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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?

Thoughts on the death of DECC

Over the course of 13 and 14 July 2016, UK’s new Prime Minister, Theresa May, appointed the Secretaries of State who will lead the various Departments of Government.  By the end of the process, which was precipitated by the UK’s referendum vote to leave the EU, the Cabinet had gained two new Secretaries of State (for “Exiting the European Union” and “International Trade”).  At the same time, the position of Secretary of State for Energy and Climate Change had been abolished, along with the Department which its holder led (DECC).  To anyone with a professional interest in energy and climate change policy, this will likely have felt like a backward step.  If nothing else, as pointed out by Angus MacNeill, Chair of the House of Commons Energy and Climate Change Committee, it raises some important questions which will need to be answered quickly.

It is, of course, far too early to judge the new Government’s approach to any issue.  After a period of several months in which relatively little in the way of major policy emerged from DECC (no doubt partly because of pre-referendum stasis), there will be a temptation to fall on anything that the Ministers newly appointed to the Department of Business, Energy and Industrial Strategy (BEIS) say in the next few weeks for clues about the future direction of energy and climate change policy – and possibly over-interpret them.  The new regime should be judged on its record rather than its name.

In practical terms, it was probably not feasible for an incoming Prime Minister to create two new Secretary of State posts without losing at least one existing one to compensate – and the former Department for Business, Innovation and Skills has lost a significant chunk of its previous responsibilities (higher education, and, presumably, at least some of international trade), so may have needed some additional bulk.  Historically, the energy portfolio has had its own Department within Government for over 50 of the last 100 years (variously as the Ministry of Power, 1942-1969; the Department of Energy, 1974-1992; and DECC, 2008-2016).  Otherwise (apart from a very brief period in the Ministry of Technology), it has been in the Board of Trade and its successors, the Department of Trade and Industry, the Department of Business, Energy and Regulatory Reform – and now BEIS.  If one looks to international comparisons, practice varies: Germany has a Ministry of Economic Affairs and Energy; Denmark has a Ministry of Energy, Utilities and Climate; in Italy, energy is a matter for the Ministry of Economic Development.  At EU level of course, DG Energy is very much a Directorate-General in its own right: energy has been a key policy area for the EU and its precursors and it will be an important element in both Brexit negotiations and international discussions about post-Brexit trade arrangements with the EU and others.

One thing that distinguishes the new configuration from those other occasions when “energy” has not had its own UK Department, is that on this occasion it does at least feature in the name of the Department that is responsible for it.  It will undoubtedly form a significant part of BEIS’s business.  It is true that “climate change” has lost some profile, but it is also noticeable, if one looks at the DECC organogram, that very few DECC teams could be said to have had an exclusively climate change focus (in any case, when DECC was originally created, only those Defra staff working on climate change mitigation joined the new Department: those working on climate change adaptation remained behind).  Arguably one of the achievements of DECC (and the period of policy formation that immediately preceded it) was to make climate change considerations part of the mainstream of energy policy-making.  The optimistic view would be that with the Climate Change Act 2008 – and its system of carbon budgets, based on work by the independent experts of the Committee on Climate Change (CCC) – well entrenched, there is less need for the symbolism inherent in the name of DECC.  One might also add, more cynically, that there was more than one occasion when having responsibility for climate change policy did not stop DECC Ministers from choosing the “less green” option.

But on a more positive note, there are clearly potential advantages in having “business”, “energy” and “industrial strategy” in the same Department.  As the CCC’s Report on the Fifth Carbon Budget made clear, if we are to achieve the kind of reductions in carbon emissions that we need in order to meet the overall goals of the Climate Change Act, not to mention contributing a fair share to the achievement of the aims of the CoP21 Paris Agreement of December 2015, we will need to go a long way beyond the task of decarbonising the electricity generation sector (admittedly still work-in-progress though that is).  There is a lot to be done in relation to heat and transport, for example, and the challenges are formidable.  Some of this is very much to do with industrial energy use, and having one Department, rather than two, focusing on this area could well make a positive difference (given the inevitable friction that exists between all public sector bodies with shared interests).  Maybe it is even not too much to hope, in this context, that the new Government may revisit the decision to abandon large-scale sponsorship of carbon capture and storage, which is thought by many to have more to offer in a wider industrial context than it necessarily does purely in the electricity generation sector.  At the same time, a Secretary of State for BEIS (Greg Clark) who has come from the Department of Communities and Local Government may be an asset at a time when it is also becoming clear that some aspects of the development of new energy infrastructure are best considered locally, at least within cities.  And “industrial strategy” – unclear as yet though it is what this will involve – could also have a mutually beneficial intra-Departmental relationship with “energy”.  Finally, given that it is only seven years since DECC was partly carved out of one of BEIS’s predecessors, it is to be hoped that this change in the machinery of Government can be accomplished without distracting ex-DECC management too much from the policy agenda (now, of course, supplemented by Brexit).

In the post-Brexit world, nothing is necessarily what it seems.  Any or all of the above speculation may be naïve or misguided.  The new Department should be watched carefully, but today, objectively and at a policy level, it is far too early to say whether (or how much) we should mourn the passing of DECC.

 

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Thoughts on the death of DECC

Energy Brexit: initial thoughts

In the energy sector, as elsewhere, it is far too early to give any definitive view on the effects of the UK electorate’s vote to leave the EU, or to offer a comprehensive analysis of the merits of the options now facing the UK Government. Here we offer some initial thoughts on these subjects.  Further posts will follow in the coming weeks, months and years.  No doubt some of what we say here and subsequently will turn out in retrospect to have been wide of the mark, but this is an occupational hazard of providing current commentary in a fast moving area.

This is a rather long post. We hope that those that follow will be shorter.

  • We begin by looking briefly at the relationship between EU and UK energy policy to date.
  • We then consider the EEA as a possible model for developing that relationship post Brexit.
  • After glancing at the anomalous position of nuclear power, we move on to consider how the UK could reinvent parts of its energy policy if it were free of EU / EEA law constraints.

Overall, our conclusions are not surprising.

  • EU and UK energy policies are in many ways closely aligned.  Yet EU membership undoubtedly constrains UK policy choices in a way that some find detrimental to UK business and/or consumer interests.
  • Most of those constraints would remain if the UK were to leave the EU but remain a member of the European Economic Area (EEA).  But even this limited change would bring with it a need, or at least the opportunity, to re-evaluate quite a large number of (in some cases fairly significant) pieces of law and regulation.
  • If the UK were to seek its fortune outside both the EU and the EEA, Government would be able, at least from a legal point of view, to introduce some very radical changes to current energy policies – and in some cases it might well be tempted to do so (although it would still face some international law constraints and would no doubt need to factor in the effect of doing so on the terms that could be negotiated with other states and the tariffs that might be imposed as a consequence).
  • There will be no substitute, as energy Brexit unfolds, for keeping a close eye on what is proposed in relation to each policy area (even if it is not presented directly as a response to Brexit).  Even if “this country has had enough of experts”, Government will need clear advice from the energy industry more than ever over the next few years.

Putting things in perspective

This Blog will focus on how Brexit affects energy law and policy. We recognise that for many with interests in the UK energy sector, the most immediate concerns may well be about other aspects of Brexit: for example, how it affects their willingness to invest in Sterling assets; whether there will be positive adjustments to the UK’s tax regime; how it could affect the employment status of their non-British workers; or how the post-referendum ferment will simply delay key Government and business decisions.  We are happy to discuss any of those issues with you, but for now, an analysis of Brexit in areas of law and policy specific to the energy sector seems as good a place as any to start to appreciate the complexities opened up by the result of the 23 June 2016 referendum.

Common ground and policy continuity?

A few days after the referendum, Amber Rudd, then Secretary of State for Energy and Climate Change, began a speech by saying: “To be clear, Britain will leave the EU”, and then went on to itemise at some length why this should not mean any big shifts in UK energy policy.  As she put it: “the challenges [securing our energy supply, keeping bills low and building a low carbon energy infrastructure] remain the same.  Our commitment also remains the same”.

It is not hard to find examples of the fundamental objectives of EU and UK policy being aligned.

  • The UK has been a leading advocate since the 1980s of the kind of liberalisation of electricity and gas markets that is now fundamental to the EU’s internal energy market rules.
  • EU and UK policy has favoured open and transparent markets in which free competition is promoted as a way of delivering lower prices and other benefits to consumers.
  • Both the EU and UK have sought to control the adverse environmental impacts of energy industry activities.  More recently, the threat of dangerous climate change has given added impetus to efforts to promote decarbonisation, renewables and energy efficiency.
  • In practical terms, the UK has been the most open of EU markets to the ownership of energy sector assets by foreign companies (although the most notable cases have involved acquisition rather than simply EU companies relying on freedom of establishment).
  • The UK can claim to have been promoting electricity generation from renewable sources for some time before the EU had an effective renewables policy.
  • The UK, having adopted the first national scheme of “legally binding” greenhouse gas emissions targets in the Climate Change Act 2008, played a leading role in developing the EU’s position on the CoP21 agreement reached in Paris in December 2015.

The first tangible indication of post-Brexit policy continuity came with the Government’s announcement on 30 June 2016 that it would implement the independent Committee on Climate Change’s recommendation for the level of the Fifth Carbon Budget, covering the period 2028-2032.  (It would perhaps be uncharitable, in the circumstances, to suggest that on a strict view of the Climate Change Act 2008, the relevant Order should have been debated by Parliament and made by 30 June 2016, and not simply laid before Parliament for approval by that date.)

Sources of irritation

Broad principles are one thing and the detail of regulation is another. There are plenty of examples of tension between EU energy sector policy and regulation and UK preferences.  We are not aware of any poll data on how many of those who voted to leave the EU had energy policy on their minds, but there have certainly been times when EU regulation has not developed as the UK Government would have wished.  At other times, the existence of EU law requirements of one kind or another as a constraint on freedom of action by the UK authorities has given some ammunition to those who argue that as it is a national Government’s function to “keep the lights on” (at a reasonable price) and choose the fuel mix, the EU’s energy policies have impermissibly eroded an aspect of UK sovereignty.

