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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?

DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

The UK Department of Energy and Climate Change (DECC) has launched a consultation proposing savage cuts in the levels of subsidy under the Feed-in Tariffs (FITs) regime for small-scale renewable electricity generation (the Consultation).  This comes only a few weeks after DECC announced the ending of more or less all subsidies for onshore wind, the removal of the renewables exemption from the Climate Change Levy and other proposals designed to reduce the costs of renewable subsidies significantly.  What does the Consultation say, and what does it mean for the future of renewables in the UK?  We look first at the background of the FITs regime and then at the detail of the proposals.

Some background

The legal foundation for the FITs regime was inserted very late in the Parliamentary passage of the Bill that became the Energy Act 2008.  Although there had been pressure to include provision for FITs from the moment the Bill was introduced in January 2008, the then Labour Government only finally gave in to it on 5 November 2008, by which time the Bill was rubbing shoulders in the Parliamentary timetable with legislation designed to avert financial meltdown as a result of the banking crisis.

Perhaps we should not be surprised that a scheme launched in the far-off days of Gordon Brown’s premiership should now be in the process of being dismantled, after 5 years of apparently too successful operation, as part of the current Conservative Government’s attempts to reduce public spending (whether funded from taxation or levies on consumers).  To see quite how different the world looked in 2008, it is worth recalling that Ministers then looked forward to a time when, by 2020, the Renewables Obligation (RO), newly modified to include different bands of support for different technologies would be “worth about £1 billion a year in support of the renewables industry”.  Current annual support under the RO runs at around three times this level, and it may hit £5 billion by 2020.

During the passage of the 2008 Energy Bill, EU Member States were set the targets for the percentage of final energy consumption from renewable sources that they would have to meet by 2020 under the Renewables Directive of 2009.  Some suggested that the UK would not meet its target of 15% unless FITs were introduced.  There was a widely held view that following the German model of FITs was at least an essential supplement to the RO, and that feed-in tariffs were generally, and could be in the UK, a cheaper way of subsidising renewables.

That was perhaps over-optimistic.  DECC and Ofgem figures show that in 2013-2014, generating stations accredited under the RO produced 49.6 TWh, or 16.3% of electricity supplied in the UK. At the same time, FIT installations produced 2.6 TWh, or 0.84% of the UK’s final consumption of electricity.  But whilst the output of RO-subsidised generation to FIT-subsidised generation stood in a ratio of about 19:1, the comparative costs of RO were no more than 4 times those of FITs.  Another comparison from DECC’s evidence review of FITs is even more interesting, when it calculates that the p/kWh cost of FIT-generated electricity is about 3 times the level of the strike price under the proposed Contract for Difference (CfD) for the Hinkley Point C nuclear power station.

Perhaps this should come as no surprise.  FITs were intended as a way of encouraging “microgeneration”.  One of the ways that renewables resemble other forms of power generation is that they tend to be more cost-effective on a larger than on a smaller scale.  But FITs were not just about meeting targets: they were to make renewable generation accessible to individual households for whom trying to deal with the RO was (in the words of one MP, apparently speaking from personal experience) a “bloody nightmare”.  FITs would be simple, and they would popularise renewables.

That part certainly seems to have worked.  As DECC notes, the scheme has all but reached 750,000 FIT installations already – a level it was not originally expected to reach until 2020.

Headline proposals

DECC says that the deployment of FITs has been significantly exceeding its projections both in terms of numbers of installations and installed capacity. As a result, the FIT scheme has put undue financial pressure on the Levy Control Framework (LCF), which was created to limit the extent to which consumer bills increase to fund the subsidies for low-carbon generation.  The measures proposed in the Consultation are intended to remedy these problems.

Significant decreases in generation tariffs for solar PV, wind and hydro power 

At the larger end of the scale of FIT eligible installations, generation tariff reductions are proposed for:

  • standalone solar PV (Large Solar PV) – from 4.28 p/kWh to 1.03 p/kWh;
  • wind farms with a capacity >1.5 MW (Large Wind) – from 2.49 p/kWh to 0 p/kWh; and
  • hydro installations with a capacity  >2MW (Large Hydro) – from 2.43 p/kWh to 2.18 p/kWh.

