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First flesh on the bones of the new UK government’s energy policy?

The UK Department of Business, Energy & Industrial Strategy (BEIS) chose 9 November 2016 to release a series of long-awaited energy policy documents.  The substance of some of the announcements, which primarily cover subsidies for renewable electricity generation and the closure of the remaining coal-fired generating plants in England and Wales, was first outlined almost a year ago when Amber Rudd, the last Secretary of State for Energy and Climate Change, “re-set” energy policy in outline in a speech of 18 November 2016.  Broadly speaking, the documents indicate that little has changed in the UK government’s thinking on energy policy following the EU referendum and the formation of what is in many respects a new government under Theresa May.

Contracts for Difference

BEIS has confirmed that the next allocation process for contracts for difference (CfDs) for renewable generators will begin in April 2017, aiming to provide support for projects that will be delivered between 2021 and 2023. There will be no allocation of CfD budget for onshore wind or solar, consistent with the Government’s view that these are mature and/or politically undesirable technologies which should no longer receive subsidies.  The only technologies supported will be offshore wind, certain forms of biomass or waste-fuelled plant (advanced conversion technologies, anaerobic digestion, biomass with CHP) wave, tidal stream and geothermal.

The budget allocation is a total of £290 million for projects delivered in each of the delivery years covered: 2021/22 and 2022/23. Details are set out in a draft budget notice and accompanying note.  CfDs are awarded in a competitive auction process, the details of which are set out in an “Allocation Framework” (the one used for the last auction, in 2014/2015, can be found here).  It is likely that most, if not all, of the budget will be taken up by a small number of offshore wind projects, as the size of the projects which could be eligible to bid in the auction is large in comparison with the available budget.

Competition for CfDs will be fierce and Government should be able to show progress towards achieving its target of reducing support to £85/MWh for new offshore wind projects by 2026. For the 2017 auction, “administrative strike prices” have been set at levels designed to ensure that “the cheapest 19% of projects within each technology” can potentially compete successfully.  Behind this terse statement and the methodology it summarises lies an extensive BEIS analysis of Electricity Generation Costs, underpinned or verified by studies or peer reviews by Arup, Imperial College, NERA, Prof Anna Zalewska, Prof Derek Bunn, Leigh Fisher and Jacobs and EPRI.

The heat is on

Alongside the draft budget notice, BEIS has published two documents about CfD support for particular technologies.

One of these is a consultation that returns to the long-unanswered question of what to do about onshore wind on Scottish islands: should it be regarded as just another species of onshore wind (and therefore not to receive subsidy, in line with post-2015 Government policy), or does it face higher costs to a degree that merits a special place in the CfD scheme, as was suggested by the 2010-2015 Government?  It comes as no surprise that the Government favours the former view: another item to add to the list of points on which the UK and Scottish Governments do not see eye to eye.

The second document is a call for evidence on the currently CfD-eligible thermal renewable technologies of biomass or waste-fuelled technologies (including biomass conversions), and geothermal.  These raise a number of issues, on which the call for evidence takes no clear stance.

  • Is continued support for the fuelled technologies in particular consistent with getting “value for money” by focusing subsidies on the cheapest ways of decarbonising the power supply (except onshore wind and solar), given that (with the exception of biomass conversions), they have a relatively high levelised cost of electricity generation?
  • Can they be justified on the grounds that they are “despatchable” (and so do not impose the same burdens on the system as “variable” renewable generation like wind and solar)?  Or on the grounds that (where they incorporate combined heat and power), they contribute to the decarbonisation of heat, as well as of power generation – an area in which more progress needs to be made soon in order to meet our overall target for reducing greenhouse gas emissions under the Climate Change Act 2008 (and the Paris CoP 21 Agreement)?
  • Is the current relationship between the CfD and Renewable Heat Incentive support schemes the right one in this context?  Is a CfD for a CHP plant unbankable because of the risk of losing the heat offtaker?
  • Are all these technologies about to be overtaken as potential ways of decarbonising the heat sector on a large scale by other contenders such as hydrogen or heat pumps (and if so, is that a reason to abandon them as targets for CfD or other subsidy)?
  • Should more existing coal-fired power stations be subsidised to convert to burning huge quantities of wood pellets (is that really “sustainable” – and would such subsidies comply with current EU state aid rules, for as long as they or something like them apply in the UK)?

Against this background, the draft budget notice proposes to limit advanced conversion technologies, anaerobic digestion and biomass with CHP to 150MW of support in the next CfD auction.