  • The UK was a strong proponent of the enlargement of the EU into Central and Eastern Europe, but the accession to the EU of countries such as Poland may well have helped to ensure that the EU Emissions Trading Scheme (EU ETS) has never set as tight a cap on emissions, and therefore as high a price on CO2 emissions, as the UK would like in order to drive decarbonisation of the power sector and industrial energy use.
  • Various EU rules on environmental, state aid, renewables and single market matters can arguably be blamed for fatally increasing the power costs of UK energy intensive industries to a point where the UK has hardly any steel or aluminium producers left.
  • EU Directives on industrial (non-CO2) pollution have driven a cycle of closures of coal-fired generating stations which some would see as having prematurely diminished the UK’s security of energy supply and limited its ability to benefit from cheap US coal prices.
  • Opposition to the granting of planning permission for onshore wind farms in many parts of the UK (or at least England and Wales) was probably materially intensified by developers arguing (supported by Labour Government policy) that planning authorities were under a duty to grant permission so as to facilitate the achievement of Renewables Directive targets.
  • Since the UK (unlike Germany, for instance) has no domestic PV manufacturing interests that it wishes to protect, it would prefer not to pursue the current EU policy of imposing a “minimum import price” on Chinese solar panels (thus helping the UK solar industry to come to terms more quickly with the Government’s decision to curtail subsidies to it).
  • Generally, as the body of EU energy regulation has grown in strength and reach, and as UK Government energy policy has involved increasing amounts of intervention in the market (for example so as to promote low carbon generation), EU law has become a significant constraint on how the UK Government achieves its objectives, even when those objectives are consistent with EU objectives.
  • The tension between EU and UK policies can be seen in the case of Capacity Markets.  The European Commission, which has no voters worried about “the lights going out” to answer to, sees these as essentially unwarranted interferences with market mechanisms which threaten artificially to partition the EU single market for electricity.  DG Competition is reviewing Capacity Markets in a number of EU Member States (not including the UK, whose regime it has approved under state aid rules already).  It is ironic that the Commission’s work at several points highlights the UK’s approach as a model of good practice, when many in the UK consider that its Capacity Market has failed in some of its primary objectives, and partly blame decisions taken to secure clearance from the Commission for the regime’s defects.
  • There is also a lingering suspicion that the UK sometimes makes matters worse for itself by taking a more conscientious approach to the implementation of EU law requirements (even those it does not entirely support) than some other Member States.

No doubt the UK is not the only Member State dissatisfied with aspects of EU energy policy and regulation. But for now, no other EU Member State has set itself on the course of withdrawal from the EU.

It is unlikely that energy policy will determine the UK Government’s Brexit implementation strategy. However, focusing just on this one area, if one assumes that the UK will not radically change the overall direction of its energy policies and will remain committed to tackling all three challenges of the familiar security-decarbonisation-affordability trilemma referred to by Amber Rudd, how might the UK Government and others seek to maximise the opportunities opened up by Brexit?

Back to the future?

We must begin by considering the “EEA option(s)” – putting to one side, for present purposes, the question of whether a way can be found to preserve existing free trade arrangements with the EU without continuing to allow all EEA nationals their current rights of free movement into the UK.

In 1972 the UK left the European Free Trade Association (EFTA) to join the European Economic Community, forerunner of the EU.  Subsequently, the remaining members of EFTA entered into bilateral trade agreements with the EU, many joining the EU.  The European Economic Area (EEA) was formed by an agreement concluded in 1993 between the European Community (not yet officially the EU), its Member States, and three of the four remaining EFTA states (Norway, Iceland, Liechtenstein – Switzerland remained outside the EEA).  What would it mean for the UK to leave the EU and become a party to the EEA as an EFTA state once more?

First, consider the other members of the club that the UK would be (re-)joining.

  • In 2015, the UK had a population of 65 million and a nominal GDP of $2,849 billion.  The four current EFTA states had a combined population of less than 14 million (more than half of which is made up by non-EEA Switzerland) and GDP of just over $1,000 billion (of which, again, Switzerland accounted for more than half).
  • In 1992, Switzerland voted by a 0.3% margin not to join the EEA in 1992 and Norway voted by a 2.8% margin not to join the EU.  Iceland dropped its bid to join the EU in 2015: fisheries policy (not covered by the EEA Agreement) was a sticking point, not for the first time.
  • Norway is the EU’s second largest supplier of both oil and natural gas.  It accounts for almost 30% of EU gas imports, as compared with Russia’s 39%.  But virtually all of its electricity is generated from renewable sources (overwhelmingly hydropower).
  • Market structures in the energy sectors of EFTA States are somewhat different from those in the UK.  Norway and Iceland are both characterised by a degree of state ownership than has not been familiar in the UK for many years.  Switzerland’s power sector is highly fragmented.
  • Both Norway and Iceland could export considerable amounts of power via interconnectors.  For potential importers such as the UK, this is attractive because, unusually, most of these countries’ renewable power output, being hydropower or geothermal, is “despatchable” on demand rather than being a “variable” source of supply like wind or solar power.
  • Switzerland has electricity interconnection capacity approximately equal to its peak power demand.  It exports and imports power equivalent to more than half its total consumption to and from its EU Member State neighbours.  The UK is making progress on interconnection, but is still some way from meeting a 2005 EU target of 10% of installed capacity.
  • Norway, although not subject to the EU legislation that underpins the EU’s electricity cross-border “market coupling” regime, nevertheless manages to participate in it.  (Note that Switzerland is reported to have been excluded from the same mechanism after its referendum vote against “mass migration” – i.e. free movement of people.)

Next, consider how the EEA works legally.

  • The EEA Agreement sets out the basic “free movement” rules as they were in the EC Treaty in 1993 so as to create an extended free trade area.  This does not extend to all the goods covered by the EU single market, and it only applies to products originating in the EEA.  Most importantly, it does not include the provisions which create the EU customs union, so that the EFTA states are not obliged to maintain the same tariffs in respect of products from third countries as the EU does under its “common commercial policy”.
  • If the UK were within the EEA, other EEA states would not be able to discriminate against energy products which the UK exported, provided that they “originated” in the UK.  That would cover, for example, power generated in the UK and exported over an interconnector. The implications of the rules on origination for trading in oil and gas extracted in non-EEA countries but entering the EEA in the UK would need to be considered (along with applicable WTO rules) if the EU were to raise its tariffs for those products from its current level of zero.
  • Most EU legislation is comprised of Directives and Regulations.  These are proposed by the European Commission, negotiated by representatives of the EU Member States (the European Council), with amendments typically being proposed in parallel by the European Parliament and a political compromise being reached between Council, Parliament and Commission on a final text in the so-called “trilogue” procedure.   Once they have been adopted in this way, Regulations in principle do not require national implementing measures, because they are directly applicable throughout the EU, whereas Directives generally require Member States to enact specific legislation to implement them.
  • EEA law is meant to correspond to EU law within the scope of the EEA Agreement.  All EEA law originates from the EU legislative process described above and the EFTA States only have the right to be consulted on its terms – they have no representation in the European Council or Parliament, and they have no vote on the final text.
  • However, EU legislation does not have any effect in the EFTA States just by being adopted at EU level.  Once an EU Directive or Regulation has been adopted, it must first be determined whether it falls within the scope of the EEA Agreement.  The EFTA Secretariat leads this work, which is not always straightforward.  For example, the EEA Agreement essentially takes (parts of) the EC Treaty as it was after the Single European Act but before the Maastricht, Nice Amsterdam or Lisbon Treaties.  As such, it does not include a provision equivalent to Article 194 TFEU, which has formed the legislative base for a number of measures in the energy sector.  This immediately makes it harder to determine whether any Article 194-based measure is within EEA scope.
  • If a measure is in scope, Article 102 of the EEA Agreement states that it is to be adopted by the EEA Joint Committee “to guarantee the legal security and homogeneity of the EEA”.  In most cases, measures are adopted in their entirety with no substantive amendments.  However, amendments are possible if it is agreed that they do not affect “the good functioning” of the EEA Agreement.  Adoption, and any amendment, is recorded by making entries in the various topic-based Annexes to the EEA Agreement.  Energy is dealt with in Annex IV (which can be compared with the European Commission’s list of measures covered by its DG Energy), but Annex XX (Environment) and others are also relevant.  There is a helpful online facility for tracking what point a given piece of EU legislation has reached in the process of EEA adoption – or otherwise.
  • The EEA Joint Committee takes decisions “by agreement between the [EU], on the one hand, and the EFTA States speaking with one voice, on the other”.  Article 102 is in effect an “agreement to agree”.  Absent such agreement, it allows the relevant part of the relevant Annex to the EEA Agreement to be “suspended” – so far, apparently, an unused mechanism.
  • In order for an adopted measure to take effect within the laws of all the individual EFTA States, national implementing legislation is required.  Note that this is the case regardless of whether the original EU measure is a Directive or a Regulation, since Norway and Iceland apparently could not accept, as a matter of constitutional law, a process by which Regulations automatically take effect in their jurisdictions without national implementation (and the Norwegian and Icelandic legislatures do not appear to have been able to find a solution to this problem along the lines of the UK’s s.2(1) European Communities Act 1972).
  • Compliance with EEA laws that are brought into force in this way is enforced both by national courts in EFTA States and by the EFTA Surveillance Authority (ESA), whose position is analogous to that of the European Commission in that respect.  Amongst other things, the ESA performs the function of determining whether cases of state aid are compatible with the EEA Agreement just as the Commission does in respect of EU law.
  • Finally, the EFTA Court is there to hear cases brought by EFTA States against each other or by or against the ESA as regards the application of the EEA Agreement.  As in the case of EU law, failure by a Member State to implement EEA requirements can result in infringement proceedings before the Court.
  • Although the EEA legislative process is somewhat slower than that of the EU (see below), both the ESA and the EFTA Court tend to process cases more quickly than their EU counterparts (but then, so far, they have also had notably lighter workloads).

The EEA Agreement in action

The way in which some familiar pieces of EU legislation have been processed for the purposes of the EEA Agreement provides some interesting examples of how the EEA works in practice.

It can take a long time to adopt some measures.