Installations with smaller capacity would also see their tariffs reduced, in the case of solar PV, even more steeply, with 4 kW installations having an 87% reduction in generation tariff levels.

In addition, the different capacity-based generation tariff bands for each technology would change (their number being reduced in the case of wind and hydro and the boundaries redrawn for solar).

It can be said that the relative levels of reduction in generation tariffs roughly correspond to the extent to which DECC’s Impact Assessment reckons the different sizes and types of installation have seen reductions in their grid connection and capex costs since 2012.  But only roughly: for example, it appears that Large Solar PV has seen an increase of 3% in costs and will have its tariff reduced by 76%, while the smallest PV installations have seen a decrease in costs of 35% and will have their tariff reduced by 87%. These reductions in generation tariffs are said to be aiming at a target rate of return of 4%, as compared to the 5-8% range of rates of return that was used to calculate the current tariff rates

The changes would mean that for future solar PV installations, the generation tariff (received on all the power they generate) would be a much less significant component of their revenue stream than it has been historically.  For those receiving the export tariff for the electricity which they export (or are deemed to export), the export tariff is likely, at least initially, to be higher in p/kWh terms, but by far the largest benefit for those who consume the renewable electricity that they produce will be in the avoidance of the costs of purchasing electricity generated elsewhere from a third party supplier.

The problem for most solar installations though, especially on domestic premises, is that for much of the year, the bulk of household energy consumption tends to occur at times when there is no sun and no generation.  The solution to that would be to connect your PV panels to a battery and store the electricity generated during daylight hours for the evening.  But – needless to say – the Consultation contains no proposals for any new German-style subsidy for adopting storage technology.

Degression

At present, FIT generation tariffs “degress” periodically by a fixed percentage automatically, but can degress further if deployment reaches specified thresholds (contingent degression).

The Consultation proposes:

  • a new fixed quarterly degression mechanism, reducing generation tariffs available for new Large Solar PV to zero by January 2019.  DECC is not proposing to degress the generation tariffs for Large Hydro, which would stand at 2.18p/kWh throughout the three-year period budgeted for under the Consultation;
  • harmonising the frequency of degression to quarterly across all technologies; and
  • a further degression of 5% if deployment of FITs exceeds DECC’s deployment projections, and 10% if the cap (discussed below) on the eligibility of new projects for the FIT scheme is reached.

The Impact Assessment takes as a working assumption the proposition on which DECC consulted in July, that future FIT eligible installations will not be able to protect themselves from the impact of degression by applying for preliminary accreditation when they have planning permission and an accepted offer of a grid connection, thereby “locking in” to the higher tariff band prevailing at the time of preliminary accreditation for a period of between 6 and 30 months (depending on technology and ownership of the installation) provided that they are commissioned and accredited within that period.

Indexation

Previously, both generation and export tariffs have risen automatically in line with the Retail Price Index (as under the RO).  New installations will see their tariff payments rise according to the movements of the Consumer Price Index link (as under the CfD regime), which is less generous.

Overall cap

So far, the proposed changes, although they slash the amounts of support available to new installations, leave the basic architecture of the regime in place.  But the existence of the proposed new FIT regime is a much more precarious thing than might be suggested by any of the above.

This is because DECC further proposes:

  • a maximum overall budget for the FIT scheme of £75 – 100 million for the period from January 2016 to 2018/2019.  This would apparently be expressed as a series of quarterly limits on FIT-supported deployment at each generation tariff level, so that once the cap is reached no further generating capacity would be eligible for the tariff during the period to which the cap applies;
  • separate caps for each of a number of different capacity-based bands for solar and wind (each of which cover a number of generation tariff bands).  These would limit quarterly FIT solar deployment, for example, to between 42 MW and 54 MW during the period budgeted for by DECC in the Consultation (Q1 2016 – Q1 2019).  This is less than is typically accredited in a single month at present.  The caps on larger solar installations would limit deployment under FIT to one or two per quarter; and
  • unlike the measures relating to generation tariffs and degression, the caps would apply to anaerobic digestion (AD) installations as well as solar, wind and hydro.