Kicking the coal habit

Finally, BEIS is consulting on the best way to “regulate the closure of unabated coal to provide greater market certainty for investors in the generation capacity that is to replace coal stations as they close, such as new gas stations”.  The consultation needs to be read alongside BEIS’s latest Fossil Fuel Price Projections (with supporting analysis by Wood Mackenzie).  These set out low, central and high case estimates of coal, oil and gas prices going forward to 2040.  BEIS has significantly reduced its estimates for all three fuels under all three cases as compared with those in its 2015 Projections.

We are talking here about eight generating stations, which between them can produce 13.9GW. Their share of GB electricity supply tends to fluctuate with the relative prices of coal and gas.  Most are over 40 years old.  All can only survive by taking steps to comply with the limits on SOx, NOx and dust prescribed by the EU Industrial Emissions Directive – at least for as long as the UK is within the EU.

The Government’s difficulty is how to ensure that these plants close (for decarbonisation purposes), but on a timescale and in circumstances that ensure that the contribution that they make to security of electricity supply is replaced without a gap by e.g. new gas-fired plant, of which so little has recently been built. BEIS evidently hopes that by the time this consultation finishes on 1 February 2017, the results of next month’s four-year ahead Capacity Market auction will have seen a significant amount of new large-scale gas fired power projects being awarded capacity agreements at prices that make them viable (when taken together with expectations of lower-for-longer gas prices).

Although BEIS professes confidence in the changes that it has made to the rules and market parameters for the next Capacity Market auctions, one cannot help but wonder how convinced Ministers are that the 2016 auctions will succeed in this respect where those of 2014 and 2015 failed.  Because from one point of view, if the Capacity Market does result in new large gas-fired projects with capacity agreements, and gas prices remain low, the market should simply replace the existing coal-fired plants – which, as the consultation points out, aren’t even as flexible as modern gas-fired plant.  Maybe if a newly inaugurated President Trump pushes ahead with his plans to revive the use of coal in the US, higher coal prices will help accelerate the closure of some of our remaining coal-fired plants: BEIS calculates that with relatively low coal prices and no Government intervention, they could run until 2030 or beyond.

So how will Government make the plants close? Two options are proposed.  One would be to require them to retrofit carbon capture and storage (CCS), the other would be to require them to comply with the emissions performance standard (EPS) that was set in the Energy Act 2013 for new fossil-fuelled plant with a view to ensuring that no new coal plant was commissioned.  Neither path is entirely straightforward.  As it seems unlikely that operators would invest the kinds of sums associated with CCS on such old plant, there must be a risk that in trying to make CCS a genuine alternative to complete closure, regulations could end up allowing operators to run a significant amount of capacity without CCS whilst taking only limited action to develop CCS capacity.  With the EPS approach, there would be some tricky questions to resolve around biomass co-firing, as well as biomass conversion, if that were to remain an eligible CfD technology and budget were to be allocated to it.

When it comes to consider how to ensure that coal closure does not involve a “cliff-edge” effect, the consultation seems to run out of steam a bit: having mentioned the possibility of limiting running hours or emissions, either on a per plant basis or across the whole sector, BEIS says simply that it would “welcome any views on whether a constraint [on coal generation prior to closure] would be beneficial and, if so, any ideas on the possible profile and design”.

What next?

Nothing stands still.  The period of these consultations / calls for evidence, and the next Capacity Market auctions, overlaps with other processes.  Over the next few months, the Government is scheduled to produce over-arching plans or strategies in a number of areas that overlap with some of the questions posed in these documents.  It will also continue to develop its strategy for Brexit negotiations with the EU; and the European Commission will publish more of its proposals on Energy Union (including new rules on renewables, market operation and national climate and energy plans).

The documents state more than once that while the UK is an EU Member State, it will “continue to negotiate, implement and apply” EU legislation. But – at least in relation to coal closure – the Government is trying to make policy here for the 2020s.  By that time, it presumably hopes, it will no longer be constrained by EU law.  It remains to be seen how Brexit will affect the participation of our remaining coal-fired plants in the EU Emissions Trading System, which is at present a significant feature of the economics of such plant.  In the short term, the coal consultation points to an announcement in the Chancellor’s 2016 Autumn Statement (23 November) of the “future trajectory beyond 2021” of the UK’s own “carbon tax”, the carbon price support rate of the climate change levy.