  • The EU adopted its “Third Package” of electricity and gas market liberalisation measures in 2009 and they came into force in the EU in 2011: the process of EEA adoption has not progressed beyond submission of a draft decision to the European Commission (in 2013).
  • The REMIT Regulation on energy market transparency, adopted and in force in the EU since 2011 is still “under scrutiny” by EFTA.  Neither of the general Directives on energy efficiency, 2006/32/EC and 2012/27/EU, yet appears close to being adopted.
  • The EU Emissions Trading Scheme Directive of 2003 and the Industrial Emissions Directive of 2010 had to wait until 2007 and 2015 respectively for adoption into the EEA Agreement.  However, in the latter case, the process could at least package the adoption of the Directive itself with that of a large number of implementing measures taken under it at EU level.

Other EU energy measures have been considered to fall outside the scope of the EEA.

  • The Directives on security of gas or oil supply, such as the Oil Stocking Directive, 2009/119/EC do not form part of the EEA Agreement.
  • Since tax harmonisation falls outside the scope of the EEA Agreement, the Energy Products Taxation Directive has not been adopted by the EFTA States.
  • The EU’s continuing sanctions measures against Iran (those adopted “in view of the human rights situation in Iran, support for terrorism and other grounds”), like other EU Common Foreign and Security Policy measures, are not part of EEA law.

How flexible is the application of EU law in the EEA?

  • In some cases, adoption of EU measures has included significant derogations, such as for Iceland in relation to the energy performance of buildings and geothermal co-generation, and for Liechtenstein in relation to rules on renewable energy.  Derogations and other amendments involve a more protracted process of approval on the EU side, since they are a matter for the Council and not just for the Commission.
  • There have been a number of ESA proceedings in respect of alleged state aid of various kinds.  As is the case with European Commission decisions, these sometimes exhibit rigorous application of economic principles, and sometimes, to a cynical eye, could be thought to carry a slight hint of political expediency.

How would the UK fit in to the EEA / EFTA energy sector?

If the UK were to become an EFTA / EEA State tomorrow, it would find itself, by virtue of its generally fairly scrupulous past compliance with its obligations as an EU Member State, considerably ahead of its EFTA peers in implementing EEA law.

As in every other area of policy, legislating for Brexit at UK level involves, at least in theory, a large number of choices. Any domestic legislation that implements a Directive could in principle either be left as it is, amended or repealed.  The Government would also have to decide whether to legislate, if only on a transitional basis, to preserve (with or without amendment) the application of each EU Regulation that currently has effect in the UK without any implementing domestic legislation.

In some cases (such as the Regulations which impose the minimum import price for Chinese solar panels in the UK), allowing such Regulations to cease to have effect on Brexit would be an easy choice. In other cases (for example REMIT, or the various Regulations made under the Energy-using Products Directive that impose labelling requirements on electrical goods based on their energy efficiency), there could be a strong case for preserving their effect as a matter of domestic law even as they ceased to apply as a matter of EU law.

But for a Government of Ministers who have long harboured ambitions of doing more to “get rid of red tape”, Brexit is likely to be too good an opportunity to pass up. In so many previous attempts to shrink the statute book, Ministers have had to accept – however reluctantly in some cases – that measures which implemented EU law were untouchable.  This time, there will be pressure to get rid of some of those.  In each case where a straight repeal is contemplated, the consequences of having a regulatory vacuum in the relevant area should be carefully considered and the views of relevant stakeholders taken into account.  Business may need to be alert to what is proposed and ready to engage fully at short notice whenever this process takes place – which could either be in parallel with Brexit negotiations or after they are concluded.  It would make sense for the default position at the start of the UK’s EU-non membership to be one in which the effect of pre-Brexit Directives and Regulation is preserved, at least for an initial transitional period, by a widely-drafted general saving clause in the legislation that undoes s.2(1) of the European Communities Act.

However, if the Government plans to join the EEA as an EFTA State, the task of sifting through decades of EU legislation on this “pick ‘n’ mix” basis should arguably only be a priority in relation to two classes of measure: (i) those that fall outside the scope of the EEA Agreement; and (ii) those that have yet to be adopted at EEA level, to the extent that there would be a clear UK advantage in disapplying them or modifying their effect on a temporary basis.

In the first category (measures outside EEA scope) it is not clear there would be many “quick wins”.

  • One possible example is the suggestion made by Brexit campaigners during the referendum that leaving the EU would enable the Government to abolish VAT on domestic energy bills – a move that would help to offset the increases in electricity bills driven by levies on suppliers to pay for the cost of renewable electricity generation subsidies.
  • In other areas highlighted above as falling outside the scope of the EEA Agreement, it is less clear what would be gained by an immediate move away from the existing EU-based law.  For example, on the whole UK levels of taxation on energy products exceed the minima set out in the Energy Products Taxation Directive – although it may help to have additional room for manoeuvre in reforming business energy taxation.  As regards sanctions against Iran, the factors to be taken into account probably go well beyond energy policy considerations.  It is possible that increased flexibilities from the removal of Oil Stocking Directive requirements would assist the struggling UK refineries sector, but the UK would still remain subject to the parallel requirements of the International Energy Agency’s International Energy Program Agreement.  Refineries might benefit more from the removal of rules implementing the Industrial Emissions Directive (but, as noted above, this is part of the EEA Agreement, and so unlikely to be disapplied if the plan is to join the EEA).

In the second category (candidates for possible temporary disapplication), there may be more scope for opportunistic (de-)regulation, but it is not obvious what the overall strategy would be.

  • Pragmatically, the disapplication of a requirement based on EU law that the UK authorities do not like may be an unnecessary step to take in some cases.  For example, if the UK has left or is about to leave the EU and it looks as if the target set for reducing the energy consumption of public sector buildings in Regulations implementing the Directive 2012/27/EU is not met in 2020, and the Directive has not yet been adopted into the EEA Agreement, would the Government bother to repeal the Regulations, or simply do nothing?  That said, it is too early to be sure that the European Commission will abandon or slow-track any infringement proceedings against the UK for non-implementation of EU law: after all, it might, for example, be part of the arrangements for the UK’s withdrawal that, where the UK was subject to infringement proceedings at the time of leaving the EU – particularly in respect of failure to implement a measure that is also part of the EEA Agreement – those proceedings could be carried on to their conclusion, whether by the EU or EFTA authorities.
  • Similarly with Directives which have been adopted at EU level, and may be required to be implemented before the UK leaves the EU: the UK could take the view that it need not implement them unless and until they are included in the EEA Agreement.  The Medium Combustion Plant Directive, with a transposition date of 19 December 2017, could perhaps safely be included in this category – although there have been indications that in order to prevent undue exploitation of the Capacity Market and other incentives for distributed generation by diesel-fired plant, the Government may actually wish to implement this early.
  • Timing is everything in this context.  EU Regulation 838/2010 imposes a cap of €2.5/MWh on average electricity transmission charges in the UK.  This has been implemented in a provision of National Grid’s Connection and Use of System Code, which previously split the charges 27:73 between generators and suppliers, but now requires suppliers to pay a >73% share and is also the subject of some dispute because of the artificiality of imposing an ex ante Euro-denominated cap on a market that operates in Sterling.  After Brexit, the cap could simply be removed (at least until the Regulation becomes part of the EEA Agreement), but unless the current modification processes move very slowly or the Brexit negotiations move very fast, Ofgem is likely to have to grapple with the issues that it raises sooner than that.  Incidentally, this example illustrates two further points about implementation: (i) that it is sometimes necessary or appropriate to make provision in domestic law to give effect to an EU Regulation; and (ii) that (in the energy sector at least) it is not just the conventional categories of statute law (Orders and Regulations) that need to be combed when reviewing the implementation of EU law: licence conditions, industry codes and other regulatory documents are also part of the picture.

Another important question in this scenario, and one which there is not space to pursue in any depth here, is the impact of Brexit on the EU’s Energy Union project.  Some elements of the proposed Energy Union package may well fall outside the scope of the EEA Agreement, which will no doubt please those who were concerned that “UK business gas supplies could be diverted to households in Europe, under EU crisis plan” (referring to the proposed new principle of “solidarity” in the Commission’s gas security of supply proposals).  Other elements are likely to result in what would amount to a Fourth Package of internal electricity and gas market measures – parts of which the UK might wish to implement before the other EFTA States have  implemented the Third Package, but in the negotiation of which, even if it is completed during the time of the UK’s remaining EU membership, it is hard to see the UK playing a decisive role.  Amongst other things, Energy Unions is likely to confer more power on ACER, the collective body of EU energy regulators.  Yet there is no guarantee that Ofgem would retain its position within this body if the UK were no longer an EU Member State (even if it were an EEA State, unless and until the EEA adopted the new rules).

Confused? You won’t be alone.  But note in passing that one difference between the Second and Third Packages is that only the latter imposes an obligation to roll out smart meters to 80% of customers by 2020 (subject to a positive cost-benefit analysis).  Surely nobody would use the UK leaving the EU, and thus (even if temporarily) not being obliged to follow this requirement as a reason to repeal or not enforce Condition 39.1 of the Standard Licence Conditions of Electricity Supply Licences, which implements it in UK law?

For the avoidance of doubt, if the UK were to join the EEA as an EFTA state, it would remain subject to EU state aid rules, under which state aid which distorts competition is unlawful and liable to be repaid if it is not first cleared by the European Commission / ESA. Many of the UK’s key current energy policies, such as the Capacity Market and Contracts for Difference (CfDs), involve an element of state aid.  State aid clearance for them by the European Commission has been very carefully negotiated, and the need to seek clearance for any significant changes to them has been a constraint on recent policy development.  The ESA has adopted guidelines on state aid for energy and environmental protection that are effectively identical to those of the Commission and it is likely to take a similar view of UK energy policies involving state aid.

In the field of climate change, the UK would no longer be represented by the EU at future UNFCCC conferences. Like the other EFTA States, it would be required to submit its own nationally determined contribution (NDC) towards the achievement of the goals of the CoP21 Paris Agreement, rather than coming under the umbrella of the general EU-wide NDC.  The mechanisms of the Climate Change Act 2008 should provide a sound basis for this.

