economically plausible. But the financing of the power investments would not be at the mercy of the fluctuating markets in coal, gas and carbon; they would be securitised through long term contracts that reflect the cost structure of the generating sources in that GP contract market, not the fluctuating spot price determined by current fossil fuel and carbon prices.

Thus, in terms of the four challenges discussed in Part 1: — Establishing such a GP contract market would reduce the financing costs, and thereby reduce the cost of investment in low-carbon electricity. To use Walt Patterson’s term, this parallel market would be better suited to the “infrastructure electricity” that new green power will supply. Long- term contracts for green power could be based on their own costs, and allow more certainty in repayment of the large initial capital costs, reducing the cost of capital. From a Treasury standpoint, it would presumably be welcome to bring new sources of private capital to help finance the UK electricity sectors’ transition. — The product differentiation from such a division could create extra incentives for innovation into low-carbon power, and help to create the missing demand-pull for low-carbon technologies from consumers, both large and small. — Such differentiation could also help create a system in which major industrial consumers, such as Aluminium, could accurately and legitimately establish a basis for avoiding carbon costs. Adopted more widely, this might provide a way for any border attribution to legitimately focus on carbon- related costs: charging imports, unless producers could produce evidence that they were drawing power from zero carbon electricity contracts, in which case they could be exempt. — Finally, this would provide a way in which diverse, large-scale electricity consumers could express their potential preference for low carbon power in the market—without the extraordinary and unsatisfactory hoops that have emerged to avoid double counting for existing schemes to small consumers, and the de facto ban on large consumers entering at all. It would thus provide a ready alternative to the bizarre situation in which the UK, whilst extolling the need for a rapid and costly transition to zero carbon sources, specifically prevents the major companies participating in the Carbon Reduction Commitment from claiming any credit for investing in zero carbon generation.

7. Challenges and Precedents

Given these potential advantages, is it possible to create such a structure, and could this be done in the context of our current regulatory regimes?

There are a number of hurdles that would need to be overcome.

“Green power” contracts would need to ensure that low-carbon power sold is matched by low-carbon generation average over a suitable time period, to account for variability. The UK already has models for this, in terms of rules around Levy Exemption Certiﬁcates. The creation of a separate low-carbon product alongside standard grid electricity would require the carbon intensity of the mainstream electricity market to be calculated separately for use in regulatory instruments like the CRC, or in voluntary carbon footprinting—with separate accounting for the electricity denominated in GP contracts. 33 This would also facilitate (though not resolve entirely) the dilemma that any cap on generator emissions “disenfranchises” consumers from claiming any carbon reductions from reducing their electricity consumption. The EU ETS cap for post 2020, for example, could be explicitly debated in terms of electricity sector emissions net of the volume of GP contracts; such contracts could thus legitimately claim to be contributing to ongoing carbon emissions, by reducing the demand for carbon-based generation and thus facilitating tougher carbon caps on the rest of the system over time. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w57

Of course, long-term contracts are nothing new. Indeed, they already exist in the electricity arena. The Finnish contract under which pulp & paper industry contracted to a new nuclear power plant, underwritten by AREVA, is the most famous recent example—though not an encouraging one, given the scale of delays and cost overruns. This reflects one reason why such arrangements are rare. A contract between an individual buyer (or a fixed consortium) and a single power plant poses big risks for both sides. A generating company that builds and operates the plant faces the risk of having a single purchaser, while the counterparty is dependent on one single power source, with the inherent risks involved: — If the buyer goes bust, the power plant is exposed—this has been a major reason cited why most generators have not pursued long term contracts with some of Europe’s major industrial consumers. In a globalising world, and witnessing the struggles of European heavy industry, the longevity of a specific industrial plant is just considered too risky to finance a major power plant construction; and — If the contract is focused on a single huge new power plant, the buyer is exposed if that goes wrong—as with the Finnish reactor.

That is why transferability, and government underwriting, would be important to lower the risks.

There is at least one other major example in Europe, which seems more relevant, namely the French Exeltium contract (see box). However, even this reflects rather special circumstances and it may be neither feasible, nor necessarily desirable, for this exact model to be more widely replicated. The French Exeltium Contract* In this contract, a consortium of electricity intensive industries combined to structure a long-term partnership with energy producers. The total value is€4 billion, funding a 24-year contract with EdF. Four French banks led a consortium of ten banks to provide a€1.7 billion loan, supplying electricity to the syndicated consortium of about three dozen heavy electricity consuming industries. The deal reached financial closure in April 2010. The cost to the consuming industries are differentiated between a fixed part at the start of the contract reflecting the investment cost, and a variable part in line with operating costs of the plant. Thus, the cost structure of the Exeltium contract broadly matches that of the generating plant, considerably reducing the cost of capital. By some pooling of demand (with a consortium of consumers), some of these risks are reduced; the electricity supply risk is underwritten through EdF. However, there seem to be major obstacles to the wider use of such contracts. One relates to political and legal acceptability. The Exeltium contract required approval from the European Commission, which was granted after considerable negotiation. However there was strong indication that this was considered to be an exception (presumably aided by strong support from the French government) and that in general such contracts would face difficulties as they are perceived as potentially anti- competitive. Another obstacle is that the conditions themselves are not so easily replicable, reflecting as it does the nature of the relationship between French industry, banks, and EdF, mediated to a large degree by the French government. The proposal in this paper is not that the Exeltium experience should itself be replicated, but rather that the underlying objective—long term contracts between suppliers and consumers of electricity—has potentially multiple benefits. Policy can learn from such experience, and rather than impede should facilitate more generic tradeable long-term contractual structures, and engage a wider group of electricity consuming organisations, more explicitly linked to the huge task of decarbonising European power generation. *Sources: Reuters, 13 Apr 2010; Simon Cotterill, Presentation to CBI Energy Conference, 2009.