After a period in which we have been relatively starved of substantive energy policy announcements, things are starting to move quite fast, and decisions taken by Government over the next few months could have significant medium-to-long-term consequences for UK energy and climate change policy.

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First flesh on the bones of the new UK government’s energy policy?

UK renewable Contracts for Difference – now only for offshore wind?

The UK’s Contracts for Difference (CfD) regime for renewable subsidies was one of the principal pillars of the Electricity Market Reform programme put in place by the 2010-2015 Coalition Government.  In one way or another, the CfD regime aimed to provide revenue stability for most renewable technologies in projects of more than 5 MW, with consumers sharing in the upside at times when power prices exceed the guaranteed “strike price” set in a competitive allocation process.

Before the UK General Election of May 2015, it was also expected that auctions would follow a regular annual rhythm – or possibly occur more than once a year for some technologies. But things have changed a lot in the last seven months in the world of CfDs – and they continue to change.

  • The Conservative Party, victorious in May 2015, had campaigned on a manifesto promise of “no new subsidies for onshore wind”, which they have been quick to implement, and which appears to include the exclusion of onshore wind (except perhaps on Scottish islands) from future CfD auctions.
  • On 11 February 2016, the Secretary of State for Energy and Climate Change, Amber Rudd, told Parliament: “We don’t have plans at the moment for a large-scale solar contract [for difference]“.
  • The day before, her Department announced “an independent review into the feasibility and practicality of tidal lagoon energy in the UK” – appearing to cast more than a little doubt over the prospects of the Swansea Bay Tidal Lagoon project, with which the Department had previously been said to be negotiating CfD support (tidal lagoon projects, like nuclear ones, fall outside the scope of the competitive CfD allocation framework).
  • The news that the European Commission has doubts about the compatibility with EU state aid rules of the proposed CfD for the conversion of a third unit at the Drax coal-fired power station to burning biomass perhaps makes it unlikely that there will be many, or any, more CfDs awarded for this technology.
  • Almost a year after the results of the first (delayed) CfD auction were announced, there is no sign as yet of Government gearing up for a second auction any time soon – merely a promise that there will be funding for three more auctions before mid-2020.

To be fair, so far, nothing has been said to suggest that Energy from Waste with CHP, Hydro (up to 50 MW), Landfill Gas, Sewage Gas, Wave, Tidal Stream, Advanced Conversion Technologies, Anaerobic Digestion, Biomass with CHP or Geothermal will not be eligible if and when the second auction finally takes place, but the fact remains that for the foreseeable future, offshore wind appears likely to dwarf all the other CfD-eligible technologies.

In clearing the original CfD rules for state aid purposes, the European Commission noted, as apparently relevant facts, that “All generators producing electricity from renewable energy sources will be able to bid for a CfD on non-discriminatory basis (albeit that some less established technologies will initially benefit from allocated budgets in order to promote their further development).“, and that “in the absence of aid renewable energy technologies will not be deployed at the required scale and pace, as without the aid such projects would not be financially viable.”  This was in keeping with the emphasis in the relevant State Aid Guidelines that an “auctioning or competitive bidding process open to all generators producing electricity from renewable energy sources…should normally ensure that subsidies are reduced to a minimum“, but admitting that “given the different stage of technological development of renewable energy technologies“, technology specific tenders may be allowed “on the basis of the longer-term potential of a given new and innovative technology, the need to achieve diversification; network constraints and grid stability and system (integration) costs“.

The statutory framework for CfD auctions allows the Secretary of State enormous flexibility to determine, at very short notice and in documents which are not subject either to Parliamentary approval or any statutory consultation requirement (the “budget notices” and “allocation frameworks”), which technologies will be eligible for support in a given auction.  However, it must be arguable that a decision effectively to exclude technologies as significant (and competitive) as onshore wind and solar from the allocation process could amount to a change in the CfD rules which should itself be notified to the Commission for state aid approval.  And it is not entirely clear that such exclusions could be – or at any rate have been – justified on the grounds specified in the Guidelines as a basis for technology specific tenders.

A cynic or conspiracy theorist might suspect that the lack of urgency in proceeding to a second CfD auction may not be unrelated to the UK Government’s reluctance to put itself – in advance of a referendum on the UK’s continued membership of the EU – in the position of appearing to have to ask the Commission’s permission (in the form of a state aid clearance for alterations to the CfD rules) not to offer CfDs to technologies that Ministers do not want to subsidise.  But cynics and conspiracy theorists are often wrong.  The Government is perhaps more likely to be just taking its time to consider the future of CfDs more broadly.  For example, in the 11 February 2016 Parliamentary exchanges referred to above, Ministers confirmed that they are looking “very closely” at the seductively labelled and highly fashionable concept of “subsidy-free CfDs” (which means different things to different people, but for one interesting suggestion, see this blog post by Professor Michael Grubb of UCL).