In short, in the “EEA scenario”, the energy sector is unlikely to see big changes from the UK side as a result of Brexit, but as there may be a sustained effort by Ministers to make the most of even temporary flexibilities, the industry will need both to be alive to the detail of proposed changes and prepared to advise the Government on how the inherent flexibilities described above can best be used in UK policy changes. It is also possible that the arrival of the UK would put some aspects of the way that the EEA operates under strain, both within EFTA itself and in its relations with the EU.  One can imagine the UK sometimes being impatient at the slowness of EEA adoption of some EU law and at other times wanting to push the boundaries of EFTA independence further than the EEA Agreement will easily tolerate.  Inevitably, a recalcitrant UK would be a bigger problem than a recalcitrant Liechtenstein.

Nuclear options?

It is a fair bet that very few voters on 23 June were asking themselves whether a vote to “leave the EU” was meant to suggest to the Government that it should cease to be a party to the Euratom Treaty establishing the European Atomic Energy Community. For what it is worth, in strict legal terms, Brexit should not necessarily imply leaving Euratom, since it, alone of the three original “European Communities” has not been terminated or submerged in the EU.  (It also forms no part of the arrangements between the EU and EFTA States in the EEA Agreement.)

The UK Government may feel that these subtleties are not to be relied on in implementing the “will of the people”.  “Article 50” notices of an intention to withdraw could presumably be served in respect of both Euratom and the EU Treaties (relying on Article 106a Euratom as to Euratom).  Would leaving Euratom be a problem?  The UK had a nuclear industry (arguably a more successful one) before it joined the EEC in 1972, and for many years some of the key international safety, liability and other industry-specific rules were to be found only in the relevant IAEA Convention and not in any European Directive.  Ceasing to be party to Euratom would not affect those.

However, it is hard not to see leaving Euratom as a backward step for a country whose Government has strong nuclear aspirations.   For example, the ability to continue to participate in European nuclear research projects, including on nuclear fusion, is something that the Government would presumably want to safeguard, but beyond the next few years, it would not be guaranteed outside Euratom.  An alternative (if it was felt to be too politically uncomfortable for the UK to stay in Euratom) might be for the UK to suggest to the remaining Euratom States that they make use of Article 206 Euratom to conclude an association agreement with the UK (if that is politically acceptable to all parties) – although this could presumably have the disadvantage of the UK being obliged to follow rules and policies which it would not have input into on an equal footing.

Meanwhile, only time will tell whether French Government support for EDF’s proposed Hinkley Point C nuclear power station will survive Brexit. At this stage it is hard to say that there is any legal reason for the project not to go ahead if the UK is no longer an EU Member State, but Brexit could provide an excuse for either Government if they wanted to terminate the project for other reasons.  EDF’s Chinese partners, may, of course, have a view about that.

The Energy Community

Unlike in some other sectoral areas of law affected by Brexit, energy has the benefit of a ready-made multilateral precedent for the EU and non-EU states to enter into a “single market” agreement which does not (at least explicitly) involve free movement of persons. The Energy Community was formed in 2005 by a treaty between the European Community and a number of Balkan states.  It now comprises the EU, Albania, Bosnia and Herzegovina, Kosovo, the former Yugoslav Republic of Macedonia, Moldova, Montenegro, Serbia and Ukraine.  Georgia is in the process of joining; Armenia, Norway and Turkey are observers.

Some, but not all of these countries are candidates for EU membership and/or have signed up to forms of EU association agreement that commit them to comply with core single market rules, but with only limited provision for the free movement of persons. The Energy Community Treaty and associated Legal Framework commit the Contracting (non-EU) Parties to implement a number of key EU law energy provisions, including the Third Package, security of gas and electricity supply rules, the Renewable Energy Directive, energy efficiency rules, the Oil Stocking Directive, competition and state aid rules and key air pollution and environmental impact assessment rules.  Although supervision of the implementation of Contracting Parties’ obligations is by a Ministerial Council rather than an independent regulatory agency or court, there are sanctions for persistent and serious non-compliance (suspension of Treaty rights).

If energy was our only industry and the UK Government wanted to spare itself the pain of taking decisions on what to do with all current EU energy law applicable in the UK, the Energy Community might be a more attractive club to join than the EEA. But in practice, that option may not be available and other industries may rank higher in terms of political priority in negotiating Brexit.

Freedom and sovereignty

Those who campaigned for Brexit had relatively little to say specifically about energy matters.  But their general pitch to voters was that Brexit would give businesses operating in the UK freedom from unduly burdensome regulation and that it would restore to UK voters, or at least the UK Government, power to determine the UK’s economic and industrial policies.

Given the constraints that EEA membership would impose on the UK Government’s freedom of action in many areas of energy policy, it is necessary to consider what use it could make of the additional freedom or “sovereignty” it could acquire in energy matters if it chose, or was obliged, to forego the ready-made packages of the EEA Agreement and Energy Community for a non-EU law-based model.

Here are some changes that it would probably only be possible to make in a non-EEA UK.  We are not here speculating on whether the Government would be inclined or likely to follow any of these approaches: they are discussed only to illustrate the extent of the potential flexibility that may be available to change current policy.

  • The Government could abandon any further attempt to stimulate private sector investment in new renewable electricity generating capacity, or the uptake of other forms of renewable energy, on the basis that it would no longer have a 2020 target to meet and that it would be better for the UK to wait until renewable technologies have become cheaper by virtue of wider deployment elsewhere in the world.  It could impose a moratorium on all new consents for such projects and suspend or abolish all remaining subsidies for new projects (and it would not have to carry out a Strategic Environmental Assessment before doing so, as EU law would currently require).  Before taking this line, which would help to deliver lower increases in consumer bills over time, the Government would have to weigh carefully: the impact on UK jobs; the potential damage to the UK’s reputation as a place with a stable and supportive regime for energy infrastructure investment (arguably already damaged by the politically driven abolition of onshore wind subsidies and cancellation of support for the commercialization of Carbon Capture and Storage (CCS)); damage to the UK’s reputation as a leader on climate change issues; and the prospect of objectors being able to construct a successful legal challenge to one or more of the steps taken in pursuit of such a policy by arguing that it would make it impossible to keep within one or more of the UK’s carbon budgets, so breaching the Climate Change Act 2008.  (Although note that if a future Government were to wish to repeal that Act, it could do so whether the UK was in or out of the EU / EEA, if it was prepared to live with the resulting  damage to its international reputation.)
  • If the Government was content to carry on subsidising renewable power to some extent, it could – free from EU state aid rules – adopt a less even-handed approach to the allocation of CfDs to new projects.  This may make it easier for the Government to follow what may in any event be its natural inclination to make subsidies available only for offshore wind farms and a few much less established technologies.  Equally, it could choose to subsidise a further coal-to-biomass conversion at Drax even if the Commission’s current state aid scrutiny finds that the existing CfD terms offered to Drax are too generous to be given state aid clearance.  And it may be more able than it is under EU law to give substantial weight to “UK content” in the plans put forward by developers when awarding CfDs.  On the other hand, it could adopt a simpler form of CfD for smaller projects, rather than subjecting 5 MW generating stations to a form of contract much of which was developed for a 3.2 GW nuclear facility.
  • On the other hand, Government could take the view that the low carbon option that really needs subsidising is heat networks, and it could divert all funds notionally earmarked for renewable electricity generation into the provision of heat network infrastructure instead –  subsidising it to a degree that would not be given state aid clearance in order to give a real boost to a market that has been slow to develop for a long time.
  • A different approach would be to focus subsidy entirely on energy storage, with a view to enabling as much variable generating capacity as possible to become, in effect, despatchable.  This is arguably the next frontier for wind and solar power and by boosting demand for storage it could help to reduce its costs in the same way as subsidies have helped to do for solar panels in particular.  That much could possibly be achieved within the EU rules, but it might also help, in such a scenario, to make storage a regulated utility function, and to allow National Grid to invest in storage capacity in a way that EU unbundling rules at present may either not allow, or make it unduly difficult for it to do (if storage is classed as “generation”).
  • It seems unlikely that Brexit would constitute a Qualifying Change in Law (QCiL) for the purposes of the standard terms of CfDs, such that it would entitle the CfD Counterparty to terminate any CfD which has already been entered into solely because of Brexit, because a QCiL must, in essence, have an effect on a particular project, rather than all or most projects, or the whole economy.
  • Government has been disappointed, from an energy security point of view, at the failure of the Capacity Market auction system to produce a clearing price that can serve as the basis for financing large-scale CCGT power stations.  However, in its proposals to change the approach to be taken in the next two auctions, it did not feel able to go as far as to suggest an auction just for CCGT capacity, as this would be incompatible with the existing state aid clearance for the Capacity Market (which is subject to legal challenge).  With no state aid rules to follow, Government could choose to hold a CCGT-only auction.  Other more radical variants on the current rules could include separate auctions for CHP plant (or handicaps in the auction process for non-CHP generating units).
  • Without the constraints of the Industrial Emissions Directive, it might be possible for Government to allow coal-fired plants to follow a gentler path towards closing by 2023/2025 (as its current policy envisages that they will) in which they were allowed to run for a longer period of time without adapting to tighter emissions limits.  However, this might militate against new CCGT development (as well as carbon budget targets).
  • Unconstrained by state aid rules, Government could allow and encourage National Grid to develop an offshore pipeline system to distribute carbon dioxide to potential permanent storage sites under the North Sea, as part of its regulated business, so as to kick-start a CCS industry.
  • Government could escape the flawed EU ETS with its apparently inevitably too-low carbon price and join an emissions trading scheme that delivers a higher carbon price.  There is an increasing number to choose from internationally, from California to China.
  • If Government were to take the view that establishing some form of state-backed entity was the best way to make the decommissioning regime in the North Sea oil and gas industry work effectively, or to ensure that there was a “buyer of last resort” for strategically vital assets whose current owners lack the incentive to carry on running and maintaining them, this is something that would be easier outside the EU / EEA state aid rules.
  • Finally, if the Competition and Market’s Authority’s current proposals for a limited price cap for some domestic energy supply contracts, which were to some extent constrained by EU law, prove inadequate, future regulatory action could go further in this direction.

