House of Commons - Draft Energy Bill: Pre-legislative Scrutiny

Draft Energy Bill: Pre-legislative Scrutiny - Energy and Climate Change Contents

3 Contracts for Difference

71. Three designs of feed in tariff (FiT) were initially considered by the Government as a replacement for the Renewables Obligation (RO):

a Fixed-FiT (which would pay a fixed payment that generators receive instead of revenues from selling electricity in the market);
a Premium FiT (PFiT) (which would pay a fixed premium on top of the variable wholesale electricity price); and
a FiT with Contract for Difference (CfD) (which would provide a long term contract set at a fixed level where variable payments are made to ensure the generator receives the agreed tariff and where the generator would return money to consumers if electricity prices are higher than the agreed tariff).

72. The consultation published in December 2010 focused on the PFiT and CfD options and the White Paper put forward a CfD as the preferred choice. Clause 1 of the draft Bill enables the Secretary of State to make regulations about Contracts for Difference (CfDs).[65] However, not all witnesses were convinced that DECC had made the right decision. Professor Catherine Mitchell (along with many environmental NGOs) advocated scrapping CfDs in favour of a Fixed-FiT.[66] Climatechangematters claimed that a Fixed FiT "would provide certainty, simplicity and much better value for money".[67] SSE preferred a PFiT, which, in its view, was "simple, understandable and bankable". However, EDF warned that a PFiT could generate excessive profits for generators.[68]

73. Nevertheless, there was a widespread view that CfD as a concept has attractions, most notably, the principle of revenue certainty provided by a long-term contract.[69] Nor is the concept "difficult"; energy companies are used to dealing with different regimes internationally, and CfDs are used in Denmark and were used in Britain's previous electricity market Pool arrangements.[70]

74. Yet the implementing arrangements proposed have become increasingly complex, arguably to the extent of being unworkable.[71] Witnesses argued that the reforms could be made to work, and that there was considerable willingness to do this, more so than for ditching CfDs altogether (see also paragraph 16). But the proposals as they stand in the draft Bill:

Are not "bankable" because a multiparty counterparty arrangement may be neither legally enforceable, nor creditworthy, and could require companies to post collateral and possibly be exposed to balance sheet fluctuations;
Introduce unacceptable levels of risk because of the possible effect of 'rationing' under the Treasury's levy cap and a future move towards auctions affecting access to contracts;
Could result in a more concentrated market because independents and smaller-scale generators will be squeezed out and be unable to find routes to market;
Are overly complex, because they are trying to cover too many disparate technologies.

Counterparty model

75. The Secretary of State helpfully clarified that there are three different models of counterparty referred to in the debate:

a single counterparty with liabilities underwritten by government;
a multiparty counterparty arrangement, comprising suppliers; and
a single central counterparty organisation of new design, which is reliant on the payment flows between suppliers and their customers (and which is not underwritten by government).[72]

THE SHIFT FROM A SINGLE COUNTERPARTY UNDERWRITTEN BY GOVERNMENT TO MULTIPARTY COUNTERPARTY MODEL

76. One of the most fundamental questions about the design of CfDs is where the liability for payments will ultimately sit. The 2010 EMR Consultation's Impact Assessment and July 2011 White Paper's EMR Impact Assessment both suggested that under the CfD, the risk would be borne by Government. For example, Table 4 of the White Paper Impact Assessment shows the price risk being borne by Government balance sheets under a CfD model.[73] The 2010 Assessment stated:

Fixed payments, premium payments and CFD provide a relatively high degree of policy certainty for investors as they would take the form of a contract between Government and industry.[74] (emphasis added)

The 2011 EMR White Paper impact assessment had this to say about the advantage of Contracts for Difference over Premium FiTs:

A FiT CfD, …. insulates generators and consumers from both short-term volatility and the impacts of long-term price trends; higher- or lower-than expected gas prices have no effect on price received by the generator or bills paid by consumers. This means that consumers will be shielded from longer-term wholesale price increases, but also that they will not gain from longer-term wholesale price decreases. Changes in wholesale prices only affect the amount of support paid out by Government; hence the price risk is borne by Government balance sheets.[75]

77. However, the draft Bill published in May 2012 proposed instead a "multiparty" payment model whereby liabilities would be borne collectively by all energy suppliers.[76] DECC claimed that in fact, it had never been the intention that Government would act as the counterparty, and told us:

When you look at the description in the White Paper, what we always envisaged would happen was the payments would always flow from suppliers through to generators to make the CfD whole. I don't think anyone really thought we would be talking about tax money or Treasury money being used to pay out these contracts.[77]