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UK renewable Contracts for Difference – now only for offshore wind?

The Politics of Onshore Wind

The new Conservative Government has made curbing the growth of onshore wind one of its short-term priorities.  On 18 June 2015, the Department of Energy and Climate Change (DECC) confirmed the Government’s intention to implement the Conservatives’ 2015 General Election manifesto promise to “end new public subsidies for onshore wind” by “legislating to close the Renewables Obligation across Great Britain to new onshore wind generating stations from 1 April 2016”.  The Secretary of State for Energy and Climate Change, Amber Rudd, made a further, oral statement to Parliament on 22 June 2015, giving further details of her thinking and the potential impacts of the change.

DECC has stated that “up to 5.2GW of onshore wind capacity could be eligible for grace periods which the Government is minded to offer to projects that already have planning consent, a grid connection offer and acceptance, as well as evidence of land rights”.  But it has also calculated that some 7GW of new onshore wind capacity (250 projects, 2,500 turbines) are likely not to be commissioned as a result of the early closure.  The future treatment of onshore wind under the separate Contracts for Difference and Feed-in Tariffs regimes remains to be clarified.

Industry has not been slow in condemning the chilling effect which the Government’s announcement will have on many projects.  But what can they actually do about it?

The Renewables Obligation (RO) is scheduled to be closed to new projects on 31 March 2017 in any event (subject to some grace period arrangements) as part of the transition to the Contracts for Difference regime being the primary subsidy vehicle for large-scale renewables projects.  The early closure for onshore wind echoes the treatment of >5MW solar projects, to which the RO was closed on 31 March 2015, subject to one-year grace periods both for projects already holding planning consent, grid connection offer and acceptance and evidence of land rights, and for projects which only failed to commission in time to be accredited by 31 March 2015 because of grid delays.

The early closure of the RO to >5MW solar was effected by an “RO closure order”: a piece of secondary legislation which Ministers were given powers to make (subject to Parliamentary approval) under the Energy Act 2013.  Ministers could, of course, use the same method in the case of onshore wind, but the DECC announcement states that the closure of the RO for onshore wind will be achieved by primary legislation – i.e. a Parliamentary Bill.  This means that there will be no statutory obligation to consult on the proposals before they are put to Parliament.  It also means that they will receive vastly more Parliamentary scrutiny: when a draft order is put before Parliament, it is presented on a take-it-or-leave-it basis and it is seldom debated for more than an hour by a handful of MPs or Peers.  In the vast majority of cases, the draft is approved.  By contrast, any provision that is put before Parliament as part of a Bill is capable of being amended or made the subject of counter-proposals.  So the industry can fight back by lobbying MPs and Peers, and the Government’s Commons majority may or may not be strong enough to make it impossible for those seeking a less harsh outcome for onshore wind projects to make some headway.

Before the 18 June announcement, there was much talk of possible legal challenges to the expected ending of onshore wind subsidies.  However, DECC’s decision to use primary legislation makes judicial review a less promising avenue for the industry.  A recent judgment in a case relating to changes to solar subsidies has made it clear that in certain circumstances a Government decision to consult on proposed subsidy cuts can be challenged in itself (even if there is no subsequent decision to implement the proposal).  The same case has clarified the range of circumstances in which projects which have not yet achieved accreditation under a subsidy scheme can nevertheless still make a claim for damages as a result of a change in subsidies.  However, if the next thing that Government does is to introduce provisions to implement the closure of the RO to onshore wind in its forthcoming Energy Bill, it is doubtful whether that action could be judicially reviewed.  Unlike a decision to make a piece of secondary legislation, or to consult on doing so, which are executive acts, a Minister’s decision to put forward a Bill is something that he or she does in his or her capacity as a Member of Parliament.  As such, it may well be considered by the Courts to fall within the category of “proceedings in Parliament” which are not judicially reviewable.  One possible trump card for the industry might be to find a way of characterising the proposed legislation as contrary to EU law: no doubt some opponents of onshore wind (inside and outside Parliament) would relish that.