Depending on which horn of the energy / climate change trilemma you think is most inadequately served by current UK Government policy, you may find any of the above, or other steps that an EU / EEA UK could not take, very attractive. What we would emphasise here, though, is that removing the constraints of EU / EEA law could lead to significantly more volatile energy policy-making in the UK, and greater politicisation of energy regulation.  Note that even Ofgem’s independence is currently underpinned by requirements of EU law, as well as fairly consistent UK tradition.  If the UK were to go down the out-of-EU-and-EEA route, we would suggest that the Government, however radical any departures it decides to take from current energy policies may be, should take steps to ensure that they develop within a stable overall framework, in which business can plan sensibly for the long term.  It may be necessary to impose some more home-grown constraints (like carbon budgets) to make up for the EU ones which would have been shaken off.

A special deal with the EU?

There may be some who dream of the UK reaching a form of accommodation with the EU (going beyond the energy sphere) which is sui generis and somehow the best of all possible worlds.  Leaving aside the question of whether that is politically feasible, it is important to bear in mind that the Commission and the Governments of the other EU Member States may not be the only people to whom such a deal would have to be sold.  On other occasions where the EU has departed from established legal norms it has found itself having to deal with the unsolicited and not necessarily positive input of the Court of Justice of the EU: indeed in the case of the EEA, parts of its founding Treaty had to be renegotiated to accommodate the Court’s concerns.  This may complicate matters.

Non-EU / EEA law constraints imposed by international law

A non-EU / EEA UK would not be constrained by EU / EEA law, but it would not be free of other international law constraints that have a bearing on regulation of the energy sector. We will consider this topic in more detail in a later post, but for now, note the following examples.

  • If the UK were to negotiate and become party to a free trade agreement with the EU / EEA other than the EEA Agreement, it is likely that (as other such agreements have), it would include requirements to enforce competition law and a prohibition on state aid.  Accordingly, all the non-EU / EEA UK energy policy options referred to above which would be contrary to EU state aid rules could be the subject of disputes under a UK-EU / EEA free trade agreement if they were implemented.  If, on the other hand, the UK were not to negotiate such a bespoke free trade agreement and were to rely instead on WTO rules, such measures may still fall foul of the WTO rules against subsidies.
  • The decommissioning of oil and gas infrastructure is regulated by the Convention for the Protection of the Marine Environment of the North-East Atlantic (more familiarly known as the OSPAR Convention), one of a number of international conventions relevant to the environmental aspects of the energy industry.
  • The Energy Charter Treaty and bilateral investment treaties to which the UK is a party may offer protection for those who invest in the UK energy sector, and cause the Government to refrain from taking action that would create claims against it under them.

More generally, if the UK were to follow this path, it is possible that any radical departures in energy policy could affect the terms of trade deals that could be negotiated with other states, and any tariffs imposed by them.

Co-operating with EU / EEA countries outside the EU / EEA

It is to be hoped that Brexit will not mean the end of useful co-operation on energy matters between the UK and other EU / EEA States acting individually. We note in this context that the UK did not sign up to the recent political declaration by North Sea countries regarding their initiative on co-operation to develop a more co-ordinated approach to the development of offshore electricity transmission infrastructure in the North Sea (known as NSCOGI), despite having previously supported this initiative.  No doubt the fact that the document was signed less than three weeks before the June 23 referendum did not help, but given the potential strength of the UK’s offshore wind industry and the savings that could be made by developing offshore links on a “hub and spoke” rather than “point to point” pattern, it would be a pity if the UK were to drop out of NSCOGI.

Closer to home

This Blog, like many similar publications, has talked in bland terms about “the UK”. This overlooks:

  • the possibility that Scotland will ultimately leave the UK rather than the EU;
  • the fact that the devolved government in Northern Ireland has (nominally) complete and (practically) very extensive powers to make its own rules on energy matters;
  • the existence of a Single Energy Market across the island of Ireland and a single set of electricity trading arrangements (BETTA) across England, Wales and Scotland; and
  • the fact that post-Brexit the Republic of Ireland will be the only EU Member State whose connection to the EU single market in gas runs entirely through non-EU territory.

There will be more to say on these points, and on other intra-UK energy Brexit issues, in later posts.

On a practical level, businesses would do well to review those parts of their key existing contracts (and any important contracts under negotiation) that contain provisions where rights and obligations could be triggered by the occurrence of Brexit: obvious examples include provisions on force majeure, change in law, material adverse change, hardship and currency-related matters. Again, more on this to follow.

(Provisional) conclusions

EU and UK energy regulation have become so intertwined over the years, and the energy industry is so international in a variety of ways that it is inevitable that Brexit will affect all parts of the UK energy sector to some degree. And those parts of it that are arguably not so directly affected are themselves subject to other massive regulatory interventions at present in any event (notably the energy supply markets in the wake of the Competition and Markets Authority’s investigation).

What will change in the energy sector as a result of the UK electorate voting to leave the EU? At this stage, it is tempting to say simply: “If we stay in the EEA, nothing will really change.  If we try to go it alone, who knows?  The only certainty is years of uncertainty”.  We hope that the preliminary observations in this post have shown that the position is rather more complex and dynamic, and the range of issues to be addressed and possible outcomes is wider than is sometimes supposed.

For now, we would suggest that it is important to follow the details closely, because unless you believe that the result of the referendum will somehow not be implemented, there is no more justification for complacency about the ultimate consequences of Brexit for the energy sector than – if one supported remaining in the EU – there was about the result of the referendum itself.

If you have questions about the issues raised in this post, or about other aspects of Brexit as it relates to your business, please get in touch with the author or your usual Dentons contact.

 

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Energy Brexit: initial thoughts

The New North Sea – Part 2: the legal mechanics of “MER UK”

This is the second in a series of posts on the new regulatory regime for the North Sea oil and gas industry following the enactment of the Energy Act 2016.  In the first post we introduced the new regime.  Here, we look at how its central legal provisions work.

At the heart of the new regime is the concept of “MER UK”.  This is short-hand for the “principal objective” of “maximising the economic recovery of [offshore] UK petroleum”, which is set out in s. 9A of the Petroleum Act 1998 (inserted by the Infrastructure Act 2015).  The way that the principal objective governs both the regulators and those they regulate is summarised below.

Diagram

Two points are worth emphasising here.

First, obligations to act in accordance with the MER UK strategy apply to a very broad range of persons engaged in a very broad range of activities – the summary above slightly understates this. It does not, for example, have room to list all the categories of offshore installation (e.g. gas storage or accommodation facilities) that are covered.

Second, the key obligations in the legislation refer to the MER UK strategy, rather than the principal objective itself.  This gives DECC (for now) and the OGA (in the future) great flexibility to articulate the practical implications of the principal objective, and to do so in a document that, although it is legally binding, does not have to be (and is not) written with the precision that one would expect to find in legislative drafting.

The position in practice could almost be caricatured as being “you must do what the OGA says you must do to achieve MER UK”.  Courts would probably be reluctant to second-guess the range of factors contributing to an assessment of MER UK in any event, but this feels like a regime which has been very carefully set up with a view to minimizing the risk of administrative law challenges to the regulator’s decisions.

NOTE: The Energy Act 2016 is being commenced in stages, by regulations.  The first commencement regulations were made on 23 May 2016.  So far, only provisions which empower the Secretary of State to make further regulations or transfer schemes (e.g. relating to the transfer of property from DECC to OGA) have been made.  However, the substantive obligations on “relevant persons” and DECC / OGA described above are largely contained in the provisions which the Infrastructure Act 2015 inserted into the Petroleum Act 1998 with effect from 12 April 2015 (even though the MER UK strategy itself was not finalized until almost a year later).

So although it may be a few months before the sections of the Energy Act 2016 that will allow enforcement of MER UK obligations are brought into force by further commencement regulations, the substantive obligations to comply with MER UK principles are already in force and should be kept in mind by relevant persons (and DECC / OGA) in all the situations where they apply.  The next post in this series will explore some of these situations, with particular emphasis on exploration activities.

The New North Sea – Part 2: the legal mechanics of “MER UK”

The New North Sea – Part 1: the revolution begins here

How much of a difference will the recent reforms of UK offshore oil and gas regulation make to the industry and its stakeholders? It may be too early to say whether the creation of the Oil and Gas Authority (OGA), the articulation of the “MER UK Strategy” and the other changes introduced by the Infrastructure Act 2015 and the Energy Act 2016 will facilitate solutions to all the significant problems faced by North Sea operators, but in our view it is already clear that the changes of the last two years will have a profound impact on the industry.

Government intervention in the UK’s offshore oil and gas industry is nothing new. It has taken different forms at different times, and has included, as well as numerous changes in taxation, Government participation (or at least the ability of Government to participate) in decision-making at the individual asset level through rights granted to state-owned entities.

More specifically, for almost 20 years, Government has been aware of, and has been taking action to address, the particular set of problems that the UK Continental Shelf (UKCS) faces as a mature basin.  Between 1999 and 2004, the Department of Trade and Industry and its successors took a series of steps to foster investment and innovation in the industry and improve its efficiency: a joint Government / industry report (A Template for Change) was published in 1999; task forces were appointed; changes were made to the administration of the licensing regime; new types of licence were introduced.

PILOT and small-scale regulatory changes, 1999-2004
1999

 

 

Brent at $9/barrel – a record low – in February, but recovers to $25 by December.

Oil & Gas Industry Task Force report (September) set a vision for the UKCS in 2010, aimed at increasing investment and employment, and prolonging UK self-sufficiency in oil and gas.

2000 PILOT established to take over the work of the Task Force and give effect to its recommendations
2002 PILOT “Progressing Partnership” Work Group launched to address behavioural and supply chain barriers. Initiatives include transferring “fallow” assets to those best placed to exploit them.
2003 “Promote” licences offered for the first time to attract new small players.
2004 22nd offshore licensing round: largest number of blocks since 1965.   “Frontier” licences first offered.
   

