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State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013

On 18 December 2013, the European Commission announced that it was opening an in-depth state aid investigation into the Government’s package of financial support for the proposed Hinkley Point C (HPC) new nuclear generating station.  On 31 January 2014 the Commission published a version of the letter setting out its reasons for launching a detailed investigation and the points on which it requires to be persuaded of before giving state aid clearance to the package.

What does the letter tell us?  It is a fairly closely-argued 67 pages, so it will take more than one post to cover it.  Today, we begin by setting the scene. 

The potential of HPC – an image from gov.uk

The critical tone of parts of the Commission’s analysis has been noted in a number of reports, but this is perhaps not the most surprising feature of the letter if one considers its context.

  • The package of support for HPC inevitably treats new nuclear as to some extent a “special case”.  State aid policy is administered on the principle that free markets are best and that claims that a particular industry is somehow “special” are to be treated with scepticism – even if that industry is one in which there is already massive state intervention in various forms. 
  • The European Commission’s decision-making on state aid cases has sometimes been criticised for being too politically expedient.  Here we have a case where the UK Government has invested huge political capital and the aid is going to a subsidiary of a company 84% owned by the French state.  Even if the Commission is ultimately minded to approve the HPC support package it cannot afford to be seen to have given it anything less than an economically rigorous evaluation.
  • In 2007, the Commission ruled on alleged state aid for the Olkiluoto 3 nuclear plant, to be built in Finland with French technology.  The issue was whether a guarantee given by the French state gave Areva an unfair competitive advantage over other potential suppliers.  The guarantee was found to have been given on market terms, so that there was no aid under the state aid rules.  However, the proceedings still lasted three years and the Commission went through an in-depth investigation before reaching a final decision. 
  • In 2006, the Commission approved the arrangements for setting up the Nuclear Decommissioning Authority (NDA).  Although the Commission acknowledged that the purposes behind the creation of the NDA were fully in line with the objectives of the Euratom Treaty, it was also very concerned about potential distortions of competition arising from it.  For example, notably tight controls were set on the pricing of electricity sold by the UK’s Magnox nuclear plants, to be run by the NDA, for the few remaining years of their life.
  • Most recently, the Commission decided that aid granted by Slovakia in relation to nuclear decommissioning was compatible with the state aid rules.  In doing so, the Commission emphasised that the aid related to plants that had already been shut down; that it did not subsidize current electricity production; and that it was “strictly limited to what is necessary to cover the costs of decommissioning historic nuclear facilities, for which no adequate provisions were created in the times of a centrally-planned economy”.  Moreover, the Slovak scheme was unlike “the numerous schemes of compensation for stranded costs, public service obligations and support schemes for renewable electricity, where the Commission has found that the financing of the support scheme through a levy has a protective effect of national electricity production”.
  • The HPC support package is the kind of arrangement that is intrinsically harder for the Commission to get itself comfortable with than the Okiluoto or NDA measures.  It explicitly and intentionally provides, under the Contract for Difference (CfD) mechanism, a guaranteed level of price for electricity and therefore a degree of revenue security which the market would not provide.  It can therefore be characterised as “operating aid” (as opposed to “investment aid”), which the state aid regime regards as particularly problematic – since it shields operating businesses from normal market risks.
  • Although there is an entire EU Treaty devoted to the promotion of nuclear power, it is politically controversial within the EU, and there are those who will take any opportunity to put the case, whether in administrative or judicial proceedings, against the adoption or approval of any measure that brings a “nuclear renaissance” in the EU closer.
  • There are undoubtedly some features of the support package for HPC which, at least at first sight and taken in isolation, appear very generous.
  • The Commission is in the process of “modernising” the state aid framework and has just published draft Guidelines on environmental and energy aid.  The Guidelines do not cover nuclear projects, but take a notably tough line on e.g. support for renewables, even though the deployment of renewables is mandated by EU law in a way that nuclear power is not.  Anything other than a searching approach to scrutiny of the HPC package would be out of keeping with the general thrust of current Commission policy in this area.
  • Whatever the ultimate outcome of the Commission’s evaluation of the HPC support package, the final decision can only be robust against potential challenge if it has clearly stated the potential objections to what the UK Government is proposing.