The industry – using the language of judicial review – has attacked the early closure as “irrational”.   Amber Rudd told Parliament: “We could end up with more onshore wind projects than we can afford – which would lead to either higher bills for consumers, or other renewable technologies, such as offshore wind, losing out on support.  We need to continue investing in less mature technologies so that they realise their promise, just as onshore wind has done.”  The references to issues of affordability and the impact that the amount of subsidy budget (the “Levy Control Framework”) that wind would consume might have on support for other types of renewable generation echo the arguments for closing the RO early to >5MW solar, where a claim for judicial review was firmly dismissed.  But it is hard to avoid the feeling that political, as well as economic considerations are in play.  And although DECC has stated that “we now have enough subsidised projects in the pipeline to meet our renewable energy commitments”, it is interesting to note that a few days earlier, the European Commission published a status update on EU Member States’ prospects of meeting their 2020 renewables deployment targets that showed the UK as being one of a number of Member States that need to “assess whether their policies and tools are sufficient and effective in meeting their renewable energy objectives“.

The subsidy change is explicitly linked to the parallel commitment to “give local communities the final say over any new wind farms”, fleshed out in a statement from the Secretary of State for Communities and Local Government on the same day.  But whilst the subsidy changes would apply throughout Great Britain (the content of the RO being for DECC Ministers to determine), the planning regime is more of a patchwork.  Hitherto, broadly speaking, onshore wind projects up to 50MW were consented by local planning authorities (everywhere), while applications to develop projects of 50MW or above fell to be determined by DECC Ministers in England and Wales and Scottish Ministers in Scotland.  It is now proposed that all wind farm applications in England will be decided locally, and that planning permission should only be granted if “the development site is in an area identified for wind energy development in a Local or Neighbourhood Plan”.  This gives English local authorities who do not wish to see wind farms in their area much greater ability to refuse them planning permission.  In Wales, under the St David’s Day Agreement, there are moves to devolve consents for projects up to 350MW to Welsh Ministers.  But before that happens, a number of old consent applications for >50MW onshore wind projects in Wales that have attracted considerable opposition and been the subject of a public inquiry are likely to be decided by DECC Ministers.  In Scotland, where >50MW consents are already devolved, no changes made by Ministers in Whitehall in relation to consenting will have an effect, but the subsidy changes will probably have a much greater negative impact on future projects throughout Great Britain than any decisions taken by planning authorities or Ministers on consents.

It could be said that all this is simply democracy at work.  There is a broad strand of Conservative opinion that is anti-onshore wind.  The Conservative Party sent a clear signal of its intentions in regard to onshore wind in its manifesto.  It won the election.  Of course, it didn’t do very well in Scotland, but while most of the big onshore wind farms are in Scotland, the money to support them under the RO mostly comes from England, where the largest number of consumers (who pay for subsidies in their electricity bills) live.  No doubt there will be lively debates on the provisions of the current Scotland Bill that proposes (very limited) further devolution of energy matters to the Scottish Government, as well as on the provisions of the forthcoming Energy Bill on closure of the RO to onshore wind.  But it hardly needs saying that however politically exciting the process may be, it does not provide a stable background for investment in what is apparently still the cheapest form of renewable generation – and one which new research suggests could also be made a lot quieter and more efficient, thus removing some of the stronger potential non-aesthetic objections to it.

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The Politics of Onshore Wind

CfDs: not unduly distorting the market, but not best value for money?

The European Commission’s state aid decision clearing the UK’s “enduring regime” of renewables contracts for difference (dated 23 July, published on 2 October 2014) confirms the CfD regime as a model example of the kind of renewables support scheme that the Commission wants to encourage, as described in its April 2014 Guidelines on state aid for environmental protection and energy.

The decision is littered with cross-references to the Guidelines, reflecting the fact that key details of the CfD regime were effectively developed in dialogue with the Commission.  Among the key points in favour of the regime as far as the Commission is concerned are that the strike price mechanism limits the ability of generators to benefit from very high prices; that “the strike price paid will be established via a competitive bidding process”; and that it cannot be higher than the administratively set strike price, which is based on “the levelised costs of eligible technologies and reasonable hurdle rates”.  Other points to note include future measures to ensure that generators do not have an incentive to generate electricity when prices are negative and details of the treatment of biomass conversions and imported renewable electricity.