78. While no-one would have expected the Government to be paying these contracts, witnesses had understood that the Government would underwrite them.[78] In fact, we understand that DECC's messaging to the investment community when the White Paper was published indicated that the Government would be underwriting the liabilities and we did not come across any witnesses who had not believed that this would be the case. John McElroy (RWE npower) outlined:[79]

I would have to say clearly the original consultation and what was set out in that with regards to the Contract for Difference was quite important in the sense that the Government as the counterparty underwriting the contract in some way and the nature of the risks associated with these large low carbon projects, that we saw Government's role in this as important in terms of reducing the cost of capital. Now that Government seems to be trying to push its involvement in these contracts away from itself, partly driven by Treasury constraints, partly driven by the State aid rules, inevitably that claimed cost of capital benefit is not there.[80]

79. DECC's claim to us that "in the [White Paper's] Impact Assessment the drafting was a little bit unfortunate" therefore appears to be disingenuous to say the least.[81] We find it impossible to believe that this "unfortunate drafting" does not in fact represent a policy shift. We suspect that this is the hand of HM Treasury at work, but its outright refusal to co-operate with our inquiry means we have not been able to explore the dynamic between HM Treasury's balance sheet concerns and its deficit reduction priorities and DECC's policy objectives.[82]

DECC'S CURRENT PROPOSAL (A MULTIPARTY COUNTERPARTY)

80. The draft Bill published in May 2012 proposed a "multiparty payment model" whereby liabilities were borne collectively by all energy suppliers.[83] The CfD would be an instrument created by statute that set out obligations on the generator on one side, and on all licensed suppliers on the other side. The payment model would run in a similar way to the existing Balancing and Settlement Code with a settling agent such as Elexon to invoice generators and suppliers. Regular but variable payments would flow to and from generators and suppliers and in both directions.

Figure 1: The multiparty payment model

81. None of the evidence received for this inquiry suggested that the draft Bill's proposed "multiparty contract" (termed a "synthetic" or "virtual" counterparty by some) would work in practice.[84] Three major problems were identified with the proposal: that it might not be legally enforceable, that it might not be creditworthy, and that it would have a negative impact on suppliers' balance sheets.

Is it legal?

82. The proposed structure has no clear legal precedent and witnesses argued that in the case of a contractual dispute, it was not clear with whom generators would engage to resolve the dispute.[85] Several witnesses had seen legal advice that a contract with a synthetic or virtual counterparty would be legally unenforceable and for this reason, the model was considered to be uninvestable.[86]

Is it creditworthy?

83. Witnesses told us that it was difficult to assess how creditworthy a "synthetic" counterparty was.[87] The CBI said:

The current approach is different from what was anticipated at the beginning of the EMR process, when it was thought that Government would underpin the contracts, meaning the liability would ultimately sit with an entity with an AAA credit rating. Under the current model, where the liability would sit collectively with suppliers, it is not clear what the effect on the cost of capital would be.[88]

84. The Minister has subsequently told us:

We understand some stakeholders have said that Government signing contracts would reduce credit risk, but given that payments ultimately flow from suppliers to generators, the credit risk in the scheme should reflect the robust financial health of the UK electricity market and form a solid base for investment.

The Government aims to provide investors with a system with a level of certainty equivalent to a contract with a counterparty that has a strong credit rating, not that Government would be the counterparty. Our intention was not for Government to be signing contracts but for a credit worthy investable system.[89]

What are the implications for suppliers?

85. There is uncertainty about the accounting treatment of CfDs and in particular, whether they might be classed as "derivatives" (financial instruments that involve making defeasible payments under contract).[90] If this is the case, the long term liability for CfDs may need to be "marked to market", that is, shown on suppliers' profit and loss accounts. This, in turn, may have implications for credit ratings. DECC has not yet received a definitive view on this from the large accountancy firms.[91] Some of the large, vertically integrated energy companies expressed concerns about this introducing volatility into their balance sheets that might make their investors nervous.[92] However, E-ON had received limited reassurance on that point:

The derivative point is a real worry and I would share the concerns already expressed on that. It is important that the contract, whatever it is, is not viewed as a derivative. We have had some good news on that in that if it is attached to a particular asset then it is less likely that it will be viewed as such.[93]

86. A further concern for suppliers was the potential requirement to post collateral. Small suppliers in particular were worried about this point and argued that it would not be feasible for small organisations to do this. Good Energy told us:

It is quite evident that there are concerns about having a large volume of cash linked to a day-ahead price going to your balance sheet. As a small supplier, that has impact in terms of credit and you also have to consider the collateral requirements ... It is one of those areas that we think needs a lot more investigation. The most recent impact assessment that we have seen, and I think it is publicly available, is from July 2011, and there is no mention of small suppliers in there.[94]

87. Ecotricity said that the risk to small suppliers was "massive" in terms of the collateral required, given that even the large energy companies had concerns about effects on their credit ratings. They called for a 250,000 customer threshold if these proposals were taken forward, to prevent barriers to entry to the market.[95] This would be similar in effect to proposals already implemented by DECC to exempt suppliers with under 250,000 customers from liability for levies. Independent suppliers agreed that DECC's proposals to look at shorter arrears periods would lessen but not remove the burden.[96] Ofgem shares concerns about the potential impact of increased credit and collateral requirements on small suppliers and the risks to new entry, despite DECC's reassurances in the "Policy Overview".[97] We consider that suggestions that small suppliers might be exempted partially or wholly from obligations to post collateral have merit and recommend that the Government takes steps to ensure that small suppliers are not disadvantaged.

Other concerns

88. In addition to these three problems, SSE identified a further difficulty with the multiparty contract model, relating to the potential for miscalculation of subsidy collection. It said:

Suppliers will have to collect money in advance from consumers to pay these contracts. Suppliers may get this wrong and over or under collect, with huge financial implications for them and consumers. This is a large threat for all suppliers and a huge additional barrier to new retail market entrants.[98]

THE THIRD WAY: A SINGLE COUNTERPARTY WITHOUT GOVERNMENT UNDERWRITING

89. The evidence suggests very strongly to us that the multiparty proposal is not workable.[99]Centrica and EDF supported an alternative simpler bilateral model with a creditworthy counterparty.[100]A recent document from DECC confirms that an "Alternative Model" with a central counterparty is now under discussion.[101] There would be a newly created central body that would sign bilateral contracts with generators. It could be Government or privately-owned. It would collect payments from suppliers, and the obligation on suppliers would require them to post collateral to cover any liabilities in a given period. Crucially, however, the single counterparty would not be underwritten by Government. Key issues under consideration include the impact of the obligation on suppliers, administratively and financially.[102]

Figure 2: The Alternative (central, single) Counterparty Model

90. It seems to us that the main difference between these two models is that in one the counterparty body signs contracts with generators, so addressing the legal signatory issues. It certainly does not change the underwriting issue.

91. National Grid felt that the current debate was between a multiparty counterparty and "a thin-balance-sheet sole counterparty, effectively, which would be set up in some convenient way", akin to the settlement role established in 1989 for Elexon.[103] It is "doing work with DECC to understand how you might structure such an organisation" including checking that no unexpected issues might arise.[104]

92. The Secretary of State told us that the model put forward by many in the industry for a singleparty counterparty model without Government underwriting was unproblematic.[105]

93. While many witnesses were aware that an "alternative model" was under consideration, the novelty of this proposal meant that considered input to our inquiry about its merits and drawbacks was limited. We also suspect that some stakeholders have mistakenly interpreted the new single counterparty model to be one that is underwritten by Government.

94. We recommend that the Government abandons the multiparty concept and reverts to a single counterparty payment model, with a contract and counterparty design that is legally enforceable.

95. The main purpose of the reforms was to reduce the cost of capital for investors. The nature of the counterparty will affect the cost of capital (see paragraph 97). In our view, a counterparty model that is underwritten by Government would be the best way to instil investor confidence and reduce financing costs.

96. DECC must fully assess the implications of a single counterparty without government underwriting on suppliers' balance sheets and on the cost of capital before adoption of this model. This should include an assessment of what impact this model would have on smaller suppliers to ensure that this counterparty model would not threaten the viability of these businesses.

THE NEED FOR A MORE RIGOROUS IMPACT ASSESSMENT

97. The Impact Assessment published alongside the White Paper in 2011 concluded that financing costs under a CfD would be £2.5 billion lower than under a Premium Feed-in Tariff. Numerous witnesses told us that this calculation was no longer valid, since it was based on the assumption that the Government would be the counterparty, whereas the draft Bill now suggests the "multiparty contract" model. The Combined Heat and Power Association explained why this was relevant: "the Government, as counterparty would have had a top AAA credit rating, but a different counterparty may not have such a high rating. A lower than AAA rating would increase credit risk for investors and, therefore, the cost of capital".[106]