The UK public may have been encouraged to think that the hard part of HPC was over once development consent, a nuclear site licence, marine licence and other environmental permits were granted, and agreement on the strike price had been reached.  But obtaining state aid clearance in this case was always going to be a challenge.  And for all sorts of reasons, it is not surprising if at this stage the Commission has stated the “case for the prosecution” in clear and strongly worded terms.  In future posts, we will examine some of the Commission’s arguments a little more closely, consider the possible outcomes of the Commission’s investigation into the HPC support package, and look at what the Commission’s letter indicates about the prospects for state aid clearance of the rest of the Electricity Market Reform (EMR) package.

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State aid for Hinkley Point C (1): the context of the Commission’s letter of 18 December 2013

Coal still counts (2): decision time for generators (or it will be soon)

In a previous post we looked at how the UK’s existing fleet of coal-fired plant had been saved from being made subject to the “emissions performance standard” or EPS under the Energy Act 2013 provisions for Electricity Market Reform (EMR).  This happened when the Government reversed an amendment that would have applied the EPS to existing coal-fired plant if its operators were to choose to keep it running in the long term by fitting the equipment necessary for it to comply with the new limits on emissions (in particular of NOx) that will apply to it from 2016 under the Industrial Emissions Directive (IED).  In this post, we explore the choice which operators have to make under the IED – and why the Government may have thought it worth keeping them out of the EPS. 

Existing plant faces a choice under IED.  In broad terms, it must either upgrade to meet the new emission limits, or run for a limited number of hours – for example, by opting for the “limited life derogation” (LLD).  The LLD allows plant to run in its current form for 17,500 hours before closing no later than 2023.  Subjecting existing coal-fired plant to the EPS if and when it upgraded to comply with IED NOx limits would have made it likely that its operators would opt for the LLD rather than upgrading, and at the load factors at which UK coal plant has been operating recently, most plants would probably burn through their 17,500 hours by 2020, if not before.

Why should that worry us?  Wouldn’t it just be another example of EU legislation that isn’t about climate change being more effective at tackling CO2 emissions than the EU Emissions Trading System?  (Most UK coal plant closures to date have been driven by the Large Combustion Plants Directive, which the IED replaces, and which was designed to combat effects such as acid rain rather than “global warming”.)  To understand why the Government was so keen to keep existing coal plant out of the EPS, we have to look at the work it is doing in the generating mix. 

In 2012, the UK’s total combined cycle gas turbine (CCGT) capacity (35.57GW) exceeded its total coal and oil-fired “conventional steam” generating capacity (30.97GW) for the first time.  But that same year, gas’s share of electricity generation fell from 40% (in 2011) to 28% and coal’s rose from 30% to 39%.  (Greenhouse gas emissions from the UK energy supply sector increased by almost 6 per cent as a result.)  Coal’s high share of UK generation persisted, and appears to have increased slightly, in 2013. 

Why is this?  Coal-fired power over this period has simply been cheaper than gas-fired power (partly because the availability of shale gas has hit US coal prices).  It can keep the lights on at lower cost.

Much of our coal-fired electricity comes from just 10 coal-fired plants, with a combined capacity of over 18 GW – about a fifth of generating capacity connected to the grid.  Now that the 1 January 2014 deadline for indicating their operators’ intentions as regards the LLD has passed, and with the threat of EPS removed, we might expect that there would be some clarity as regards their future, but in fact there is still a degree of uncertainty about most of them.