The core argument of this paper is that long-term contracts are desirable, but that they need to be embedded in a structure that would facilitate transfer of such contracts. Structured in the right way, making long-term contracts transferrable can reduce risk to both generators and consuming parties.

Creating a transferrable contractual structure would be crucial to such arrangements, allowing aggregation of buyers to finance large investments, for example, and allowing firms to acquire or divest such contracts as their financial situation (and CSR policy) dictates, within prescribed rules that protect the underlying financing commitments. The great difficulty with such an idea is the potential diversity of such contracts—how would one trade a 15-year contract with one finance and risk structure with another of 20 years and a completely different finance and risk structure? This is why it cannot emerge on its own. Some degree of diversity is probably necessary and healthy, but the need for some liquidity in such a contract market would imply two things: a need for a publicly defined framework for a limited number of “qualifying” contract types; and as wide a market as possible. More specifically, there needs to be a government-led process that establishes a basic structure of such contracts, and that facilitates competition between those entities that are interested in securing stable, zero carbon long term power contracts. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w58 Energy and Climate Change Committee: Evidence

Why link the long-term contract market to zero carbon power? Fundamentally, because of all the reasons set out earlier in this paper: — decarbonising power generation is one of the major public policy challenges of our times, and low carbon generation is almost all very capital intensive and infra-marginal; — the electricity system suffers from insufficient innovation in general, and specifically in relation to low carbon innovation given the industrial discounting of political uncertainties around the carbon market; a market for long term contracts could widen the space and incentives for innovative approaches, — the ability to demonstrate zero carbon generation in legally secure, verifiable and trackable ways is crucial to attributable power-related emissions in any system of border leveling; and — there are a substantial body of electricity consumers whose interest might be driven partly by the desire for low carbon power and/or long term stability separate from the fluctuations of fossil fuel and carbon prices—considered further below. One open question is how to design such a market interface in open competition with standard grid electricity, where consumer switching of suppliers is strongly encouraged. Individual consumers seem unlikely to be the main participants in long term contracts anyway, but there may need to be some re-examination of the rules if consumers were interested in long-term contracts. At some scale, preventing or impeding mutually assenting parties from entering long-term contracts can no longer be presented as a way of preventing market abuse, but risks instead impeding another sort of competition—one which might be far better suited to fostering the investments required. These are big questions and I do not pretend to have all the answers, but the issues need examining. Another key question is how such a GP contract market would relate to existing support structures, notably for renewable electricity. Clearly, if a country has a mandated renewable energy cap (as in theory does the UK) that it is set to achieve, then GP contracts could only increase the renewable energy investment if they retire credits (ROCs in the UK case). However even in the UK the system is subject to a “cap price”. With feed-in tariffs, the question is whether any investor would wish to sign such a contract, compared to the returns available under a feed-in tariff. This is an empirical question, not a fundamental conflict. Moreover, a key goal of GP contracts would be to provide a more secure “convergence point” for a sector if and as technology-specific supports phase down. At present, the proposition appears to be that low carbon technologies will benefit from an extended period of support, whilst there is an “industry-building” case for supporting the implicit innovation, or compensating for an inadequate carbon price—but will then have to fend for themselves on the basis of a market determined entirely by short-run marginal prices of fossil fuels and carbon. After supports expire, leaving many GW of capital-intensive plant, this is a recipe either for windfall profits or eternal financial restructuring of bankrupt projects that cannot cover their loans. GP contracts could offer a much more robust answer to the question of whether and how we could ultimately move beyond current technology-specific supports. The carbon price would still be crucial—but alongside it, there would be a market structure more appropriate for existing “infrastructure” generation—and for supporting continued investment in low carbon technologies if and as other supports expire.

8. Potential purchasers A key question is who might want to buy such long-term, zero-carbon power contracts. There are three broad approaches to answering this question. One is to speculate, based on current indications and possibilities. Many consumer-facing companies already have clear environmental goals, and have expressed frustration at the current rules that make it so difﬁcult for them to purchase genuinely low carbon electricity. Examples exist in telecoms, supermarket chains, and ﬁnancial services; companies like TESCOs and Marks & Spencer are also starting to market electricity to consumers under their own brand, and might prefer to be able to offer genuinely zero-carbon electricity. CRC participants, that currently have to pay for carbon in their electricity even if they might pay for zero carbon electricity, is an obvious place to look. Depending on cost differentials, some electricity-intensive industries might welcome the certainty of moving to such contracts as their current contracts expire. In addition, the recent government move to allow local councils to sell electricity might open up a whole new kind of purchaser, more closely aligned to domestic markets, that might sell “clean power” on to local consumers. Each of these might inject preferences for different kinds of zero carbon power; several might also help to engage citizens more in the choices about low carbon investment, reducing some of the political obstacles that emerge (eg opposition to onshore wind energy, despite its cheapness) when the incentives for investment become too disconnected from civil society. Indeed, underlying the thinking there lies a strong element of organisational and behavioural economics, in which the degree of control that people have over their choices is an important motivating factor. There are obvious parallels with the various proposals for “green bonds”, and buyers could of course include pension companies, for example. However its distinctive feature is its potential to help electricity consumers of different sorts connect with—and help to fund—electricity sources of their choice, through the electricity they purchase. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w59