98. However, DECC told us that in fact, the Impact Assessment was based on the impact of removing the volatility in the revenue streams, and did not take account of the nature of the counterparty. The Secretary of State said that the "numbers from the impact assessment would not have been different" under a Government-underwritten or a multiparty contract model.[107] The Minister subsequently told us:

The Impact Assessment would not […] need re-working, in order to analyse an alternative payment model, because the choice of counterparty doesn't impact on its underpinning assumptions - which for the counterparty would be the same in either scenario. However, we will of course produce an updated Impact Assessment when we introduce the Bill.[108]

99. We believe that the nature of the counterparty will have an impact on the cost of capital. DECC's claim that the nature of the counterparty would not affect the outcome of the Impact Assessment (IA) merely reflects the lack of sophistication in the original assessment, rather than the likely real-world impact on the cost of capital.

100. The Low Carbon Finance Group has questioned the broader assumptions underpinning the Impact Assessment and has suggested that the results reflect a "theoretical approach to capital pricing, not how banks and investors allocate capital to, or price capital, for various investment opportunities".[109]

101. Investors also highlighted wider concerns about the direct impact of political and policy uncertainty on market perceptions of risk (for example, the changes to the counterparty arrangements and the interaction between the levy control framework and the CfD). The draft Bill and associated documents fail to properly assess the cumulative impact of policy changes and pronouncements on cost of capital. We return to this in paragraphs 229 - 231.

102. DECC must update its methodology as well as the figures when revising the Impact Assessment (IA). The model needs to reflect real world approaches to capital pricing and should incorporate the impact of new risks on the cost of capital (including counterparty risk, development risk, risks to credit ratings and basis risk). The IA should specifically address the issue of how Government-underwriting (or lack thereof) of the CfD counterparty affects investor risks and costs.

Allocation of CfDs: the Levy Control Framework and use of auctions

IMPACT OF HM TREASURY'S LEVY CONTROL FRAMEWORK

103. CfDs will fall under a cap, introduced in the 2010 Spending Review, on DECC levy-funded spending. Deficit neutral DECC policies that are classified by the Office of National Statistics as tax and spend are included in the cap. HM Treasury's Levy Control Framework (LCF) already sets spending limits to 2014/15 for the RO, Feed in Tariffs, and the Warm Home Discount.[110] The Framework says that if forecast or out-turn spend for any policy varies beyond a 20% "headroom" of the cap, DECC must urgently develop plans for bringing them back into line - or the Treasury may seek a financial contribution.[111]

104. The draft Bill states "The Government is minded to instruct the System Operator to only issue CfDs for low-carbon generation up to the value of the amount set out in the Levy Control Framework. The same principle will also apply when the Secretary of State is issuing any investment instruments in relation to projects that require final investment decisions in advance of EMR implementation, and when issuing any CfDs after the CfD regulations come into force".[112]

105. Clause 8 of the draft Bill provides for the Secretary of State, by Order subject to parliamentary approval, to set out the maximum cost for the scheme by setting a financial cap on the scope of the national system operator to issue CfDs. It also provides for a power to direct the system operator "not to issue CFDs if the Secretary of State determines that doing so would exceed the cost cap".[113]

106. Witnesses argued that rationing CfDs to fit within a levy cap would introduce a new risk to developers, who could not be sure that they would be able to secure a CfD for an otherwise fully consented project.[114] The Low Carbon Finance Group told us that certainty over the allocation process would be central to the ability of developers to bring forward a project for financing and that "at present this is one of the weakest parts of the package".[115] Keith Anderson (Scottish Power) said:

The concern for us would be that once we start investing […] on a large offshore project where I am likely to have put at risk £100 million to £150 million to get it there and then I get to FID [Final Investment Decision] and I do not know if I am going to get a contract or not, that is an unacceptable risk. So there needs to be enough transparency of how that levy control works and where we are against it all the way through that investment process and we would want enough flexibility in the way it is moved to say, "By the time we get to FID bring forward your project and look for the contract", you are not going to get told, "Wait 18 months because there is no money left". That would be absolutely unacceptable.[116]

107. Shaun Kingsbury (Low Carbon Finance Group) noted that there were also risks with offering contracts too early in the development process and suggested that a balance between the two extremes needed to be found:

If you say up-front to anyone with even an idea of a wind farm, "Please apply for a CfD", you may get 20 or 30 GW of applications. This is what happened, for example, in Turkey. If you wait until the very end, then people will not invest the capital to get there because of the risk.[117]

108. Witnesses suggested that one way of dealing with this problem would be to introduce a pre-registration process that could provide greater security that a contract will be awarded earlier in the project development process.[118] Gaynor Hartnell (Renewable Energy Association) said:

What we think is important is that a project developer can essentially reserve a CfD at the point of winning planning permission; for example, they might have an option to take it up for, say, 18 months or a couple of years, by which time they take that project to the point of the making the final investment decision. Then the contract kicks in, and then they have a certain period of time in which to build it. It seems to us essential that that happens to de-risk the process. Obviously you can't hold on to that allocation of a CfD or future allocation indefinitely, because you would have funding sterilised by, say, a project that was not going to reach fruition, so that is why we are suggesting, say, 18 months or two years to take it to the financial investment decision.[119]

109. Rationing the number of CfDs under the levy cap increases development risk. We recommend that DECC introduces a two-step or pre-registration process to give developers greater confidence that they will be able to obtain a CfD before reaching Final Investment Decision.

110. Two further problems with the levy cap were identified: first, the fact that early projects brought through under investment instruments (Chapter 4) might use up the pot of CfDs before other projects were able to apply. Second, that large scale projects like nuclear and offshore wind are "chunky" investments and may use up an annual allocation in one go, leaving other projects that year without CfDs.[120]

111. Suggested options for dealing with these included improving flexibility between each year's allocation of CfDs, a longer term (multi-year) approach, and specifying in advance how many CfDs will be available for each type of technology each year.[121]

112. A recent letter to us from the Minister of State has outlined further how the Levy Control Framework (LCF) will operate. It says that the agent allocating contracts will, in principle, have limited discretion over who should be allocated contracts and that precise allocation arrangements will depend on the "affordability within the LCF", with legal obligations being fully taken into account.[122] Continuing RO payments and possibly other levies such as ECO will come within the Levy Control Framework. The Government should clarify what will be defined as falling within the Levy Control Framework at an early date.

113. It is essential that the Government makes clear how choices will be made by the agent allocating contracts, in particular in allocation between technologies. We recommend that reporting against the delivery plan should include details of commitments already entered into at FIDs or during FID-enabling discussions, and is transparent to other players in order to assist long term planning.

114. Dr Kennedy (Committee on Climate Change) told us:

We know what that [the Levy Control Framework] is out to 2015, but it is important to understand what that is going out beyond 2015 to 2020. We need to see a high-level number that is commensurate with the required power sector decarbonisation in 2020 sooner rather than later, and we need to see some flexibility in that number, given the huge range of uncertainties around the kind of support that might be required.[123]

115. The Committee on Climate Change has recently recommended that a funding envelope of around £8 billion in 2020 should be agreed now, with flexibility of +/-20-25% depending on gas prices and low carbon technology costs.[124] We recommend that in order to provide greater confidence to developers, Government should set out

a) the level of the funding that will be available under the Levy Control Framework until 2020

b) whether the present rules on headroom will remain as they are or will be amended to provide more flexibility for levy allocation over the next spending period; and

c) whether the present mechanism of capping expenditure annually and longitudinally by line will be maintained or relaxed during the next spending period.

We note the Committee on Climate Change's suggestion that funding available under the Levy Control Framework until 2020 should be around £8 billion in 2020.

USE OF AUCTIONS

116. DECC's current proposals envisage moving to competitive CfD allocation processes, such as tenders or auctions, as early as 2017 for some technologies.[125] Many witnesses thought that this date was too early.[126] Some witnesses were opposed to the use of auctions at all, suggesting that it would introduce a similar type of development risk to the levy cap, and thus increase the cost of finance.[127] RenewableUK said:

Introducing auctions discourages investment because there is less certainty to investors that their projects will receive a contract, and at what price. This will discourage investment in development and slow down the rate at which renewable projects come forward.[128]

117. An additional problem with auctions is that they do not guarantee a cheaper outcome for consumers. Auctions may be useful but they are not the only means to secure cost reduction. We recommend that DECC should learn from experiences overseas and consider setting out a planned reduction pathway for strike prices. This would guarantee a reduction in the level of subsidy paid by consumers over time.[129]

Ensuring routes to market

118. The third major problem identified with the current CfD proposals is whether independent generators would still be able to sell their electricity under the new arrangements. Low levels of liquidity in the market mean that it is difficult for smaller and independent generators to sell directly into the market (for example via the power exchanges). Instead, smaller generators often sign long-term contracts called Power Purchase Agreements (PPAs), usually with large vertically integrated energy suppliers. Through these, independents sell power at a discount to market rates; they receive less for their energy because they are reducing their risk through having longer term contracts. PPAs are important for smaller generators who do not have a large in-house trading capacity, and for intermittent generators who cannot produce electricity on demand in the same way as a traditional generator.[130] Vertically integrated businesses, in contrast, are not reliant on PPAs because they are able to hedge risks between the generation and supply parts of their business.