  • The future plans of three (Drax, Eggborough and Rugeley, together representing some 6.8GW of capacity, and all owned by generators who are not in the “Big 6”) appear to depend in part on plans to convert to burning biomass.  The success of these plans is likely to depend on whether they are allocated EMR Contracts for Difference (CfDs), and meet the conditions for those CfDs to take effect (more on all this in a later post).
  • One (E.ON’s Ratcliffe, 2GW) appears fully prepared for IED compliance.  Another (SSE’s Fiddler’s Ferry, just under 2GW) has development consent to fit the necessary equipment.  A third (Scottish Power’s Longannet, 2.3GW) is testing new technology to comply with IED.
  • The operators of four of them (Aberthaw, Cottam, Ferrybridge and West Burton, representing together some 7.5GW) have provisionally decided not to invest in the equipment necessary to comply with the IED.  Instead, EDF, RWE and SSE have said they plan to use the LLD. 

The story is clearly not over.  EDF, RWE and SSE have all indicated that they may still choose to upgrade some of their plants to IED standards.  So their choice of the LLD may be more about keeping their options open than representing their preferred long-term option for these four plants.  RWE commented: “Only after we have political clarity on how the energy market will operate under the Government’s new energy legislation as well as any other political changes to be enacted, will we be able to make [a] final decision with confidence.”.

The reference to the uncertainties still surrounding a number of aspects of  EMR reminds us that some existing plant may be looking to the EMR capacity market as a means of funding investment in IED compliance.  More on how the capacity market may work for coal and other types of plant in further posts.  For the moment, though, note two more points.  First, if operators wish to revisit their decision to choose the LLD and opt back in to the IED, they will be relying on, and will need to fit in with, the UK’s Transitional National Plan (TNP).  The TNP permits plants to ease in to IED compliance by 2020 rather than 2016.  But the UK’s TNP has so far not been approved by the European Commission as required by the IED.  Second, according to Defra, RWE, EDF and SSE do not have to reach a final decision on IED until the end of 2015.  This may be a very convenient deadline, since it comes after the next election, when operators will know whether Labour’s ambitious “Green Paper” proposals for further market reform are likely to be enacted.   

So, we are a long way from having heard the last of the power-politics of coal – although there are a few more legal elements to the debate than there were in the good/bad old days of the 1960s and 1970s.  There is no doubt that coal still counts, but it looks as if we will have to wait a little longer to see how far we can still count on some of our existing coal-fired plant.

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Coal still counts (2): decision time for generators (or it will be soon)

Contracts for difference: established technologies must compete for strike prices

Only a few weeks ago, DECC announced the “final” strike prices that were to apply to contracts for difference (CfDs) for the various eligible renewable technologies under Electricity Market Reform (EMR) (see our earlier post on this).  But things move fast in the world of EMR.  On 16 January 2014, DECC announced that for those technologies considered “established”, there would be no guarantee of securing strike prices at the level of the figures fixed in December 2013. 

The group of “established” technologies for these purposes consists of onshore wind (>5MW), solar PV (>5MW), energy from waste with CHP, hydroelectric (>5MW and <50MW), landfill gas and sewage gas.  For these technologies, it is proposed that strike prices will be set by a process of competitive bidding for which the December figures will function as a cap.  For the “less established” technologies (offshore wind, wave, tidal stream, advanced conversion technologies, anaerobic digestion, dedicated biomass with CHP and geothermal) the December strike prices will apply.  A decision has yet to be made about strike prices for biomass conversion and Scottish islands projects.

Moreover, all technologies will have to apply for their CfDs through allocation rounds – i.e. at specified times, rather than whenever it is most convenient for them to do so.  There will be no initial period of “First Come, First Served” allocation of CfDs.  The draft CfD allocation framework, originally scheduled for publication in January 2014, will not now be published until March 2014.

The DECC announcement is cast as a consultation, but the key points look fairly firm.  Although the document lists a number of factors that have been taken into consideration, it is clear that the European Commission’s draft state aid guidelines have played a big part in DECC’s thinking (see our earlier post on the draft guidelines).  The draft guidelines place a heavy emphasis on the desirability of competition for subsidies to renewable generators.  

There can be no doubt that the change of approach on strike prices ought to improve the chances of gaining state aid clearance from the Commission for the CfD regime.  But what will be the practical and wider impacts of more projects having to compete on strike prices sooner? 