A second approach is simply to wait and see: to argue that one never knows, until one tries, what the demand for a new product might be. “Green tariffs” to date have been presented as a green version of conventional energy, set purely at a price per kWh—not presented in the form of a long-term offering more akin to a mortgage. Discovering the scale of demand could itself be valuable.

The third approach notes that ultimately, the leverage of carbon price remains in State hands. If there is insufﬁcient investment in low carbon electricity sources, in addition to contracting more itself, the government could increase the carbon price, to improve the competitiveness of the “GP contracts market”. And that, indeed, is one additional advantage. Many of the proposals for support mechanisms, including long-term contracts with government as the purchaser, marginalise the role of the carbon price. Having put huge political effort into creating a carbon price, for sound reasons, it would seem very strange to then sideline its role in long-term electricity investments. By creating zero-carbon electricity contracts as a separate commodity, in competition with “normal”, high carbon electricity at the point of end users, the carbon price would remain a key driver of a market-based switch to low carbon investment.

9. Conclusions

Creating a low-carbon power system is a cornerstone of the move towards a low-carbon economy. This requires huge investment and extensive innovation. Our current electricity market structures create large uncertainties for investors, and have incentivised little private innovation and R&D. We have put in place policy instruments to try and address these problems. ROCs and feed-in-tariffs create greater certainty over returns to investment, and boost demand for renewable power. Both of these policies have had their successes, but also face long-term limitations.

Harnessing consumer, business and industry demand for zero-carbon electricity can help raise investment in low-carbon power, and also increase the political acceptability of the endeavour. Our current market structures do not harness this demand, and the systems we currently have in place struggle to provide clearly additional zero-carbon electricity to consumers. Creating a clearly deﬁned separate low-carbon electricity product could help to harness this demand and capital, and could carry a number of other beneﬁts as indicated.

The idea is only presented for consideration: it is not a proposal that has been rigorously explored and debated. Closer examination might reveal insuperable obstacles, or show advantages to be less than they seem. With the EMR process, however, the UK is at a major juncture, and has the kind of opportunity for major reform that only arises every couple of decades. Whether and how to create a separate contractual market that allows end-user competition between zero-carbon electricity and the rest of the system requires more research and analysis, but it is surely an option that should be seriously debated in the EMR process February 2011

This submission is drawn from a published working paper: Tim Laing and Michael Grubb, “Low-Carbon electricity investment: The limitations of traditional approaches and a radical alternative”, Electricity Policy Research Group, Cambridge University, September 2010 (www.eprg.cam.ac.uk). References are contained in that working paper.

Memorandum submitted by Alex Henney, EEE Ltd

A SENSIBLE COMMERCIAL FRAMEWORK FOR NUCLEAR POWER

Summary

There has been much wheel spinning (and in the case of the Renewable Obligation substantial waste of customers’ money) considering how to meld expensive low carbon plant into a market. There should be a clear understanding that nuclear power plants (and windmills) are not being developed for economic reasons— they are manifestly not economic compared with gas plants—but to meet government environmental policy. Consequently the energy market as an investment mechanism is not a relevant consideration. The ﬁnancial risk of such plant should not be increased by exposing them to irrelevant risks; rather the aim should be to insulate their revenue from market price risk, and furthermore to minimise the cost of capital.

The British government has a long and lamentable history of incompetence in dealing with nuclear power, which has led to wasting many tens of £billions. It should learn from practice in other jurisdictions, notably Ontario and Georgia, where there are signiﬁcant nuclear developments: — In Ontario the Bruce Power A nuclear plant is being refurbished at a cost of Can$5.25 billion. The power is being paid Can$63/MWh indexed by the Consumer Price Index. The developer assumes the construction and availability risk. The post-tax weighted average cost of capital (WACC) is reported as being in a range 10.6% to 13.8% nominal. The contract is open book to the Ontario Power Authority. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w60 Energy and Climate Change Committee: Evidence