However, by the time that Ed Davey, as Secretary of State for Energy and Climate Change, commissioned Sir Ian Wood to carry out a review of the industry in 2013 and the Wood Review’s final report was issued early in 2014, it had become clear that all the good work done after the 1999 report had not resolved or prevented some fundamental problems, and that the “vision for 2010” which it articulated had not been fully realised.   Average production efficiency declined from 81% in 2004 to 60% in 2012.  There had been a downward trend in numbers of exploration wells drilled since 2008 (with about 70% fewer being drilled in 2013 than were drilled five years before).  Perhaps worst of all, costs of production per barrel had risen fivefold in ten years.  And all that was before global oil prices began a period of sharp decline which has seen them fall to levels at which most North Sea fields are said to be uneconomic, with no certainty of a rapid or sustained recovery.

A false sense of security? North Sea licensing events highlighted in Government reports, 2005-2012
2005 24 new companies enter the North Sea as part of a record offering of 151 licences.
2006 UK a net importer of gas in value terms for the first time since the early 1980s.
2007 Legislation to allow storage of natural gas under the seabed / unloading of LNG at sea announced.
2008 Brent crude tops $100 / barrel for the first time, rising to over $140 / barrel in June and July.
2010 Largest number of blocks applied for since the first licensing round in 1964.
2011 Brent crude tops $100 / barrel for the first time since 2008.
2012 Demand for offshore licences again breaks all records (applications covering 418 blocks).
   

Many of the concerns that were articulated in the 1999 report and addressed in the initiatives that followed from are echoed in the Wood Report. Both reports are in favour of such things as “collaboration in place of competition”, “improving relationships between licensees” and encouraging innovation, for example.  But the final results of Wood’s work are very different from those of the earlier report and its follow-up.  Where the 1999 report tends to talk about “deregulation”, the Wood Report has led to the creation of a new, more powerful and better resourced body to regulate the industry.  In the words of the Wood report itself: “In the early days with large fields to be found by major operators, the free market model worked well with a light touch Regulator…However, over time, the number of fields has increased, now to over 300, new discoveries are much smaller, many fields are marginal and very inter dependent, and there is competition for ageing infrastructure. Alongside this, the…Regulator has halved in size in 20 years and…is clearly struggling to perform a more demanding stewardship role.

There has been general agreement with Wood’s conclusion that “a stronger Regulator with broader skills and capabilities able to significantly enhance the level of co-ordination and collaboration” would “largely resolve” the problems that his review identified.  It is rare for an industry to be so apparently united in its desire for stronger regulation – even if it was clear from the first that a regulator based on Wood’s prescription would be different from many sector regulatory bodies in terms of its remit, composition, and its interactions with industry.  It has probably helped that the fall in oil prices has made the problems identified by Wood more acute, increasing the demand for a powerful independent regulator to get to work on solving them.  This, together with the compelling nature of Wood’s analysis and strong political support, has enabled the necessary legislative changes to be put in place rapidly.

The Wood Review and its implementation, 2013-2016
2013 Government commissions the Wood Review of offshore oil and gas recovery (June)

The interim report of the Wood Review is published (November)

2014 Final report of the Wood Review published   (February)

Sharp fall in oil price begins (June)

Government response to the Wood Review published (July)

Clauses on MER UK (to amend the Petroleum Act 1998) inserted into Infrastructure Bill (October)

Appointment of Andy Samuel as CEO of OGA (November)

2015 Andy Samuel asked to lead urgent study of key risks to North Sea oil and gas industry (January)

Infrastructure Act 2015, including revised provisions on MER UK receives Royal Assent (February)

OGA issues “call to action” document in response to DECC’s request to Andy Samuel (February)

OGA launched as an Executive Agency of DECC, carrying out DECC regulatory functions (April)

Energy Bill, dominated by provisions on the OGA, introduced into Parliament (July)

Oil & Gas UK launches efficiency task force (September)

OGA reports: call to action 6 months on (September)

OGA publishes draft corporate plan (November)

DECC launches consultation on MER UK strategy (November)

2016 Brent crude falls below $30 / barrel (January)

Government support package for UK offshore oil and gas (January)

Draft MER UK strategy laid before Parliament (January)

OGA publishes Corporate Plan 2016-2021 (March)

MER UK strategy finalised and comes into force (March)

Energy Bill receives Royal Assent, Energy Act 2016 published (May)

Why do we think that North Sea regulation from now on (or at least from the date on which the relevant provisions of the Energy Act 2016 come into force and the Regulator’s staff complement is up to full strength) will be radically different from what operators have been accustomed to? There are six main reasons.

For the first time, the UK offshore regulatory regime (excluding its environmental and health and safety aspects) has a single governing principle articulated on a statutory basis – the objective of maximising the economic recovery of UK petroleum (MER UK).

Although MER UK is defined in general terms in a strategy promulgated by DECC under the Infrastructure Act 2015, its specific meaning and impact in any given situation will in large measure be determined by the Oil and Gas Authority (OGA).

The obligation to act in accordance with MER UK, as so defined and interpreted, applies – or could be said to apply – to at least one person involved in the taking of almost any commercially important decision in the offshore industry.

Under the new regime, the OGA and DECC will potentially have access to vastly more information about North Sea assets and infrastructure, the commercial intentions of those with interests in them, and the relations between them, than DECC has had to date.

The OGA does genuinely appear to be a new kind of regulator, in terms of its composition, capabilities, culture and combination of functions. It is also likely to take a more proactive approach than its predecessors.

The terms of the MER UK strategy and the robustness of the enforcement tools at the OGA’s disposal suggest that it will enjoy unparalleled leverage over licence holders and others to ensure that collaboration “for the greater good” really does happen.

In future posts in this series, we will explain in more detail how the relevant provisions of the Infrastructure Act 2015, the Energy Act 2016 and the MER UK strategy achieve these results and how we think the application of the new rules by industry parties, DECC and the OGA will affect key moments in the life of North Sea infrastructure and assets.

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The New North Sea – Part 1: the revolution begins here

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?

Ready to “stand on its own two feet”? Government’s vision for UK solar industry

In a series of announcements on 17 December 2015, the UK Government has almost completely answered the question it posed in a series of consultations in July and August 2015: how to minimise, and then stop, any further subsidies to the UK solar industry. The headline points are as follows.

  • As proposed in its consultation of 22 July 2015, the Government has decided to close the Renewables Obligation (RO) to new solar PV plants of <5 MW from 1 April 2016.
  • There will be a grace period until 31 March 2017 for projects that had progressed to the stage of meeting specified criteria relating to preliminary accreditation or “significant financial commitment” (accepted grid connection offer, planning application and land rights) by 22 July 2015, or subsequent grid connection delays.
  • The Government is proposing a change in the level of ROC banding with effect from 1 June 2016, such that projects with an accreditation date after 22 July 2015 would receive 0.8 ROC / MWh rather than their previous levels of 1.5 or 1.4 (for roof-mounted projects) or 1.3 or 1.2 (for ground-mounted projects).
  • Projects that had not satisfied the “significant financial commitment” criteria by 22 July 2015 will not necessarily benefit from the same level of RO support (0.8 ROC from 1 June 2016) over the 20 year period of their eligibility for Renewable Obligations Certificates (ROCs) – i.e. the policy of “grandfathering” will not apply to them and their ROC support could be reduced at any time.
  • The Feed-in Tariff (FIT) scheme will be reformed broadly in line with the consultation proposals of 27 August 2015 – that is, the tariffs for most technologies and installation sizes will be significantly reduced, future deployment under the scheme will be tightly limited, and the overall administration of the scheme will become more complex.

One point on which the 17 December announcements do not elaborate is whether any future allocation process for Contracts for Difference (CfDs), which are intended to replace the RO for most eligible technologies, will include solar projects. More on that below. DECC has also left the door open to, or positively indicated that it will, make further reforms in 2016.

We set out below some further points to note in respect of each of the 17 December announcements and some thoughts about where all this is, or may be, going. For background, particularly on FITs, see our earlier blog post on the FIT reform proposals.

Renewables Obligation changes

It is hard to imagine what any consultees could have said to persuade the Government not to close the RO to new <5 MW solar projects a year before the general RO closure date of 31 March 2017.

Government concern about breaching the limits on renewables subsidies set out in the Levy Control Framework (LCF) runs very deep. The Impact Assessment suggests that early closure will save the LCF between £60m and £100m. This is on the assumption that those plants that qualify for grace period treatment are unlikely to need to rely on it (perhaps likely in most cases except where it is an unforeseen delay in the grid connection that qualifies the project for grace period treatment). However, the Impact Assessment is also even-handed enough to note that the LCF savings could be counter-balanced by the negative value of CO2 emissions not avoided as a result of losing 1.2 to 2.0 GW of new solar generating capacity that might otherwise have been constructed.

The Government appears to have been concerned that if it were not for the removal of grandfathering and the banding review, projects that did not enjoy grace period treatment (some of them perhaps projects failing to accredit at current FIT generation tariff levels and seeing 1.3 or 1.2 ROC as an attractive fall-back) would have come forward and been accredited before 31 March 2016 – in numbers that would have been prejudicial to the LCF limits: “the spike of deployment of solar projects of greater than 5 MW at the end of the last financial year demonstrates the solar industry’s ability to react quickly and decisively to changes in the policy environment”. If there is no similar spike in <5 MW RO projects in the current financial year, it will probably be because by consulting in July on both the removal of grandfathering and the possibility of a banding review, but only announcing in December what the level of post-banding review ROC support might be, the Government created a climate in which the majority of prudent solar developers would not consider pursuing, in the intervening period, projects that did not meet the significant financial commitment criteria.

It is to be hoped that investors will perceive the removal of grandfathering in this case as a tactical manoeuvre by a Government that believed it faced a unique problem.  If, instead, investors were to form the view that what has happened in this case heralds a general departure from the policy of grandfathering renewables subsidies that has been almost universally adhered to by the UK to date, they would obviously be more reluctant to commit to UK renewables projects in future.