119. The Renewables Obligation (RO) provided an incentive for larger suppliers to enter into PPAs, but the CfD proposals do not. In the absence of an obligation, PPAs might only be available at a steep discount - leading to a concern that the price received under any future PPAs will be significantly below market price.[131] In CfD terms, this means independent generators would not be able to achieve the "reference" price, leaving them with lower returns than the bigger players. Gordon MacDougall of Renewable Energy Systems told us:[132]

One thing in terms of maintaining the RO, which seems to be lost, is that the RO was more than just a certificate system. It was a physical obligation on the suppliers to source the right kind of energy and that has been lost in all of this. I think that is a much more significant departure than many people seem to recognise because one of the big problems with a CfD is there is not sufficient liquidity in the market for independent generators to trade and, as such, they require a PPA. Without the obligation on the supply companies, there is no incentive for them whatsoever to offer sensible PPAs to make these projects bankable.

120. The absence of "bankable" PPAs could mean that independents will struggle to raise finance for new projects. Ian Temperton (Climate Change Capital) told us that "people wanting third-party finance will need Power Purchase Agreements. They will need to give their financiers a surety that their product is going to get into the market".[133]

121. Annex B of the EMR policy overview states that Government "believes suppliers and independent aggregators will continue to offer PPAs as there will be commercial opportunities for doing so".[134] Witnesses were sceptical about this idea, suggesting that historical precedents were not promising.[135] For example, the NETA trading arrangements that were introduced in the 2001 were expected to encourage aggregators, but in practice delivered vertical integration.[136] The Renewable Energy Association told us "they [aggregators] will only enter the market if there is some margin that they can earn. There is none".[137] RES argued that the existence or not of aggregators was "wholly missing the point" because "the question is not whether or not PPAs will be offered, but it is whether the PPAs will be viable or not".[138]

122. RES warned that failure to resolve this issue could lead to the pipeline of new renewable energy projects drying up. It said:

If there is not an effective route-to-market available by mid 2015, the market for independent renewable generators will come to a halt, with independents being unable to progress projects under either the old RO structure or the new CfD Structure.[139]

123. DECC has belatedly acknowledged that access to the market is a serious problem and on 5 July 2012, it launched a call for evidence "to help independent renewable generators access the electricity market".[140] This is yet another example of the policy and practical arrangements underpinning EMR still being in the process of formation.

124. Access to market for independent generators under the CfD arrangements is an extremely serious issue that must be resolved before a Bill can be introduced. We recommend that DECC expedites its review of evidence on access to the electricity market for renewable generators to ensure that a solution to this issue is identified before the Bill is introduced to Parliament in the "autumn".

125. One possible answer is to improve the liquidity in the market. Ofgem has work underway in this area and is currently consulting on proposals to require vertically integrated companies to sell 25% of their generation output in the forward market.[141] However, we heard concerns that Ofgem's current work would not deliver sufficient liquidity and that it would probably not include enough mandatory measures.[142] Ofgem's evidence did not address the wider market liquidity issues.[143]

126. Three other potential solutions were put forward:

A "buyer of last resort" mechanism could be introduced.[144] The impact of this would be equivalent to a fixed FiT and capacity using this route would not be responding to market signals (because generators would be guaranteed a buyer, even when the market price was low and indicating that their generation was outweighing consumer demand). It would therefore go against the overall principle of maintaining a competitive market.[145]
Introduce an obligation (or some other incentive) on suppliers to source energy from low carbon generation. For example, by making a proportion of the costs of CfDs proportional to the amount of low carbon energy they secure.[146]
Delay the closure of the RO to new entrants.[147]

127. In paragraph 70 we recommended that the FiT for small-scale generation should be increased to include projects at least 10MW in size. This would eliminate the route to market problem for all projects in this category. In paragraph 211 we make recommendations about the timetable for closing the RO.

128. We recommend that as part of its review of access to market for independent generators, DECC should examine the following options: introducing a buyer of last resort; introducing an incentive for suppliers to source energy from low-carbon generation; extending the micro-gen FiT to projects up to 50MW in size; and holding open the RO for new entrants in the event that the PPA market disappears.