— Georgia Power Company (GPC) is the developer and has a 45.7% share in the ownership of the Westinghouse AP1000 Vogtle 3 and 4 units (the other owners are municipal entities). The construction cost of the contract is $9.8 billion while including interest during construction the cost is estimated at $14 billion. GPC’s share of the plant is being built against a price approved by the Public Service Commission of Georgia, and the cost will be included in the rate base and allowed a WACC of 7.8% nominal post-tax. The price is based on an Engineering Procurement Construction contract, and the amount allowed in the ratebase will be subject to a performance bonus/penalty. The contract is open book to the Commission, who have recruited an experienced nuclear engineer to assist with the formalized monitoring procedure. In December 2010 the Commission authorized expenditure of $1 billion on GPC’s share of the work so far. As of the first week in March both the company and the Commission expressed satisfaction with the arrangements Common features of both schemes is that they insulate the plants’ revenue from any market; they have open- book contracts; and the resulting output is “blended” with other electricity. In the Energy Market Review DECC set its face against a regulated asset base approach for reasons that hold little water. Unfortunately DECC officials do not appear aware that GPC’s costs (and costs of thermal plant in California) are incorporated into the asset base on a regulated base. Mr. Atherton of Citigroup reported to the Committee that EDF will be seeking a post-tax nominal return of 10.5% (and other developers may seek more). According to Citi Investment Research’s model, using a construction cost of€3200/kW (which is in line with EDF’s claim of £9 billion for 3300MW) and their other assumptions, the resulting cost of nuclear power would be £74/MWh. With the 7.8% return of the Georgia Power financial framework, the resulting cost of nuclear power would be £56/MWh, which is 24% lower and allows significant cost overrun yet still leaves the customers ahead. It thus seems to me to make eminent sense to eschew talk of markets and their imagined disciplines (particularly as we have destroyed ours), but rather to follow the approach adopted in Georgia. Plant should be developed to an agreed cost based on Engineering Procurement Construction contracts which are open book to the relevant authority (which may be the government or Ofgem or a special agency set up for the purpose) and subject to expert monitoring review, with a performance payment/penalty at the margin. The cost would be the regulatory asset base on which the company would earn an appropriate—but modest—return. The resulting electricity would be blended with other electricity.

A Disastrous History with Nuclear Power The British government has a lamentable track record of incompetence and wasting taxpayers money in dealing with nuclear power, which I set out in detail in “The Economic Failure of Nuclear Power in Great Britain”;34 “A study of the privatisation of the electricity supply industry in England & Wales”;35 and “The British electric industry 1990–2010: the rise and demise of competition”.36 The economics of the Magnox reactors were fudged; most of the AGR programme was an economic disaster; the Sizewell Inquiry was intellectually fraudulent, if not downright dishonest; Sizewell B cost 40% more than estimate and was written down by £800 million for the sale of British Energy. Following the debacle of the withdrawal from the privatisation of the nuclear power stations in November 1989 the House of Commons Energy Committee conducted an inquiry into “The Cost of Nuclear Power”37 because: “After years of ofﬁcial assurances that nuclear power was (or could be) the cheapest form of electricity generation, Parliament and the public are entitled to know why it was only when faced with the commercial discipline of life in the private sector that nuclear power (from both existing and proposed reactors) suddenly became an expensive form of generation…we believe the Department of Energy, as the CEGB’s sponsoring department, must share the blame for this, since it apparently made no attempt to obtain realistic costings from the CEGB until it was seeking to privatise nuclear power…The manner in which the Department has supervised the CEGB over the years can only be described as inadequate.” By the early 1990s it had cost the British taxpayer and electricity customers more than £10 billion (in 2010 prices) in research and development and about £50 billion in capital expenditure, with another nearly £4½ billion for Sizewell B.38 Then came about £7.5 billion for the nuclear levy in the 1990s, then the government devised an unwise approach for British Energy to pay for decommissioning, which contributed to its demise. On top of this is a bill of an undiscounted cost of discharging all future civil nuclear liabilities conservatively estimated at about £100 billion.39 This is an awesome bill for “electrical energy in homes that is too cheap to meter.”40 34 The Economic Failure of Nuclear Power in Great Britain, Alex Henney, Greenpeace, 1989. 35 The privatisation of the electricity supply industry in England & Wales, Alex Henney, published by EEE Limited, 1994. 36 The British electric industry 1990–2010: the rise and demise of competition, Alex Henney, published by EEE Limited, 2011. 37 The Cost of Nuclear Power, Volume I, Energy Committee, Fourth Report, Session 1989–90, HC205-II, HMSO, 7 June 1990. 38 In addition to the shambles over “conventional” reactors, in current prices we wasted several tens of £bns on the fast breeder reactor and on the Thorp reprocessing plant. 39 The assessment was provided by Professor Gordon MacKerron, former chairman of the Committee on Radioactive Waste Management, in an e-mail to Alex Henney dated 16/12/2010. 40 Admiral Lewis L Strauss, ﬁrst chairman of the US Atomic Energy Commission, 16 September 1954. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w61

If the British government is going to mess again with nuclear power it behoves it to get its act together properly. In particular it should learn from others.