With exquisite understatement, DECC observes: “We recognise that implementing deployment caps presents significant logistical challenges.”, although DECC has outlined a number of possible ways in which the caps might be administered (essentially, by Ofgem or by licensed suppliers).  Anticipating the possible objections to a system where eligibility for a particular tariff (or any support at all) would depend on the relative timing of accreditation of different installations, measured in seconds, DECC proposes to suspend the FIT regime pending any better suggestions.  Anticipating the objection that a cap will simply not achieve its purpose of controlling costs, the Consultation proposes the alternative solution of ending generation tariffs altogether, possibly as soon as January 2016.  The industry is, in effect, challenged to accept the capping proposals or face potentially worse consequences.

Almost as an afterthought, DECC adds that its consideration of “further amendments to the existing FITs scheme to ensure that it provides better value for money” includes “consideration of whether future applications within a system of caps could be prioritised through a competitive process“.  It’s a pity the CfD regime, with its competitive allocation process, wasn’t designed to cover microgeneration.

Other points

DECC is concerned that (especially in the wind and AD sectors) the “extension” of an existing FIT installation – or developing what is in truth a single installation in a series of separately accredited stages – can be used as a way to gain the benefits of economies of scale associated with larger installations whilst qualifying for the higher generation tariff rates associated with smaller installations, leading to “overcompensation”.  To put an end to this, it is proposed to “put in place a rule to prevent new extensions claiming support under FITs.”  No detail is given as to how this will work in practice.

When the Energy Bill was being debated back in 2008, three issues were often raised (not necessarily in connection with FITs) on which less progress has been made in the intervening years than could have been wished: smart meters, the impact of small-scale renewable generation on distribution networks, and energy efficiency.  The Consultation has something to say on each.

  • DECC propose to end the practice of estimating how much electricity smaller installations export to the grid (deemed exports) in favour of full metering of exports, and may take further measures to enable remote generation meter reading.  The key question here seems to be whether existing installations of 30kW and below should be compelled to accept smart or “advanced” meters in order to facilitate this more accurate and “remote” measurement of their FIT entitlements.  DECC note that deemed exports were meant to be a temporary measure.  It remains to be seen whether smart meters will be rolled out before the FITs regime closes to new installations.
  • More accurate measurement of exports would facilitate a further reform: moving to “dynamic” export tariff rates that could reflect changes in the wholesale price of electricity, rather than the current, static export tariff rates.  It is a matter of concern to DECC that “the current export tariff is higher than the wholesale electricity price, with resulting overcompensation of generators by suppliers“.  This is because the tariff is meant to represent the wholesale price less the value of the transmission and distribution costs which suppliers do not have to pay in respect of FIT electricity (even though, DECC acknowledges slightly confusingly “in certain circumstances these can be additional rather than avoided costs“).
  • DECC propose an obligation to notify DNOs of new small-scale generators to facilitate grid management.  The problems of DNOs not being made aware of new generation on the grid are not new.  Such an obligation is perhaps a case of “better late than never”, but would no doubt have been more welcome to DNOs when FIT generating capacity was still increasing at a rate unconstrained by the proposed new caps.
  • DECC propose that roof-mounted solar PV installations seeking to accredit at the higher generation tariff rate should satisfy the requirement of being at least in energy efficiency band D before they commission the solar installation, rather than being able to count the installation itself as one of the things entitling them to be certified at band D or above.  Under the current regime, the higher tariff sees to have become effectively a default rate, applying to 99% of installations, rather than setting any kind of incentive to improve the energy efficiency of buildings.  DECC mentions, but is not yet proposing, the further step of raising the higher tariff threshold to band C.

Finally, DECC is “considering implementing”, but is not yet proposing, changes such that AD plants that sought accreditation under the FIT regime would have to comply with the same sustainability requirements that the feedstock of AD plants seeking support under other renewable incentive mechanisms (e.g. the RO and Renewable Heat Incentive) are required to observe.  This would be to avoid FITs becoming a haven for operators with non-compliant feedstocks.

The good news?

In contrast to some of its recent proposals in relation to the RO, DECC has reasserted its commitment to its “grandfathering” policy on FITs, so that existing installations will not be affected by the proposed changes to tariffs and caps.  However, the Consultation does not address explicitly the question whether any tariff reductions will affect projects which have been pre-accredited (whilst this was still possible) but have not achieved full accreditation at the point when the new tariffs come into effect. Such projects are likely to be at risk of being subject to the new, lower tariffs if construction or grid connection delays result in them not being commissioned and applying for full accreditation within their pre-accreditation periods of e.g. 6 months (12 months for community projects) for solar PV.  But it is to be hoped that if they are commissioned and accredited within their pre-accreditation periods, they will still benefit from the earlier, higher tariffs prevailing at the time of their pre-accreditation.