How “technology-specific” will each auction be?  How frequently will auctions take place? Some questions will have to wait for an answer until we have seen the allocation framework.  For some time now, it has been clear that the allocation framework will be a hugely important document.  Assuming that DECC sticks to its overall timetable, there will not be very much time to consult on the first allocation framework before the package of EMR secondary legislation that requires Parliamentary approval is laid before Parliament.

In the meantime, it is a fair bet that some projects which might have applied for a CfD will now opt for the more predictable support mechanism provided by the Renewables Obligation (RO) instead (as they will be able to do until 2017).  Many of these projects are not large and the process of competing on strike price can only add to the costs of a CfD application.  But if more opt for the RO from the outset, how will that affect the budget available for CfDs under the Levy Control Framework?  And what will be the implications for any state aid analysis of the RO if projects that fail to win CfDs in the auction process can go on and claim what turns out to be a higher level of support under the RO?

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Contracts for difference: established technologies must compete for strike prices

EU renewable generators: time to wean them off “overcompensating” subsidies?

The European Commission has published draft state aid guidelines on environmental and energy aid for 2014-2020 for consultation.  According to the accompanying press release, these would “facilitate the decarbonisation of energy supply and the integration of the EU internal energy market”.  A less charitable reader might detect in the draft guidelines some tensions between the EU’s competing goals of promoting free competition and completing the EU internal energy market on the one hand and the need to reduce greenhouse gas emissions and ensure security of energy supply on the other.

The draft guidelines follow the policy outlined in the Commission Communication on delivering the internal electricity market and making the most of public intervention, published with accompanying  staff working papers in November: the suspicion that, notwithstanding “the challenges of the climate change agenda”, some national subsidy regimes for renewables are “overcompensating” what are now “mature” technologies; that new schemes designed to ensure security of supply may end up supporting plants that are unnecessary or inefficient; and that Member States too readily opt for subsidies rather than pursuing demand reduction options or the potential for EU market integration.

There is considerable emphasis on the use of competitive bidding processes.  The draft thresholds for determining whether a technology is “deployed” and subsidies to it therefore require to be subject to more rigorous criteria may be set quite low (between 1 and 3 per cent of production at EU level).  For each technology / kind of aid, the draft guidelines list specific anti-competitive pitfalls to be avoided and/or ways to monitor for, and correct, possible overcompensation.  And it is envisaged that the guidelines will apply not just to new schemes, but also to existing ones which are amended after the guidelines come into force – unless the only amendment is the publication of a new tariff, or the beneficiary has received confirmation that it will benefit for a predetermined period.

In some ways, none of this should be surprising.  By definition, even aid that has been cleared by the Commission remains susceptible to further examination in the light of changing market conditions – which may lead to something that was originally found compatible with the internal market subsequently being found to be incompatible.  It remains to be seen whether the draft Guidelines will lead to this happening more often, or whether they will change much as a result of this new consultation (the third on this subject).  One thing that is certain is that there is no shortage of high-profile cases to which the Commission can apply its current thinking.  On the same day as the draft guidelines were published the Commission announced an in-depth investigation into a German scheme reducing renewables surcharges to energy-intensive users and into the UK’s proposed aid to EDF’s Hinkley Point C nuclear power station.

All of which comes as a reminder that the low carbon investment support and security of supply elements of the UK Government’s flagship programme of Electricity Market Reform (EMR) require – and have yet to be granted – state aid clearance from the Commission.  The same is true of the proposed exemption for energy intensive industrial users from the increases in supply charges that will fund EMR.  It is not surprising that recent DECC announcements have stressed the possibility of e.g. moving to competitive bidding for EMR contracts for difference (rather than setting the “strike price” administratively) sooner rather than later.  Fortunately, the EMR regime has been designed in such a way as to accommodate a lot of adjustments both before and after it goes live later this year.

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EU renewable generators: time to wean them off “overcompensating” subsidies?