Nuclear Development and the Concern about Price Risk

Over recent years there has been much discussion about how to facilitate ﬁnancially the development of nuclear power plants because of the power price risk, see exhibit. UK price movements: 2007 to 2009 in € 120

100 Electricity forward 2010 (£/MWh) Gas cost forward (2010) + EUA 80 Coal cost forward (2010) + EUA EUA price in €/tCO2 60

0 1-Jul-08 1-Jul-07 1-Oct-08 1-Oct-07 1-Apr-08 1-Apr-07 1-Jan-09 1-Jan-08 1-Jan-07

Source: Newbery.41

In addition to the obvious point that the lower the gas price which drives the electricity price the less favourable is the economics of nuclear, the graph also brings out the volatility of gas and electricity price which are closely linked. Although gas (and coal) plant are automatically hedged against the volatility, as Professor Newbery has pointed out, nuclear is not: “The price of electricity in the forward market moves very closely with the cost of generating using either gas or coal, allowing for the cost of CO2 required for each. Although the prices of gas, coal, CO2 and electricity are separately highly volatile, (gas prices have fluctuated between 20p/th and 110p/th and coal has fluctuated from $50–200/ton between 2004–08) the forward clean spark spread and the forward dark green spread have remained far more stable. The reason is simple, the price of electricity is set by the cost of generating using the marginal fuel and the CO2 price moves to equate the marginal costs (including the EUA cost) of coal and gas. Companies with fossil generation are therefore naturally hedged against fluctuations in the input and output prices, while low-C electricity, whether renewables or nuclear, is exposed to the full volatility of the electricity price, as its variable costs are low, predictable and stable.”

The potential price risk to nuclear plant in a gas price driven market was more than adequately shown by the demise of British Energy in September 2002 following the collapse of prices that began in the winter of 2000–01. The wish to mitigate price risk has led to proposals for a carbon ﬂoor price and now in the government’s Energy Market Review a contract-for-differences.42 But in my view much of the discussion has been misplaced because it has started from the stance that the nuclear plants should operate within the framework of the market. Part of this storyline is that exposure to the market price provides the conventional incentives to construct and operate the plant efﬁciently.

In my opinion this approach is fundamentally ﬂawed and results in a higher cost of capital than needs be, and consequently a higher cost of electricity. This has been illustrated by the Renewables Obligation, which was a case example of an ill judged, complex and expensive scheme based on ersatz market principles. The starting point should in my view be that nuclear power plants (and windmills) are not being developed for economic reasons—they are manifestly not economic compared with gas plants—but to meet government environmental policy. Consequently the energy market as an investment mechanism is not a relevant consideration. The ﬁnancial risk of such plant should not be increased by exposing them to irrelevant risks; rather the aim should be to insulate their revenue from market price risk, and furthermore to minimise the cost of capital. This approach has been adopted for both the renovation of the Bruce Power A plant in Ontario, and for the development of the Vogtle 3 and 4 units by Georgia Power Company in the US. 41 A Nuclear Future? UK government policy and the role of the market, David Newbery, paper presented to the Beesley Lectures on Regulation in London, 22 October 2009. 42 This is misleadingly referred to as a FIT CfD—presumably the “FIT” part of the term is supposed be a semantic sop to the terminology in the Conservative election manifesto. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w62 Energy and Climate Change Committee: Evidence

The Ontario Approach to Financing a Large Nuclear Refurbishment In 2005 the Ontario government announced that it has reached an agreement with the owners of Bruce Power A to refurbish the plant for a cost of Can$4.25 billion. Subsequently in 2007 the agreement was extended to extend the refurbishment for an additional Can$1bn, resulting in a total investment of approximately Can$5.25 billion. In return, the provincial government, through the Ontario Power Authority (which is guaranteed by the provincial government), agreed through a contract-for-differences to pay an initial price for electricity of Can$63/MWh as of the date the Refurbishment Agreement was signed. This price is indexed by the Consumer Price Index. The Can$63/MWh is the only income the generator receives; consequently the plant owner bears both the construction risk and the availability risk. According to the Ofﬁce of the Auditor General of Ontario “Bruce Power and the Ministry agreed to an ‘open-book’ process, and the Ministry was given access to a data room containing conﬁdential documents provided by Bruce to support the refurbishment plans, supplemented by management presentations, facility site visits, and meetings with relevant government agencies”.43 The weighted average cost of capital (WACC) was a post-tax return in the range of 10.6% to 13.8% nominal.