What next?

The proposed measures in the Consultation, if implemented, will bring about a drastic change in the FITs regime.  Is this anything more than the latest manifestation of fiscal austerity, or are the Government’s proposals for the FITs regime part of a coherent renewables / energy policy?

There are a number of points on which the proposals are notably consistent with other statements of the present Government’s policy on renewables.  The gentlest decrease in solar PV generation tariffs (a mere 62%) has been applied to the 250-1000kW band which most obviously represents the commercial rooftop solar sector that DECC has said it wants to see expanding.  The fact that wind generation tariffs have only been abolished for installations above 1.5kW (with proposed tariff reductions of as little as 37% for the smallest wind installations) tends to reinforce the impression that the current Government’s objections to further onshore wind subsidies owe as much to aesthetic as to financial considerations.  There is a general intention that tariffs should be set at a level that encourages “well-sited” installations rather than making viable those that ought not to be viable.

As noted above, the UK nearly didn’t have a FIT regime.  Political pressure ensured that it did.  It may be that calculations of what was and was not politically feasible resulted in the regime being unreformed for too long after its 2012 review.  A number of the ideas in the Consultation feel as if they could have been more usefully deployed if they had been proposed much earlier, but may now come too late, and/or in too Draconian a form, to save the regime as far as any significant quantity of new installations is concerned.

Whether, in retrospect, the proposals will look like a well marked out path to subsidy-free small-scale renewable generation is hard to assess.  However, it is clear that DECC is determined to avoid a situation in which a large bulge of smaller projects that fail to make the relevant cut-off date for accreditation under the RO flood into the FIT regime instead.  The proposed caps should stop that.

If you would like to discuss any issues arising from this post, please feel free to contact the authors or another member of the London Energy team at Dentons.

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DECC’s latest consultation on Feed-in Tariffs – an Era of “FIT Austerity”?

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

Large scale solar and the Renewables Obligation: 9 more months of grace

DECC has confirmed that there will be a further year-long grace period for large scale solar PV projects which fail to be accredited under the Renewables Obligation (RO) by 31 March 2015.  In addition to the previously announced grace period for projects which are considered to have made a “significant financial commitment” before 13 May 2014, there will be a further opportunity for those projects which only fail to be accredited by 31 March 2015 for lack of a grid connection.

DECC’s announcement came in a response to a consultation that ran from 2 to 24 October 2014 and followed on the 13 May 2014 consultation on early closure of the RO to large scale solar PV (see our earlier post).   The key difference from what was proposed in the 2 October consultation document in relation to the proposed grid connection grace period is that it will now run for a full year, like the grace period for “significant financial commitment” projects, rather than just three months – giving those projects that meet the relevant criteria until 31 March 2016 to achieve accreditation.

Alongside the response to consultation, DECC has published a draft of the statutory instrument that it proposes to lay before Parliament in the New Year to amend the existing RO Closure Order.  This makes it possible to see exactly how DECC envisages eligibility for both grace periods working. 

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Large scale solar and the Renewables Obligation: 9 more months of grace

UK electricity interconnectors: all coming together (by about 2020)?

One of the problems faced by the UK in achieving security of electricity supply at an affordable cost is its comparatively low level of interconnection with the electricity networks in other countries.  But recent developments offer some prospect that the UK may become a bit less of a “power island”.

The EU’s goal of a single electricity market has the potential to help national Governments with all three horns of the energy trilemma (how to maintain security and decarbonise whilst keeping energy prices at a reasonable level).  But it cannot be realised without adequate interconnection capacity.  As long ago as 2002, the European Council set EU Member States a target of having electricity interconnections equivalent to at least 10% of their installed production capacity by 2005.  Twelve years on, the UK is only half way to meeting this target.  In May 2014, as part of its work on European energy security, the European Commission proposed an interconnection target of 15% for 2030.  This was adopted by the European Council in its 23 October 2014 conclusions on the EU’s 2030 Climate and Energy Policy Framework.