Given the Commission’s emphasis on the benefits of strike price competition, it is interesting to note the parallel clearance for the award of early “FID-enabling” CfD “investment contracts” – outside the enduring regime, and with no competition on strike prices – to five UK offshore wind farms (Walney, Dudgeon, Hornsea, Burbo Bank and Beatrice).  For the Commission, the award of these contracts was justified because “the Commission was able to verify that the amount of aid for each project is limited to what would be necessary to allow the project to reach a reasonable rate of return” and “the Commission further notes that…the notified projects are all reaching an IRR below the central value of the hurdle rates considered by the UK”.  However, as if DECC needed to be reminded that it cannot please everybody all the time, within a day of the release of the two state aid decisions, the Public Accounts Committee published a report that criticised the investment contracts as poor value for money, repeating a number of points first made in a National Audit Office report in June.

The PAC’s headline criticism is that the investment contracts will consume up to 58% of the total funds available for renewable CfDs to 2020/2021 – without accounting for a correspondingly large proportion of the new renewable generating capacity that is to be funded by CfDs.  They argue that committing so much of the overall CfD budget to the five offshore wind projects and three biomass projects (which have yet to receive state aid clearance) was both unnecessary (because the 2020 targets for renewables deployment could have been met in any event) and represents poor value for consumers, because the enduring regime, with its more competitive allocation processes, can be expected to deliver more MW of renewable power per £ of subsidy.  Ultimately, as both the PAC and NAO acknowledge to some extent, the effect of the investment contract regime may have been to ensure the continuing healthy development of the offshore wind industry in the UK, albeit potentially at the cost of support for some later offshore wind (and possibly other) projects.

Whilst there may be a wider political context to the line taken by each of the Commission and the PAC, their different appraisals of the investment contracts regime also reflect their different functions.  The Commission, in reviewing proposed state aid measures, is properly concerned only with their impact on competition within the EU internal market.  It is not in the business of telling Member States that one renewable technology or project is better or worse value than another for UK consumers, provided that neither is being given more aid than is strictly necessary to remedy the market failure that inhibits its development in the absence of aid.  If gaining state aid approval were simply a matter of comparing the level of subsidy per MW of new generating capacity, the investment contracts for the biomass conversions at Drax and Lynemouth (with an estimated CfD level of support of £2.6m/MW and an assumed load factor of 64.5%) would not still be awaiting clearance when the aid to the five offshore wind farms (with estimated CfD levels of support of between £3.4m/MW and £4.4m/MW and an assumed load factor of 37.7%) has been approved.

 

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CfDs: not unduly distorting the market, but not best value for money?

Worth the wait? DECC responds to RO / CfD consultations

In July and November last year, DECC consulted on the transition period between the introduction of the Contracts for Difference (CfD) regime under Electricity Market Reform (EMR) later this year and the closure of the Renewables Obligation (RO) to new generating capacity at the end of March 2017.  The response to these consultations was published earlier this week, just as Spring came to London.  Some of the policy decisions it sets out will already have been apparent to careful students of the draft Renewables Obligation (Amendment) Order 2014 that was published and laid before Parliament last month with an accompanying  written ministerial statement, but the response provides an opportunity to see DECC’s approach to RO / CfD transition issues in the round, with a fuller set of explanations.

Botticelli’s “Spring”: spot the connections between the picture and this post!

The transition period

The transition period begins once the CfD regime is live.  No firm date is given for this, but the response refers to 31 October 2014 as the date when CfD applications are expected to open.  It also says Government does not expect applications for CfDs to be open in advance of State Aid clearance. 

Choice of scheme

During the transition period, developers will be able to apply for accreditation under the RO or for a CfD or Investment Contract (if they meet the relevant eligibility criteria).  When they make their applications, they will be required to make various declarations: for example, if they are applying for a CfD, to declare that they are not supported under the RO.  A developer who is unsuccessful in relation to an application under one scheme will be able to apply under the other. 

A developer whose Investment Contract is terminated for certain reasons relating to State Aid, or to possible amendments to the Investment Contract in the light of the standard terms for CfDs will be able to apply for RO accreditation.  But a developer who withdraws an RO or CfD application or refuses a CfD or RO accreditation will not be able to apply under the other scheme: so, you cannot, for example, bid for a CfD, decide that you don’t like the strike price (e.g. in a “pay as clear” regime), and decide to retreat to the perceived safety of the RO instead. 

The level of the RO (i.e. the extent of the obligation on electricity suppliers to purchase ROCs) will continue to be set by 1 October, rather than being pushed back to being decided by 1 February.  Whilst effectively acknowledging that the likely launch of the CfD regime in the later part of this year will complicate the task of setting the RO level at the same time, Government has been persuaded that moving to a February deadline would mean that suppliers had to rely on their own internal RO forecasts when pricing supply contracts, resulting in the addition of a risk premium which would increase consumer bills.  The status quo was therefore preferred.