Other issues

LENGTH OF CONTRACTS

129. Clause 4 of the draft Bill allows the terms of a CfD to include its duration. DECC's draft operational framework for CfDs proposes that this will be 15 years for renewable technologies and 10 years (with the possibility of varying this) for CCS projects under the commercialisation programme. The Government has not yet formed a view on how long nuclear CfDs will last for, but says it would expect no less than 15 years.[148] Renewables and CCS organisations argue that the length of CfDs for their technologies should be linked to project lifetime and therefore longer than the 15 or 10 years proposed.[149]

SETTING THE STRIKE PRICE

130. Clause 5 of the draft Bill allows for the setting of strike prices either administratively, competitively or through a combination of the two methods. Initially, strike prices will be set administratively for each technology, before moving to the use of auctions. The negotiation processes will be different for different types of low-carbon energy:

Renewables: the process will be similar to the most recent RO Banding Review. The System Operator (National Grid) will conduct an analysis of costs and deployment potentials, which will feed in to a cost benefit analysis of different strike prices on security, carbon and cost objectives. Based on this analysis, a report from a panel of experts, and—possibly—the advice of the Committee on Climate Change, the Secretary of State will make a decision on the strike prices. However the experience of the latest RO review, when for example the decision about the support for onshore wind was widely rumoured to be the subject of disagreement between DECC and the Treasury, does not inspire confidence among potential investors that the process will be determined exclusively by an objective analysis of the available evidence.
CCS: for early stage CCS projects (including those supported under the CCS Commercialisation Programme), there will be a negotiation between developers and DECC. It will be possible to set different strike prices for different projects in order to take account of the wide variety of technologies and location-specific costs.
Nuclear: the level of the strike price will be determined through an administrative price setting process, which will involve "negotiation with developers on a project by project basis".[150]

THE STRIKE PRICE FOR NUCLEAR

131. Witnesses raised concerns about transparency in setting the nuclear strike price in bilateral negotiation, with little opportunity to move to auctions or competitive price setting.[151] Although Vincent de Rivaz (EDF) told us that "the strike price will not be defined in a cosy way through hidden decisions" and that the result would be "absolutely open and transparent",[152] Richard Hall (Consumer Focus) was not convinced:

In a bilateral negotiation where there is only one player in the room and that player can say, "Take it or leave it; these are our terms", I have very little confidence that that is an efficient way of deriving a price.[153]

132. Which? recommended that further detail was needed in the Bill about how contract negotiations will be made transparent, how arrangements will be scrutinised and how the Government and System Operator will be held accountable.[154]

133. The Government is proposing that an "expert panel" will be appointed to scrutinise the System Operator's assessment of costs and deployment potentials for renewables. We asked the Secretary of State whether an expert panel might also scrutinise the negotiation of the nuclear strike price. He told us: "We do not currently believe they should have a role".[155]

134. We are concerned that the proposed process for setting the nuclear strike price lacks sufficient transparency. The perception that decisions are being made "behind closed doors" could be highly damaging to the low-carbon agenda and may further undermine consumer trust in energy companies. It is essential that the negotiations deliver, and are perceived to deliver, value for money to consumers. We recommend that an independent panel of experts should be appointed to oversee the negotiations and to report to Parliament on the adequacy of the outcome and value for money for consumers.

THE LIKELY COST OF NUCLEAR

135. Witnesses from environmental NGOs, argued that the strike price for nuclear was likely to be higher than that for renewables, perhaps as much as £160/MWh.[156] We note that a Times report of the 16^th July 2012 indicated that the asking strike price for new nuclear would be £165/MWh. Vincent de Rivaz (EDF) however said "we are confident that the strike price agreed will reveal the competitiveness of nuclear new build compared to other forms of low carbon generation".[157]

136. Since there is little competitive pressure or prospect of moving to auctions for new nuclear, we are concerned that the strike price for nuclear could be driven upwards. We hope that industry claims that the cost of nuclear is competitive with other forms of low-carbon energy will be reflected in the offers they put forward during strike price negotiations. We do not believe that a nuclear strike price higher than that given to offshore wind would represent good value for money to the consumer. The Secretary of State should not agree to contracts of this nature.

LONGER-TERM PRICE VISIBILITY

137. To provide developers and investors with the visibility to make investment decisions, the draft operational framework for CfDs proposes that five years of strike prices for renewables will be published in the delivery plan in late 2013 with indicative prices in the draft delivery plan, published in mid 2013.[158]

138. Aquamarine Power (a company involved in developing wave power devices) told us that they needed more certainty about what the strike price would be on a longer timescale. It said:

It is the strike price for marine energy after 2017 which is critical for the growth of the marine energy industry. We remain concerned that early-stage investors will find it hard to make an investment case for early arrays without clear sight of the market towards 2020 and beyond.[159]

139. Government should provide clarity on the strike price level beyond 2017 as soon as possible in order to provide certainty and help secure investment for emerging technologies, such as wave and tidal power.