Meanwhile, as Member States connect increasing amounts of intermittent renewable generating capacity to their networks, leaving them in some cases with total generating capacity that is much greater than the amount of power they can reliably generate at any given moment, the goal of achieving 10% or 15% of total installed generating capacity becomes more challenging (see the statistics and charts below).  While such targets are undoubtedly useful, the optimum proportion of interconnection capacity is not the same for each Member State and is bound to change over time with the evolution of its generating mix and electricity consumption profile.  However, it is not always easy for the market to respond quickly and produce more interconnection capacity where it is most needed given the amounts of capital and the regulatory processes involved.

Achieving an interconnection target of 10% or 15% of installed generating capacity in the UK is particularly challenging.  Even before it began to add significant amounts of renewable generation, the UK had one of the larger generation capacities in the EU, and it is very much more expensive per MW to create connections between the electricity networks of Great Britain and other EU Member States than it is to connect networks between Member States which share a land border.  The costs per km of a subsea cable connection are several times greater than those of an overhead transmission line, and the distances involved in GB interconnectors tend to be larger than those which link the transmission systems of different countries in Continental Europe.

However, if the costs of interconnection are significant, so too are the potential benefits for UK consumers.  In a paper entitled Getting more connected published earlier this year, National Grid estimated that: “each 1GW of new interconnector capacity could reduce Britain’s wholesale power prices up to 1-2%…4-5GW of new links built to mainland Europe could unlock up to £1 billion of benefits to energy consumers per year“.  As the European Commission’s most recent report on energy prices and costs in Europe notes, in some of the countries to which the GB system either is not yet connected or with which it could be much more interconnected, average baseload wholesale electricity prices are up to 40% lower than those in the UK.

So is the potential for new UK interconnection capacity going to be exploited anytime soon?  There are encouraging signs both from a regulatory point of view and in terms of actual projects.

The regulatory treatment of projects is crucial to the development of more interconnection.  In this respect, there have been a number of helpful recent developments for potential UK interconnectors.

  • In August 2014 Ofgem confirmed its intention to implement, with only minor modifications, its previously consulted-on proposals for the regime that will apply to the regulation of near term GB interconnector projects (i.e. those expecting to be commissioned by the end of 2020 and likely to be taking significant investment decisions in 2015).  Ofgem recognises that if the development of new UK interconnection capacity is left to proceed without any form of regulated “consumer underwriting”, it is likely that insufficient new capacity will be built.  It therefore proposes a 25 year regulatory regime of a “cap and floor” on revenues, based on its assessment of the need case and efficient level of costs for projects.  The new regime, building on Ofgem’s approach to the Project Nemo interconnector, aims to combine advantages of both the traditional regulated revenue model and more purely market-based approaches.  Ofgem’s 27 October 2014 consultation on the Caithness Moray transmission project shows how far a regulator’s assessment of efficient costs for a project involving subsea cables can vary from a developer’s estimates.
  • Also in August 2014 the UK Government published a paper entitled Contract for Difference for non-UK Renewable Electricity Projects.  This raises the prospect of Contracts for Difference (CfDs) under the Energy Act 2013 being competed for by and awarded to renewable electricity generating projects outside the UK by 2018.  This is a significant step, given the continuing importance of subsidies for the renewables sector (and coming as it did shortly after the approval by the Court of Justice of EU Member States’ historic tendency not to extend their national renewables support schemes to generators in other Member States – notwithstanding the potential for such restrictions to impede free movement in the single market for electricity).
  • In September 2014, the Government included in a consultation on supplementary design proposals for the Capacity Market established by the Energy Act 2013 an outline of how interconnector owners could participate in future Capacity Market auctions.  This had been promised in the context of obtaining state aid clearance, so as to ensure that the Capacity Market, like similar measures being put in place by other Member States, does not militate against the integration of national markets – clearly a matter of concern to the European Commission.
  • Interconnection is most effective when the interconnector capacity is allocated most efficiently and facilitates the flow of electricity from areas of lower to areas of higher prices (see study on this).  These outcomes should be brought closer by the progress there has been in integrating EU national electricity markets through the Target Model.  In February 2014, the markets in GB and 14 other EU Member States became part of the day-ahead price coupling regime for North-West Europe (and in May 2014 they were joined by Spain and Portugal).  In April 2014, a number of Central European Transmission System Operators, National Regulatory Authorities and Power Exchanges signed an MoU to develop flow-based market coupling, which in time will enable better calculation of the network capacities that are allocated through the price coupling process.
  • Finally, the 2013 EU Regulation on cross-border infrastructure (“projects of common interest” or “PCIs”, which are to be fast-tracked through national consenting processes) should make it easier to get interconnection projects funded and built.