Dual Scheme Facilities

Additional capacity added to an RO accredited project will be eligible for registration under the RO if no application for a CfD has been made in respect of the project.  However, additional capacity of 5MW or less added to RO accredited stations after 31 March 2017 will not be eligible for RO or FiT support.  On the basis of the representations made to it, DECC does not seem to believe that there is a significant class of potential ≤5MW extensions to existing RO-accredited projects which would not be able to go ahead without an extension of the RO deadline (or FiT support) beyond March 2017. Although, between 2006 and 2012, 131MW of the 190MW of additional capacity accredited in respect of existing projects was ≤5MW, 103MW was for landfill and sewage gas sites: analysis of this sector suggests that existing sites have added most of the extra capacity they can, and DECC do not expect many new sites to be developed under the RO.  Finally, increases in capacity resulting from station refurbishment or unit replacement after the closure date will not be eligible for support under the RO.

On the other hand, projects which are developed in phases may find themselves with part of their capacity accredited under the RO and part being the subject of a CfD.  In such cases there will need to be separate metering and fuel data collection for the two parts of the project, so as to make sure that plants do not claim ROCs / CfD payments in respect of capacity which is not entitled to them.  As DECC puts it, “preventing arbitrage opportunities between the two schemes and ensuring accuracy, is crucial to minimise the impact on consumer bills”.  DECC also take the view that the dual scheme arrangements should not be available to RO-accredited projects which wish to add less than 5MW of extra capacity funded by a CfD, as it would give rise to an “unjustified” and “disproportionate administrative impact in relation to the amount of additional generation produced”.

Grandfathering

The July consultation included some proposals about grandfathering, with particular reference to biomass co-firing.  The response reports “widespread misunderstanding” of these proposals, which DECC concludes “were too confusing and administratively complicated to take forward” and “would have had little genuine impact in terms of budgetary stability”.  Further proposals in this area may be consulted on “later in the spring or summer”.

Grace periods

The grace periods are a set of four exceptions to the rule that the RO closes to new capacity on 31 March 2017: projects which reach the stage at which RO accreditation could have been given within a certain period after that date will be allowed to be accredited in certain circumstances.  A project that is in a position to benefit from two or more of these exceptions will only be permitted to benefit from one, but (subject to the eligibility rules) has a free choice in deciding which one it will benefit from.

  • New or additional capacity which is delayed by a failure to resolve issues with radar or to establish a grid connection will have a 12 month grace period.  In the case of grid delays, there must be evidence of a grid connection offer made and accepted and a network operator having set a date before April 2017 for connecting the project.
  • There will be a 12 month grace period for any project that is awarded a FID Enabling Investment Contract if that contract is terminated either for reasons relating to state aid or because the developer exercises a right to terminate when changes are made or proposed to it in the light of the CfD standard terms.   
  • A 12 month grace period will be available to a class of ACT or offshore wind projects which are scheduled to commission close to 31 March 2017 and have been identified as at risk of investment hiatus.  These projects are expending funds but are unwilling to commit to the CfD regime because elements of it are still uncertain.  The deadline for applications for this grace period will be 31 October 2014 – i.e. about the time when applications for CfDs are expected to open.  DECC rejected suggestions of a later deadline “as it could give projects which could have applied for a CfD shortly after applications open an incentive to enter the RO instead”.  Of course, it may be that by requiring developers to apply for the grace period before the outcome of the first CfD allocation round is apparent, DECC will simply guarantee that they opt for the RO, but DECC’s thinking seems to be partly that it is targeting projects that ought to be commissioned before 31 March 2017 and making sure that this happens by giving them the confidence to proceed, in the knowledge that the grace period provides them with a safety net.  By way of evidence that they are sufficiently advanced to be eligible for this grace period, developers will have to produce a grid connection offer, a letter from the network operator indicating that connection will take place before April 2017, planning consent (the conditions of which need not have been discharged) and land use rights or an option to acquire them.  They will also have to produce a director’s certificate confirming that the developer will have sufficient resources to commit to the project and that it is expected to commission before April 2017.  Various forms of more detailed evidence of “substantial financial commitment” towards the project were considered and rejected as “too restrictive, too unclear or too sensitive”. 
  • DECC begins discussion of the final grace period by observing that “dedicated biomass projects have in some cases been delayed while detailed Government policy arrangements in relation to the 400MW cap were put into place”.  Dedicated biomass projects allocated an unconditional place within the cap will therefore be offered an 18 month grace period, regardless of whether they are CHP or not.  However, this grace period will not be available for additional capacity.