A sizeable minority of consultees agreed that costs have reduced since the last banding review (and about half of them thought the reductions significant). Many also cited plausible reasons why – notwithstanding e.g. the fall in panel prices – the Government should not take the strike price for solar projects set in the first CfD auctions earlier this year (£50 and £79.23 / MWh) as necessarily representative of the typical costs of an RO-supported solar project. However, the Impact Assessment for the banding review consultation, supported by an Arup study, suggests that 0.8 ROC / MWh is not a prohibitively low level of subsidy for some projects and industry players.

As the banding review and grandfathering changes only affect projects in England and Wales the trend of increasing interest in Scottish projects is likely to continue. Northern Ireland will also continue to enjoy different bandings.

Clarification of what is required to satisfy the planning component of the significant financial commitment grace period criteria has been provided in a draft of the Order that will implement the early closure of the RO to <5 MW solar projects. This may well terminate the viability of some projects whose promoters hoped to obtain grace period treatment in cases where something less than what constitutes a valid application under the relevant planning legislation had been submitted to the local planning authority by 22 July 2015.

The combined effect of the decisions on early closure and grandfathering, coupled with the proposed banding review changes, is well summed up in the following tables from DECC.

Stations that qualify for the grandfathering exception criteria/significant financial commitment grace period

Stations that do NOT qualify for the grandfathering exception criteria

FIT reforms

The FITs changes affect smaller-scale onshore wind and hydro projects as well as <5 MW solar projects.  The starting point is clear from the first page of the Impact Assessment for the FITs announcement: “The intention is that a maximum of £100m is spent on new-build deployment per year over this FITs review period (from early 2016 to the end of 2018/19).”.

If it achieves this, the Government expects to reduce LCF costs by between £380m and £430m, reduce deployment by between 5.6 GW and 6.2 GW (or between 802,000 and 912,000 fewer installations) and see between 9,700 and 18,700 fewer jobs in the solar industry by 2020/21.

The principal means of securing these results are severe cuts in generation tariff rates.  The DECC table below shows how the new rates for solar PV projects compare with those currently in force, and those proposed in the August 2015 consultation.

DECC table

It is the smallest installations, representing domestic roof-mounted solar, which have done best out of the consultation process, but it is those in the 250-1000 kW bracket that will see the lowest reductions in subsidy. Good news for commercial and industrial premises with lots of roofspace and a significant daytime electricity demand on-site – even if the consultation process has led to 0.01p/kWh being trimmed from their proposed tariff. (The cuts to wind and hydro tariffs are somewhat less severe, but still swingeing in many cases.)

The Impact Assessment and response to consultation together are more than 150 pages long. Blog posts are meant to be short and pithy, so there is not space here to mention everything that is of interest in the FITs announcement. However, the following points are worth noting.

  • The consultation response confirms that support under each tariff band will be subject to quarterly rationing (“deployment caps”). For the largest bands this may mean that only one or two installations are accredited in each quarter. Everything will depend on the date and time (“to the second”) of an installation’s MCS certificate or ROO-FIT application. Those who miss out in one quarter will be “frozen” in a queue until the next cap opens.
  • There is a lot of detail on the working of the caps and the reformed degression mechanism in the consultation response (see also Ofgem’s draft guidance).
  • Pre-accreditation, removed as long ago as 1 October 2015, is to be re-introduced (for those installations to which it was previously available – i.e. not including those of <50 kW) but in an attenuated form: installations will get the tariff rate that applies on the date of their accreditation, not that of their pre-accreditation.
  • Some of the post-consultation tariff adjustments reflect changes in what the Government considers to be appropriate target hurdle rates (now 4.8% for solar). These may not be enough to motivate those who are thinking of installing domestic rooftop solar.

What happens next?

RO

The early closure of the RO to <5 MW solar will be implemented by amendments to the Renewables Obligation Closure Order 2014. The banding review proposals, if taken forward after the current consultation ends on 27 January 2016, will need to be implemented by amendments to the Renewables Obligation 2015, by 1 June 2016.

The statutory instruments required to make both sets of changes will require the approval of both Houses of Parliament – which, although likely, cannot be guaranteed, particularly in the case of the House of Lords, who recently voted down the proposed early closure of the RO for onshore wind.

FITs

Implementing the policy decisions on FITs requires a combination of modifications to the standard conditions of electricity supply licences and amendments to the Feed-in Tariffs Order 2012.  Differences in Parliamentary procedure mean that the licence modifications take longer to bring into force than the amending Order. Accordingly, Government expects the Order to come into effect on 15 January 2016 and the licence modifications (which include the new tariff rates) to come into effect on 8 February 2016. As mentioned briefly in the FITs consultation, there is to be a pause in the FITs accreditation process between 15 January and 8 February 2016.

As in the case of the RO changes, there is (at least in theory) scope for a negative vote in either House of Parliament to blow the implementation off course. It would also be surprising if there were not some attempts to challenge the changes by way of judicial review, although the litigation process would inevitably play out over a slower time-frame.

And there is more to come…

The Government has expressly flagged or left open a number of areas of possible further reform. For example, the feedback received on possible changes to the FIT export tariff “will be used to frame a detailed consultation on these issues in the future” – Government “may make changes to the structure of the export tariff…for new entrants [including] changes to indexation”.

And just in case anybody should feel too comfortable, the new tariffs, the system of deployment caps and the overall scope of the FITs scheme (i.e. whether it should be more tightly focused in terms of technologies or sizes of installation) are all to be kept under review.

What about CfDs (and everything else)?

The original reason for closure of the RO is its replacement by CfDs, the costs of which, because they are allocated in a competitive process and using defined budgets, can be more easily be controlled. The expectation was that CfD allocation rounds and Capacity Market auctions would be (at least) annual events. However, whilst the Government has held a second Capacity Market auction a year after the first such auction, more than one year on from when the first CfD auction process began, there is no sign yet of the process for a second CfD auction being set in motion. And although one has been announced in general terms as taking place in 2016, there has been no definite pronouncement as to whether it will include a budget for solar.

Is the Government waiting to see how the new ROC band and FIT tariffs play out before deciding whether to include solar in the next CfD auction, and/or how much money to allocate to the part of the auction where solar projects will compete? The rules allow the Secretary of State to decide these points only a very short time before the allocation process begins. For developers considering whether to commit significant sums of money to progress potential solar CfD projects to the stage where they could bid in a 2016 auction, the lack of clarity about such an auction is not helpful.

The FITs consultation response says that it contains measures that “seek to maintain a viable renewables industry which, in the longer-term, can continue to reduce its costs, seeking to achieve grid parity”. By the Government’s own admission, that industry, if still viable, will be considerably smaller once these reforms have been implemented.  It is to be hoped that the industrial and commercial rooftop sector will continue to expand, given the relatively less severe FIT tariff rate reductions that are to be imposed on it. It is likely that some business will be lost to other European jurisdictions which currently enjoy a more benign solar subsidy environment.

Away from the narrow focus on subsidy costs, the hottest strategic topic about the growth of solar deployment is how to manage the system integration costs of low carbon technologies (particularly intermittent wind and solar generation) and encourage the use of storage by renewable generators so as to smooth their export profile and increase system flexibility. (See also Ofgem’s position paper of 30 September 2015 on system flexibility.) These issues were essentially absent from the consultation proposals and decisions. However, the FITs consultation response states that DECC is engaging closely with Ofgem and stakeholders to identify barriers to the deployment of storage and are considering potential remedial actions. The Government plans to consult on this work in “spring 2016”. Perhaps less advantageously for the solar industry, Government is also  “continuing to explore” with National Grid and Ofgem the question of “distributed generation paying for its impact on the whole system”.

Another interesting year ahead for an industry which learnt some time ago that the only certainty is change.

Ready to “stand on its own two feet”? Government’s vision for UK solar industry

Published at last – a winning strategy for the UK Continental Shelf?

Finally, we have the missing piece of the jigsaw.  The current reforms to the UK’s regulatory regime for the offshore oil and gas industry were recommended by the Wood Review in 2014.  They began to be implemented with the creation of the Oil and Gas Authority (OGA) and the amendments made to the Petroleum Act 1998 (the 1998 Act) by the Infrastructure Act 2015; they are continuing with the current Energy Bill (now half way in its passage through Parliament).  But it is perhaps only with the publication of a draft of the strategy for maximising the economic recovery of UK petroleum on 18 November 2015 that we start to get a full sense of how the new regime may work in practice.

What is the draft strategy, and why does it matter?

The legislation describes the strategy as “enabling” the “principal objective” of “maximising the economic recovery of UK petroleum” (MER UK) to be met.*  The principal objective and the strategy occupy a central position in the revised regulatory scheme.

To begin with the regulators.  In one way or another, the OGA is taking over most of the Secretary of State’s statutory functions under the Petroleum Act 1998 and Chapter 3 of Part 2 of the Energy Act 2011.  The OGA is also to acquire a raft of new functions under Part 2 of the Energy Bill.  In exercising all these functions (including any of its powers under a petroleum licence), the OGA will be obliged to “act in accordance” with the strategy.  The Secretary of State will be similarly obliged to act in accordance with the strategy when exercising her functions under the Part 4 of the 1998 Act “to the extent that they concern reduction of the costs of abandonment”.

At the same time, the strategy will be binding on holders of, and operators under, petroleum licences, when planning and carrying out their activities as such; persons planning or carrying out the commissioning of upstream petroleum infrastructure (broadly defined); and (subject to the Energy Bill) owners (broadly defined) of offshore installations and upstream petroleum infrastructure, when carrying out their activities as owners of such installations or infrastructure, or decommissioning it.  Such persons and (in so far as they can affect the fulfilment of the principal objective) activities are referred to in the draft strategy as “relevant persons” and “relevant functions” respectively.

The Energy Bill provides that if a business which is a relevant person fails to act in accordance with the strategy, the OGA can impose sanctions including financial penalties of up to £1 million (and potentially up to £5 million if the Secretary of State raises the penalty cap by regulations) and revocation of the business’s status as a holder of, or operator under, a petroleum licence.

Although the strategy will become more important as and when the Energy Bill completes its passage through Parliament and becomes an Act, many of the provisions establishing the importance of the principal objective and the strategy are already embodied in the amendments made to the 1998 Act by the Infrastructure Act 2015.  So it is noteworthy that reform of the offshore oil and gas regulatory regime has gone so far without public consultation on a full draft of the strategy.