In terms of actual projects, Ofgem’s October 2014 preliminary decision on eligibility of projects to benefit from the cap and floor regime identifies five projects that aim to commission by 2020 and, having come forward in the first cap and floor application window, have been judged sufficiently mature to proceed to the three to six month initial project assessment stage.

The five projects are: FAB Link between GB and France; Greenlink, between GB and the Republic of Ireland; IFA2, between GB and France; NSN, between GB and Norway (recently granted a licence by the Norwegian Government); and Viking Link, between GB and Denmark.

According to Ofgem, these projects, together with Project Nemo and the Channel Tunnel-based ElecLink, could add up to 7.5GW of interconnection – more than doubling existing GB cross-border apacity.  They have a number of points in common.   A number of these projects feature in the ENTSO-E Ten Year Network Development Plan and the European Commission’s list of PCIs.  Most of them involve the Transmission System Operators of one or both of the countries they would run between or companies affiliated to them.  Establishing links between GB consumers and renewable generation outside GB is an important part of the rationale for many of them (the FAB Link project even involves plans for up to 300MW of electricity generated from the tides around Alderney). Recent publicity for the TuNur project to export large amounts of solar-generated electricity from North Africa to Europe, including the UK, shows the scale of the possibilities in this area.

It now remains to be seen whether the further development of the Government’s proposals on non-UK renewable and interconnected capacity – and perhaps more significantly the outcomes of the first CfD and Capacity Market auctions (which will not be open to interconnected / non-UK capacity) – will enhance or detract from the business case for these projects.

 

Illustrative statistics and charts (drawn from EU Energy in Figures: Statistical Pocketbook for 2014 and other European Commission and ENTSO-E publications)

1. Ratio of available cross-border electricity interconnector capacities compared to domestic installed power generation capacities

Source: Ten Year Electricity Network Development Plan, 2012

Source: Ten Year Electricity Network Development Plan, 2012

2. Electricity generation across EU Member States

Table 4_2

3. EU Member States’ power generation supluses and deficits compared to gross inland consumption in Q1 2013 and 2014

figure 2

4. Electricity consumption across EU Member States in Q1 2013 and 2014

consumption

5. EU Member States’ renewable and non-renewable generation

Table 6

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UK electricity interconnectors: all coming together (by about 2020)?

Early closure of RO to >5MW solar PV projects confirmed

Following a consultation that ran from 13 May to 7 July 2014, the UK Government has confirmed its intention that, as a general rule, funding under the Renewables Obligation will not be available to larger scale (>5MW solar) PV projects after 31 March 2015.

There will be a “grace period” of a year for projects which were, in effect, in a position to begin development before 13 May 2014.  Perhaps more usefully for projects which may struggle to meet the requirements for RO accreditation before 31 March 2015, further consultation is taking place on a proposal to protect the position of those projects which only fail to meet the 31 March 2015 cut-off date for commissioning because their electricity network operator has not met a pre-31 March 2015 estimated connection date.

Background

For most technologies, the Renewables Obligation will close on 31 March 2017.  After that date, smaller projects will have to rely on the Feed-in Tariffs regime and larger projects must compete for Contracts for Difference (CfDs) under Electricity Market Reform.  In March 2014, the Government set out its overall approach to the two and a half year  transition period when both the RO and CfD regimes are open to new projects: developers are able to choose between the two schemes (subject to certain qualifications). But subsequently DECC has become increasingly concerned that the rapid growth of the UK solar industry, supported by the “demand-led” RO, will breach the Levy Control Framework (LCF) limits on the overall amount of money that the Treasury will permit to be spent on renewable energy subsidies.  In its May 2014 consultation, DECC estimated that large-scale solar PV deployment under the RO could reach “more than 5GW by 2017”; in the response to that consultation, DECC’s “updated assessment” found that “in the absence of intervention”, up to 10GW of solar PV could deploy within this period, costing some £400m more than was allowed for in the EMR Delivery Plan and exceeding the LCF cap.