The Vogtle3 and4 Reactors in the US The US Department of Energy is offering a loan guarantee to up to four nuclear plants in order to help pump prime development.44 The loan guarantee reduces the cost of development by lowering the cost of debt, but is not by itself a critical factor in underpinning development. The first scheme for which conditional45 loan financing of $8.3 billion covering 70% of the construction cost has been agreed for the Vogtle 3 and 4 Westinghouse AP1000 reactors with a total capacity of 2200MW in Georgia which is being developed by Georgia Power Company, an investor owned utility. It is taking a 45.7% share of the scheme and is the agent for development on behalf of the other owners, who are municipally supported generation production and supply entities. The construction cost of the scheme is $9.8 billion ($4500/ kW); the cost including financing is $14 billion. The loan guarantee effectively reduces Georgia Power’s cost of borrowing by $15–20 million p.a. Georgia Power will incorporate its share of the construction cost of the plant in its rate base, where it will represent an increase of about 34% of the current rate base (the financing charges during development are paid off as incurred). When the plants are operating their costs will be blended with the other generation costs together with transmission and distribution costs to construct the tariffs in the traditional US manner for a vertically integrated utility—there is little or no market based input. The Public Service Commission has certified a sum of $6.11 billion for Georgia Power’s share of the plant including the interest incurred during construction ($6080/kW) based on an Engineering Procurement Construction contract for the plant which is described as price defined turnkey contracts with Westinghouse and architect/engineer Stone & Wesbter. (Stone & Webster is a subsidiary of the Shaw Group, which also has a 20% interest in Westinghouse; Toshiba has a 65% interest). In December 2010 the Commission authorized expenditure of about $1 billion for Georgia Power’s expenditure thus far (representing about half of total expenditure) on procurement of long lead time items; excavation and preparation of foundations, and construction of buildings. The contract has provisions that share cost overrun between the contractor and the company. Although this is the first AP1000 built in the US it is benefiting from the experience of the three AP1000s being built in China which have similar nuclear islands and are three years in advance. There is extensive interaction between people in Georgia and in China. The staff of the Public Service Commission proposed an incentive scheme for the company consisting of a bandwidth of +$250 million. If the in service cost of the project is less than the lower threshold, then the Company could earn an incentive return of 10 basis points in the return on common equity for every $100 million the in-service cost is less than the lower threshold of the bandwidth. If the completed cost of the project is more than the upper threshold, then the return on common equity would be reduced by 10 basis points for every $100 million the completed cost is over the upper threshold of the bandwidth. The company objected to this, and the Commission upheld it and asked the company to see if they could negotiate a mutually agreeable incentive scheme. The negotiation is still in progress, but is hoped it will be concluded by the end of March 2011. The Public Service Commission has appointed an experienced ex-Westinghouse consultant to monitor performance with an allowed annual cost of $600,000. The Public Service Commission requires a Construction Monitoring Report every six months that includes actual expenditures for the January–June and July–December periods together with a narrative of activities and a forecast of expectation of final project cost. It must also include an analysis to show whether it is cost effective to move forward. Costs are certified in the subsequent 180 day period if deemed prudent. The contract is open book to the Public Service Commission. 43 Special Review for the Minister of Energy, Office of the Auditor General, http://www.auditor.on.ca/en/reports_en/brucespecial_en.pdf. 44 The Energy Policy Act of 2005 provides a number of incentives for “Innovative Technologies” which apply to “advanced nuclear energy facilities, including a loan guarantee for up to 80% of eligible project costs, http://www.ne.doe.gov/energypolicyact2005/ neepact2a.html. 45 The guarantee is conditional upon the Nuclear Regulatory Commission licensing the plant, which is expected late this year. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w63

There is no target load factor in the contract, and so at first sight the ratepayers assume all of the load factor performance risk. But the company has a performance based ratemaking scheme with a target allowed return on equity of 11¼% pre-tax nominal and a deadband of +1% within which the company earns what it earns. If the company earns over 12¼% in a year it keeps 1/3 of the earnings and returns 2/3 to customers; if it earns less than 10¼% it can request a filing to raise tariffs. Thus since the plant will represent about a third of the company’s rate base its operating availability will have a noticeable impact on the company’s profitability— thus implicitly there is a link between plant availability and company profitability. The company’s capital structure is approximately 43% debt; 10% preferred; and 47% equity; its cost of debt is about 5.8%; its cost of preferred stock is about 6.1%; its allowed pre-tax return on equity is 10¼–11¼% so its post-tax WACC is about 7.8% nominal. As of the beginning of March 2011 discussion with officials of Georgia Power Company and the Public Service Commission found satisfaction both with the arrangements in place and the progress on the plant.

The Foreign Lessons for a Commercial Framework for Nuclear In both Ontario and Georgia the market price risk is removed from the developer. In Ontario the construction and availability risk remain entirely with the developer, while in Georgia the developer bears some of the construction risk at the margin through a profit incentive scheme, and the company has an incentive to achieve a good level of availability through its general performance based ratemaking scheme. The Georgia approach results in a lower WACC (8.1% cfr 10.6% to 13.8% for Bruce Power). The Energy Market Reform Consultation paper argues against the Georgia approach, which is effectively a regulated asset base (RAB), commenting “It would represent the most fundamental change to the current arrangements of all the options; making such a radical change would be high risk. Moving to a RAB system would require the Government to sacrifice all market benefits and competitive pressures for greater efficiency, optimal operation and innovation that could be retained under other options considered as part of this project. The generation sector—where competition is viable and a key feature of the current market—is different to the natural monopoly market for the provision of transmission and distribution networks. As such, the Government does not consider this an attractive option for reform” (p66). The paper also argues that “the approach transfers construction risk, which generators are better able to manage, to customers.” In my opinion this rejection is not a soundly based regarding nuclear plants: 1. It is not at all obvious that this approach would in fact “sacrifice all market benefits” because those of optimal operation can be retained by a suitable contract structure. 2. Innovation in nuclear design is a slow process pioneered by manufacturers working for an international market and subject to an elaborate licencing process; it is not influenced by the British power market. 3. I do no consider that “competition is viable and a key feature of the current market.” With (i) the development of the complexities and economic distortions of NETA/BETTA; (ii) the vertical and horizontal consolidation of the industry into an oligopoly; (iii) the lack of liquidity in the contract market; (iv) the subsidies for renewables and quasi-planning for so much wind/4 CCS plants/possibly nuclear, the market long ago lost the semblance of competitiveness. It is overdue time we gave up the pretence that we have much of a generation market, let alone a competitive one, and recognize that flooding it with subsidized windmills, nuclear plants and CCS plants will destroy it entirely. 4. The claim that the approach transfers construction risk is a statement of hope, rather than of realization which will depend upon the eventual CfDs. It is perhaps noteworthy that not so long ago EDF Energy was claiming that it could bear the market price risk. Then it wanted a carbon floor price to mitigate part of the market price risk; now with a CfD it has probably got rid of the market price risk. Will it negotiate to the wire, then say that in the light of the cost overruns of the two EPRs being built,46 it needs help with construction cost risk? Then as the government increased the ROCs for offshore windmills to get the London Array going, it requires little imagination to work out the government’s response. 5. The 7.8% of Georgia Power’s development of the Vogtle 3 and 4 plants compares with the 10.5% that Mr. Atherton reported EDF as seeking. (Other developers may seek more—DECC’s consultant (Redpoint) assumes an 11.2% hurdle rate for a nuclear plant with a CfD). According to Citi Investment Research’s model, using a construction cost of€3200/kW (which is in line with EDF’s claim of £9 billion for 3300MW) and their other assumptions, the resulting cost of nuclear power would be 46 The performance of the two European schemes being built highlight construction cost risk: — The 1600MW Finnish EPR (European Pressurised Water Reactor) being built by Areva at Olkiluoto is four years behind its original target commissioning in 2009 and the construction cost has increased from€3 billion in 2003 money to€5.7 billion (€3,600 or $4,600/kW). Areva NP is claiming compensation of about€1 billion for alleged failures of Teollisuuden Voima Oy (TVO). TVO, in a January 2009 counterclaim, is demanding€2.4 billion in compensation from Areva NP for delays in the project (Agence France Presse, “Setbacks Plague Finland’s French-built Reactor,” 30 January 2009) — In May 2006 EDF estimated that the construction cost of its EPR at Flamanville would be€3.5 billion. Two years later An Areva official suggested that the cost will be at least€4.5 billion, although it was not specified whether this was an overnight cost (Nucleonics Week, “Areva Official Says Costs for New EPR Rising, Exceeding $6.5 billion,” 4 September 2008, p. 1) cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w64 Energy and Climate Change Committee: Evidence