STATE AID AND A "ONE-SIZE FITS ALL" PACKAGE

140. EU state aid rules seek to ensure that Member States do not unjustifiably distort the single market through financial or other interventions. Any new scheme under EMR will have to be submitted to the European Commission and many aspects of the EMR proposals will need clearance.[160] If a scheme or technology falls under previous case law or block exemptions however, then the clearance process may be completed quickly. Article 23 of the General Block Exemption Regulation provides (subject to conditions, such as the amount of aid provided) that environmental investment aid for the promotion of energy from renewable energy sources is compatible with the single market.[161]

141. SSE considered that the clearance process for CfDs might be lengthened through them covering both renewables and nuclear, to which Article 23 does not apply.[162] There are also questions about the nature of the counterparty and whether this could fall foul of state aid rules; if the Secretary of State or a government owned body were the counterparty, the funds could be perceived as belonging, albeit temporarily, to the state and being directed by it. This might increase the likelihood of a scheme being viewed as state aid.

142. DECC accepts that "the eventual assessment [of whether CfDs amount to state aid] may depend on the detail of policy design". If EMR is classified as state aid, DECC considers that this should still be approvable under the Treaty because:[163]

The EMR is designed to secure new investment in low carbon generation, while maintaining energy security and diversity. EMR will minimise costs to the consumer, and the specific instruments under EMR are designed to minimise distortions of competition. So long as the balance of assessment is positive, any aid should be compatible with the Treaty.

143. The Secretary of State told us that "We think we will find favour" with the EU, because the EMR proposals share EU objectives.[164] Nuclear wrapped up within an EMR package may therefore pass an approval process, whereas if presented outside the package, it likely would not. It is possible that the Commission will take a view on different technologies, but DECC told us that they did "not see the fact that we are notifying for nuclear necessarily holding up any decision on renewables".[165]

144. Witnesses shared the widespread perception that EMR, and specifically CfDs, are a fig leaf over support for new nuclear.[166] The Green Alliance thought that the state aid issue was probably why the "obvious" and "simple" decision, to have the government as counterparty, had not been taken.[167] The REA believed that the state aid question had been driven by nuclear, and it was a "great pity" that renewables had been tied up in that policy.[168]

145. We conclude that state aid as well as political considerations have influenced the design of the CfD package, and have caused policy and financial support for nuclear to be rolled up with that for renewables. Logic suggests that the Government should differentiate nuclear from other low-carbon technologies within an overall FiT regime. The Committee will consider further the building of new nuclear and its associated challenges later in the year.[169]

146. Given that the Government (and the Committee on Climate Change) see nuclear playing a key role in the future energy mix, Government should consider how carbon and security objectives could be delivered if no new nuclear is forthcoming.

65 DECC, Planning our electric future: a White Paper for secure, affordable and low-carbon electricity, CM 8099, July 2011p 37; DECC, Electricity market reform: policy overview, Annex B: Feed-in tariff with contracts for difference: draft operational framework, May 2012 Back

66 Ev 137, Ev w34, Ev w130, Ev w165, Q 96 [Professor Mitchell], Q 237 [Mr Steedman] Back

67 Ev w165 Back

68 Q 49 [Mr De Rivaz] Back

69 Ev w29, Ev 161, Ev w61, Ev 168, Ev w62, Ev w66, Ev w71, Ev w74, Ev 176, Ev 206, Ev w170, Ev w173, Ev 227, Q 7 [Ms Vaughan], Q 57 [Mr de Rivaz], Q 98 [Dr Kennedy] Back

70 Q 407 [Secretary of State], Q 24 [Mr de Rivaz] Back

71 Ev 232, Ev w79, Ev 178, Ev 211 Back

72 Q 433 Back

73 DECC, Impact Assessment, Electricity Market Reform - options for ensuring electricity security of supply and promoting investment in low-carbon generation, 12 July 2011 Back

74 DECC, Impact Assessment, Electricity Market Reform - options for ensuring electricity security of supply and promoting investment in low-carbon generation, 14 December 2010 , p 66, para 69 Back

75 DECC, Impact Assessment, Electricity Market Reform - options for ensuring electricity security of supply and promoting investment in low-carbon generation, 12 July 2011, para 100 Back

76 DECC, Electricity market reform: policy overview, Annex B, Feed-in tariff with contracts for difference: draft operational framework, May 2012 p 68 Back