Proposals and policy decisions

The table below summarises the Government’s main proposals on RO closure for solar PV in the May consultation and the policy decisions announced in the response to consultation.

table-1

DECC has not been persuaded to change the cut-off date or open up the grace period to a wider group of projects.  Responding to “the main criticism…that any projects that can meet the grace period…requirements are unlikely to need the grace period because they will already be sufficiently advanced to secure connection by 31 March 2015”, DECC states that “the grace period will have fulfilled its purpose if it protects eligible projects that subsequently encounter unexpected events which delay their completion beyond the end of March 2015.  However, DECC very clearly has taken on board the industry’s practical objections around the evidence to be provided by those that are eligible for the grace period and has accommodated its evidential requirements to the realities of the industry.

Further consultation

In response to comments from consultees that early closure of the RO to large-scale solar would create a “cliff-edge” effect for some projects, DECC has put out a further consultation (closing on 24 October 2014) on the proposal that there should be a separate 3 month grace period (until 30 June 2015) for projects which are prevented from meeting the 31 March 2015 deadline only because they are not connected to the grid by that date.

The proposal is that such projects would have to include in their RO application:

  • a grid connection offer and acceptance and a letter from the network operator estimating or setting a date for connection of no later to 31 March 2015 (the estimated connection date);
  • a declaration by the developer that to the best of its knowledge, the project would have been commissioned by 31 March 2015 if the connection had been made by the estimated connection date; and
  • a letter from the network operator confirming that in its opinion, the failure to make the grid connection before the estimated connection date was not due to any failure on the part of the developer.

The first of these proposed requirements is open to the same sorts of objections that were made by the industry against the proposed requirement for a letter from the network operator that formed part of the May 2014 proposals.  However, DECC insists that past experience on banding review grace periods suggests that the difficulties associated with it are “not insurmountable”, and the response to consultation is careful to note that the requirement has been removed from the final policy decision on the May proposals because a letter from the network operator was considered unnecessary in that context, rather than that it would be too difficult to obtain.

What next?

DECC intends to implement the policy decisions described above in relation to RO closure through an amendment to the Renewables Obligation Closure Order 2014, to take effect on 1 April 2015.

DECC is evidently determined to do whatever it has to in order to mitigate the risk that the growth in large-scale solar PV will lead to a breach in the Levy Control Framework limits. It wants the sector to switch to the CfD regime, where the auction-based allocation process will drive down the costs of subsidy, acknowledging that the greater complexity of the CfD regime will favour the larger players in the industry.

The deadline for applications for the first CfD round is now 30 October 2014, and in recent publications both DECC and National Grid (as EMR Delivery Body) have been doing their best to make the regime user-friendly.  The table below suggests which groups of developers may need to consider making a CfD application.  If onshore wind developers (with whom solar projects must compete) are likely to avoid bidding for CfDs in the first auction since they  have until 31 March 2017 to achieve RO accreditation, it may be that solar projects stand a reasonable chance of success of being allocated CfDs later this year.

table-2

At present, for those who miss out on both the RO and a CfD from the first allocation round, the next opportunity would be a CfD allocation round in Autumn 2015.  DECC has given some indications that it is sympathetic to the proposition that the rapid development cycle of solar projects means that there ought to be solar CfD allocations every 6 months rather than every year, as for other technologies, but it also points out that more frequent auctions would not mean any increase in the overall budget.  And since 2015 is a General Election year, no promises of a further allocation round for solar can be made at present.

 

 

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Early closure of RO to >5MW solar PV projects confirmed

Why won’t UK shale be subject to the renewable energy community stake requirement?

As noted in our recent post on Shared Ownership, the UK Department for Energy and Climate Change (DECC) has published its Community Energy Strategy (Strategy) which anticipates that by 2015, it will be normal for new renewable energy developments to offer project stakes to local communities (and which could be enforced by an enabling power in the draft Infrastructure Bill 2014). At a recent renewable energy industry event, it was asked why shale developers are not similarly targeted by the Strategy to offer stakes to local communities?