£74/MWh. With the 7.8% return of the Georgia Power financial framework, the resulting cost of nuclear power would be £56/MWh, which is 24% lower and allows significant cost overrun yet still leaves the customers ahead. DECC’s lack of understanding of the issue was perhaps shown by a presentation on 3 March at the Policy Exchange which included a slide which stated that nowhere was plant investment based on a regulated asset base—this view is wrong (see my submission “Capacity markets and reliability options”).47 EDF definitely, and perhaps other nuclear developers, have the government over a barrel if it seriously wants the development of nuclear plants. It thus seems to me to make eminent sense to follow the approach adopted in Georgia. Plant should be developed to an agreed cost based on Engineering Procurement Construction contracts which are open book to the relevant authority (which may be the government or Ofgem or a special agency set up for the purpose) and subject to expert monitoring review, with a performance payment/penalty at the margin. The cost would be the regulatory asset base on which the company would earn an appropriate—but modest—return. The resulting electricity would be blended with other electricity. March 2011

Memorandum submitted by Mainstream Renewable Power 1. Mainstream Renewable Power is a leading renewable energy company developing renewable energy projects across several continents, including Europe, Africa, and both North and South America. The Company expects to be a major provider of renewable capacity for the UK and has a development pipeline in excess of 5,000MW. 2. In the UK, we are developing two large offshore wind projects; both of which are subject to the OFTO regime. In Scottish territorial waters we are developing the 450 MW Neart Na Gaoithe project. Through the SMart Wind consortium, we are developing the 4,000MW Hornsea Round 3 zone with our partners, Siemens Project Ventures. In the German North Sea, we are developing the 1,000 MW Horizont project. 3. In doing so, we will be attracting new sources of finance, encouraging new entrants to broaden and deepen the supply chain, and pursuing innovation at all levels to lower the cost of offshore wind. We are concerned that some of the proposals contained in EMR, if implemented, may militate against these goals. We provide below our response to the Consultation, together with detailed answers to the Consultation questions. 4. Mainstream Renewable Power supports the Government’s objective to decarbonise electricity generation in the UK. We believe that the current market arrangements will not facilitate the required rate of decarbonisation to deliver the UK’s 2050 ambitions, nor enable the UK to fully exploit its offshore renewable energy assets over this period. We agree that the incentives to invest in low carbon generation need to be strengthened, as do instruments to ensure that high carbon energy sources are not “locked in” to the energy mix, as the UK pursues measures intended to accelerate the transition to a low carbon energy sector. 5. The investment challenge for the UK electricity industry is the highest it has ever been, with both generation and transmission assets requiring renewal on an unprecedented scale. This represents a singular opportunity for the UK. With the appropriate suite of market reforms, skilfully delivered, not only will our ambitions for low carbon generation and the networks to support it be realised efficiently, but the consequent multiplication of investment benefit through additional high quality industrial activity, skills and jobs will provide a continuing benefit to the economy. 6. That is why it is important that the reforms are the right ones to bring about this necessary transformation; and have the broad support of both industry stakeholders and those parties who will provide the finance to enable the realisation of the vision. The confidence to provide this support will be underpinned by reform proposals which are clear, detailed and widely accepted, together with an implementation/transition plan which charts a low risk path from where we are now, to where we need to be. It is imperative that reforms are robust and enduring, to avoid the necessity of further near term revision and the accompanying damage this would cause to investor confidence. 7. Any proposed reforms must be based on the fundamental objective of promoting confidence, in order to ensure that there is not a damaging hiatus, or permanent diversion of investment away from the UK energy sector. It is vital that investment in renewables is seen as an increasingly attractive opportunity by all stakeholders involved in the sector. We look to the government to continue the constructive process of engagement as the Energy Market Reform (EMR) reform moves to the next stage of development. 8. We are particularly concerned that the preferred CfD mechanism presented in the EMR effectively removes capacity from exposure to the market and relies instead on central direction, with its attendant need for “perfect foresight” and constant corrections as events unfold. Further, by removing a significant proportion 47 I provided DECC in August 2010 with a paper which clearly explained in some detail that in the California energy market thermal generators are being built to a return on a regulated asset base, and is Georgia Power investment in Vogtle 3 and 4, “A multiclient project on developing trading arrangements for a windy electric industry”, Alex Henney, EEE Ltd, July 2010. cobber Pack: U PL: CWE1 [O] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Energy and Climate Change Committee: Evidence Ev w65