Further measures for biomass

Generating stations which co-fire biomass and are RO-accredited but have never claimed ROCs under the biomass conversion support band will be permitted to apply for a CfD or Investment Contract as biomass conversions, and leave the RO if they are successful.  If the operator gets cold feet about its CfD before reaching the CfD “Start Date”, it will be able to revert to the RO.  However, DECC has not yet decided whether an operator which finds itself in this position with respect to only some of the units in a generating station would still be entitled to claim ROCs at the conversion band for units in respect of which it has not previously fired or claimed this level of support.

Biomass co-firing stations which are supported by the RO will be permitted to bid into the EMR Capacity Market, leaving the RO if they are successful in their bid.

Offshore wind

Offshore wind projects accredited under the RO when it closes will be permitted to commission their remaining phases under (i) the RO, (ii) the CfD or (iii) both regimes, provided that they “inform Ofgem by 31 March 2017 “whether they intend to take up the RO option” in relation to any of those phases.  Option (iii) is expected to be a minority interest.  RO and CfD phases “will need to be on entirely separate strings of turbines”, with no connection that enables electricity generated by one string to be exported on another.  

Replacement of ROCs with Fixed Price Certificates

The July consultation opened up the possibility that the transition from the current ROC regime to a system of fixed price certificates (FPCs) might be brought forward to coincide with the closure of the RO to new capacity in 2017 rather than taking place in 2027 as originally proposed.  However, DECC intends to stick to the original plan, because consultees did not persuade it that ROC values are likely to fall below the buyout price or that a significant oversupply of ROCs is likely to occur.  

What next?

The implementation of most of these policies will be spread across the RO (Amendment) Order mentioned above (intended to come into fore on 1 April 2014) and the RO Closure Order (due to be laid before Parliament in May and come into fore in July 2014).  “Some remaining transition policy issues, such as those relating to interaction between the RO and the Capacity Market” will be dealt with in an RO Consolidated Order to be made “later in 2014/15”.

Comments

In a world where there is no perfect answer and the most important thing is for developers to know where they stand, DECC’s consultation response is to be welcomed.  It bears the hallmarks of  evidence-based policy making and shows a proper degree of engagement with what consultees had to say as well as a willingness to interrogate critically the representations that they made.  

Overall, the response appears to take a slightly tougher line than is sometimes found on what DECC evidently sees as unjustified special pleading in some areas.  This, and a recurrent emphasis in the response on controlling costs, make sense both in domestic political terms and from the point of view of clearing these policies with the European Commission under the state aid rules.  

The response is perhaps a little more favourable on balance to biomass developers than some of DECC’s publications on biomass of last year, whilst emphasising its transitional status.

DECC has tried to keep things simple at a number of points.  However, the detail of what must be done in order to be eligible to make particular choices is inevitably quite intricate.  Developers will need to think carefully about how to integrate transition and grace period decision-points and criteria, as well as the various steps in RO and CfD procedures, into their own project plans.

As ever with EMR, some big questions remain.  Perhaps the biggest in this case is whether the flexibility to move between the RO and CfD regimes will encourage those who are able to choose either regime to opt for a CfD in preference to the RO.  If it does not, there must be a risk that the RO’s share of Levy Control Framework funding (see the table below, based on DECC figures) will continue to dominate UK renewables subsidies to a greater extent and for a longer period than to be comforably consistent with either the ultimate goals of EMR or the European Commission’s policies on state aid for renewables schemes.

£m 2011/2012 prices 2015/2016 2016/2017 2017/2018 2018/2019
  £ % £ % £ % £ %
Levy Control Framework Cap: RO + FIT + CfD 4,300 100 4,900 100 5,600 100 6,450 100
Committed FIT expenditure(estimated) 760 18 760 15 760 14 760 12
Committed RO expenditure(estimated) 2,900 67 2,790 57 2,790 50 2,790 43
Projected new FIT expenditure 40 1 130 3 200 4 260 4
Renewables Investment Contracts (maximum) 260 6 450 9 720 13 1,010 16
New RO projects, other CfDs 340 8 770 16 1,130 20 1,630 25

 

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Worth the wait? DECC responds to RO / CfD consultations