Analogy to a new tax

In short, because it would likely be argued to be unfair. Shale developers have already paid and committed to fulfil minimum work obligations onshore under a petroleum, exploration and development licence, in order to have the right to explore for and later extract hydrocarbons from the sub-surface (and off the Crown). Any later requirement to give a royalty or equity interest to a local community, could be regarded as being analogous perhaps to an unexpected new tax. In addition, having to obtain DECC consent or adding say a community interest company (CIC) vehicle to a hydrocarbon licence, could be administratively cumbersome.

Misalignment of local opposition

That said, renewable developers may argue that buying or leasing surface land rights for renewable energy generation, and later having to give a stake to a local community, is little different philosophically. However, the current Strategy proposal is perhaps designed to address the apparent misalignment between national poll results (which are reported to suggest a majority are in favour of renewable energy); and local communities (who often resist wind and solar developments in their own localities). Such opposition is often then said to be reflected in local authority planning application refusals, which in turn reduces renewable energy development and impacts national carbon targets.

Reduced justification for compensation

By comparison, opposition to shale developments, is perhaps expected to be less driven by local planning or land-use opposition, as opposed to broader ideological and environmental concerns, which may not be as effectively addressed with active community participation – few well-heads will have the “wow factor” of a windmill. In addition, once DECC’s current consultation on granting horizontal drilling access rights (to ease shale and geothermal developments) runs its course (see our recent post Compulsory access rights “in the national interest”), then developers will possibly have less need for community alignment on specifically land-use environmental concerns. Indeed, the relative thickness of exploitable UK shale resources means that relatively few well-pad sites on the surface could be used to access large areas of sub-surface resource horizontally, causing little environmental impact (truck movements apart). This may reduce any justification for giving local communities a substantive share of the profits.

Conclusion: proactivity in hindsight

It is also important to note that the nascent shale industry, to the extent represented by the recently invigorated UK Onshore Operator’s Group (UKOOG), has perhaps already drawn some of the sting of potential community engagement regulation, by pro-actively suggesting well-pad and production payments (albeit modest in amount) for local communities. Whilst the renewables industry is more mature, numerous and with diverse interests, it may be noted that a sophisticated regulator is rarely motivated to act, except where market failure is perceived. Therefore, if the shale industry were to fail to implement the recommendations volunteered by the UKOOG, DECC may be tempted to re-assess the absence of unconventional developments from the Strategy and Infrastructure Bill’s proposals for community participation. In hindsight, now that DECC has seen a need to prompt the renewable energy industry into volunteering community participation, it appears less likely that community payments divorced from equity stakes or project profitability alone, will meet the regulator’s perception of community needs.

For further analysis on the potential application of UK and other international examples for tailoring legislation, farm-in and joint operating agreements in developing unconventional basins, please see our Shale Guide, recently presented and discussed over two days in Washington DC at a World Bank and OGEL symposium, aggregating the learning of representatives covering 18 countries.

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Why won’t UK shale be subject to the renewable energy community stake requirement?

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

Winners and losers: Government announces strike prices for new renewables projects

The Department of Energy and Climate Change (“DECC”) today published final strike prices representing the level of income in £/MWh hour that new renewable generating plant will be guaranteed to achieve under Electricity Market Reform (“EMR”) Contracts for Difference (“CfDs”).  We compare the final prices with the draft strike prices consulted on in July for selected technologies below.

winnersandlosers1table

Technologies with higher final strike prices included Biomass with CHP (up £5 to £125 for all five years), Anaerobic Digestion and Geothermal.  Landfill Gas, Sewage Gas and Hydro all ended up with lower final strike prices.  The prices proposed for Biomass Conversions, Wave and Tidal Stream projects have not changed, and those for Offshore Wind have only changed for 2018/19 (down £5 to £135).

It is hard to avoid the conclusion that some of the changes are intended to have a political resonance. Reduced subsidies for onshore wind and solar PV should mean fewer locally unpopular wind and solar farms, at least in areas where the weather makes the business case highly sensitive to subsidy levels.

But whether you think you are a winner or a loser, the strike price story is not over yet.  DECC will have a lot of flexibility in terms of writing – and re-writing – the rules for each CfD allocation round, and today’s publication includes strong hints that some or all of these “administratively set” strike prices could be swept away and replaced by a system of competitive bidding sooner rather than later, perhaps as part of the price for persuading the European Commission to approve the state aid aspects of EMR.

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Winners and losers: Government announces strike prices for new renewables projects