of capacity from the market, the fundamental operation of the residual competitive, liberalised market is inevitably compromised and distorted. 9. In order to deliver a fully decarbonised power sector, EMR must meet the following objectives, which are vital if offshore wind is to continue its contribution to the UK’s energy and climate change objectives: 10. Transform the RO into a low carbon premium FIT in preference to a CFD. Given the current trading arrangements for electricity in the UK, we cannot see how a CfD can be made to work. The UK does not have a sufficiently liquid electricity market (both transparent and accessible) to create a reference price on which to base a CfD. A premium FIT is better understood by investors, would operate more effectively in the UK market, and has greater similarity to current support schemes, so as to ease the “switchover” from the RO. A transition from the RO to a premium FIT would ensure that the momentum of the offshore industry is maintained, an essential requirement for any new investment in the sector. 11. Retain an obligation on suppliers to source electricity from low carbon generation. The RO has been successful in attracting all of the major UK electricity suppliers to the offshore wind sector. Not only is it necessary to have suppliers involved in order to provide a route to market for the power that sector will generate, but the presence of large established utilities has given confidence to the wider supply chain that they can make the necessary significant investments to supply the offshore wind industry. Any new support scheme, whether it be a premium FIT or CfD, must retain an obligation on suppliers. 12. Recognise that auctions are inappropriate to set support levels. Auctions have proven very ineffective at setting the price of renewable support schemes. The UK’s own experience with the Non Fossil Fuel Obligation demonstrated that those who win the auctions tend to do so at levels that do not allow them to deliver their projects. The industry has become used to the RO banding review process as a support setting mechanism and that should be the mechanism to deliver further adjustments to the levels of support for the sector. 13. Ensure that those who have already invested in the UK power sector are treated fairly. Government should ensure a transition process which adequately protects existing investment and provides the necessary confidence for industry to continue its expansion as we move forward to operation under the reformed arrangements.

Memorandum submitted by Carlton Power Carlton Power Limited is a UK independent power station developer and has taken forward gas-fired generation projects in the UK and Europe since the company was founded in 1995. To date, we have been involved with the construction of over 1,800MWs of installed electrical capacity and a further 2,380MW of consented plants in the UK. Consequently we have an in-depth knowledge of the energy market here in the UK and a strong sense of the changes that need to be brought into force in order to ensure security of supply and carbon targets without too high a cast being incurred by the consumer. We have been following the Select Committee’s inquiries relating to the EMR and welcome the attention given by the Committee to the lack of liquidity in the market. Carlton believe that many of the challenges that the UK energy market, most notably new investment in generation, can only be met if there is greater competition. However, since privatisation and the market’s consolidation by the Big 6, the barriers to entry for independent players to participate in the market have increased which in turn has worked against the interests of domestic and industrial customers, and held back levels of investment. The market has witnessed higher prices, a lack of transparency and a reduction in competition—both in supply and generation. In summary, we believe the following: — The “Big 6” do not have the capital or the sources of new investment to fulfil the required investment needed. — Much of the EMR assumes, and indeed requires, more market liquidity for the suggested changes to be effective. — Greater liquidity increases competition and creates a more accurate and market-driven wholesale price. The long term wholesale price is a key signal in both encouraging and enabling independent companies to invest in the construction of new generation plant. — The UK needs additional capacity, and a secure capacity margin, but this should not be supplied by older, less efficient plants. — The capacity market may will interfere with the wholesale market and should be separated and run separately. — Carlton Power thinks the re-introduction of a self-supply licence condition (SSLC) would greatly help free up the wholesale market. cobber Pack: U PL: CWE1 [E] Processed: [10-05-2011 17:30] Job: 009048 Unit: PG01

Ev w66 Energy and Climate Change Committee: Evidence

— Wholesale market conditions are heavily stacked towards the vertically integrated companies. The introduction of compulsory auctions would further open up the wholesale market and increase liquidity and competition. March 2011

Printed in the United Kingdom by The Stationery Ofﬁce Limited 05/2011 009048 19585