What the draft strategy says

The Wood Review pointed out, and subsequent OGA papers have elaborated on, the fact that the inter-dependence of different installations and infrastructure in the UK upstream oil and gas industry is such that if each relevant person only seeks to optimise its own financial position, the performance of the industry as a whole is likely to be sub-optimal.  So the key question for the draft strategy to answer is how (and how far) businesses are to be induced to compromise their interests for the greater good.

To look at how the draft strategy answers this question, it is best to start with two of its key definitions.

  • “economically recoverable petroleum” means “those resources which could be recovered at an expected (pre-tax) market value greater than the expected (pre-tax) resource cost of their extraction, where costs include capital and operating costs but exclude sunk costs and costs (like interest charges) which do not reflect current use of resources.  In bringing costs to a common point for comparative purposes a 10% real discount rate will be used“.
  • “satisfactory expected commercial return” means “a reasonable post-tax return having regard to the risk and nature of the investment“.

These two definitions underpin what are perhaps the draft strategy’s two most important provisions:

  • The Central Obligation applies to relevant persons in the exercise of their relevant functions, and obliges them to “take all steps necessary to secure that the maximum value of economically recoverable petroleum is recovered from the strata beneath UK waters“.  (Emphasis added: as a recital to the draft strategy puts it: “all stakeholders should be obliged to maximise the expected net value of petroleum produced from relevant UK waters, not the volume expected to be produced”.  The focus on value (undefined) rather than quantity contrasts with the similar but different words about “securing the maximum ultimate recovery of petroleum” in the petroleum licence model clauses on unitisation, which represent perhaps the greatest degree of intervention by the licensing authority under the existing regulatory regime.)
  • Paragraph 27 provides that if relevant persons “decide not to ensure the recovery of the maximum value of economically recoverable petroleum from their licences or infrastructure (including because that does not achieve a satisfactory commercial return, in accordance with paragraph 3) they must relinquish or divest themselves of such licences or assets“.

The “paragraph 3” referred to here is one of the draft strategy’s Safeguards: “No obligation imposed by or under this Strategy requires any person to make an investment or fund activity where they will not make a satisfactory expected commercial return on that investment or activity.”.

It is hard to quarrel with any of this in the abstract, but applying these principles in any given case will not necessarily be easy.  For example, how do you assess “expected pre-tax market value” in the context of massive uncertainty over future oil and gas prices?  DECC’s own most recent fossil fuel price projections suggest that the average oil price for the next 10 years could be anything from $46.8 to $140.4 a barrel (depending on whether you take the “low” or “high” scenario).

What does this mean in practice?

The consultation document spells out where all this leads.  If you are the owner or operator of an asset or infrastructure and take the view that you cannot make a satisfactory commercial return from its continued operation, you may be obliged to divest it to somebody who takes a different view of what constitutes a satisfactory return or what is economically recoverable.

Paragraph 27 is one of a number of “supporting obligations” and “required actions and behaviours” listed in the draft strategy in respect of exploration, development, asset stewardship, deployment of new technology and decommissioning.  So, for example, owners and operators of infrastructure must plan, commission and construct it in a way that meets the optimum configuration for MER UK, and must allow access to it on fair and reasonable terms.  If the infrastructure is not able to cope with demand for its use, they must prioritise “access which maximises the value of petroleum recovered”.  Meanwhile, the OGA may produce plans addressed to “a single or small group of relevant persons” setting out its view of how the obligations of the strategy may be met in their particular circumstances”.  According to the consultation document: “A plan might target a particular or small range of circumstances, or might be broader and more strategic in nature, for example setting out how the OGA thinks a region should be developed or decommissioned.”.

The new regime

In the words of the consultation document: “How the OGA uses and acts on the Strategy is…of great importance – it will set the tone for the basin and will be a key factor determining its attractiveness to industry and investors.”.

One could perhaps sum up the spirit of the strategy by mangling a famous line from John F. Kennedy: “Ask not what the strategy can do for you, but what you can do to maximise the economic recovery of UK petroleum.”; or perhaps quoting Karl Marx, without modification: “From each according to his ability, to each according to his needs”.

But enough flippancy.  The consultation document goes out of its way to emphasise that the OGA will not be unduly interventionist: “whilst enforcement measures are a necessary backstop, the OGA is expected to act primarily as a convenor and facilitator, working together with industry to deliver increased value from the UKCS for both industry and the UK as a whole”.  If it is “occasionally…the case that the OGA [finds] that a relevant person’s contractual provisions place that person…in breach of the Strategy”, or if the OGA finds that it needs “to assert its right as a regulator to use its sanctions where a relevant person fails to avoid a breach of its MER responsibilities through continued reliance on contractual provisions which conflict with the Strategy…. it will always be for the relevant person to decide for itself how to deal with that in terms of its contracts.”.

Perhaps a useful point of comparison here is the UK power market.  It has become commonplace to note that the UK’s various schemes for subsidising new low carbon electricity production, and the Capacity Market which subsidises old nuclear and fossil fuelled generating stations, have turned the liberalised GB power generation market into something closer to a “planned economy”.  Where the fulfilment of the principal objective is at stake, the Energy Bill requires that the OGA be allowed to participate in meetings between relevant persons, and recommend ways of resolving disputes between them.  Reading such provisions side by side with the draft strategy, it is clear that in the oil and gas industry too, future commercial decision-making may be much more strongly directed by the state than before.

Then again, perhaps one should compare oil and gas production not so much with the power generation market, which is supposed to be characterized by free competition, but with the monopoly markets of transmission and distribution, where it is accepted that it is only economic for one operator to build and operate infrastructure in any given location – just as petroleum licence holders enjoy exclusive rights in their licensed areas and many oil and gas infrastructure owners are de facto monopoly service providers.  In the power sector, to avoid any abuse of monopoly, the returns which network operators can earn on their investment are regulated.  The strategy does not go (quite) that far.

In the end, the strategy highlights the two risks that the OGA will need to guard against particularly carefully in administering the reformed regulatory regime.  The first is highlighted in a letter of 3 December 2015 from the UK Competition and Markets Authority, using for the first time its new powers to make and publish recommendations to Ministers about proposed new legislation: the OGA and those it regulates could collaborate so closely that beneficial competitive pressures, which are important to reduce costs and support the principal objective, could be dampened, so that, for example, the regulatory process ends up facilitating the anti-competitive exchange of information between competitors.  The second and opposite risk is that a less co-operative attitude amongst industry players prompts the OGA to start using its enforcement and other formal powers to an extent that in turn stimulates the kind of “over-zealous commercial and legal behaviour” on the part of the industry that Wood wanted to make a thing of the past.

So perhaps what matters most is not the strategy itself, but the tactics of those who must follow it – both the OGA and industry players.

* Note: The definition given above of the “principal objective” reflects the current text of section 9A of the 1998 Act.  If clause 8 of the Energy Bill (introduced by an Opposition amendment) survives, it will become instead “maximising the economic return of UK petroleum, while retaining oversight of the decommissioning of oil and gas infrastructure, and securing its re-use for transportation and storage of greenhouse gases” – although how much difference some of those additional words will make now the Government has abandoned its CCS commercialisation programme is debatable.

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Published at last – a winning strategy for the UK Continental Shelf?

UK onshore wind subsidies: not dead yet

A vote in the House of Lords on 21 October 2015 has, for the moment at least, derailed the Government’s proposals to prevent new onshore wind farms commissioned after 31 March 2016 from being subsidised under the Renewables Obligation (RO).

Readers of our earlier posts on this subject (see here and here) will recall that in June 2015 Government said that its proposals would form part of the current Energy Bill.  In July, “grace period” arrangements were promised for those projects with planning permission, grid connection agreements and land rights by 18 June 2015.  On 8 October, Government amendments to the Bill, setting out the details of grace period relief, were  published.  They covered a somewhat broader range of cases than just the “planning / grid / land rights” one.  After a Committee debate on 14 October 2015 in which Lord Wallace of Tankerness and others identified a range of scenarios where they felt projects would, unfairly, not benefit from the grace period amendments, Lord Bourne, for the Government, withdrew the amendments to consider them further.

Before the debate at Report stage on 21 October, Government re-tabled its amendments, virtually unchanged, and Opposition Peers tabled a number of others, including one that simply removed clause 66 (the early closure provision) from the Bill altogether.  This amendment was passed, by 242 votes to 190.

What is going on, and what (so far as we can tell) happens next?

  • Ministers have suggested that in voting to remove clause 66, Peers were flouting the “Salisbury convention” – i.e. the principle that the unelected House should not thwart measures that have appeared in the election manifesto of an incoming Government.  The Opposition response to this is that the Conservatives’ General Election pledge to “end any new public subsidy” for onshore wind was one thing (which might, for example, equate to removal of onshore wind from the list of technologies eligible to compete for Contracts for Difference (CfDs)); but bringing forward the closure of the RO (an existing subsidy) is another thing altogether.

 

  • The Opposition stress that they are not opposing the phasing out of onshore wind subsidies per se – rather, they object to what they see as the Government’s failure to provide details of the proposed grace period arrangements soon enough for them to be properly scrutinised and amended, and to the fact they do not cover various categories of projects whose exclusion from the RO seems to them to be unfair.  It is also alleged that the average savings to Bill payers (30p per household annually) from early closure are outweighed by the lost investments on the part of the industry (over £300 million).

 

  • Some of the “hard luck cases” cited might not have achieved RO accreditation even under the existing, pre-18 June position on RO closure.  Others that it is said may be unfairly treated by the 8 October amendments include projects where a local authority decided to grant planning permission before 18 June but the mitigation arrangements under a “section 106” (England and Wales) or “section 75” (Scotland) agreement were not yet signed off; cases where the developer gave the local planning authority longer than the statutory minimum before treating its silence as a “deemed refusal” of planning permission and challenging it; and cases where a project essentially had a grid connection agreement for some time prior to 18 June but temporarily lost it before that date.

 

  • Lord Bourne may win a prize for Parliamentary understatement when he said, towards the end of proceedings: “The debate has exhibited a clear difference of position in relation to onshore wind.”

 

  • For the moment, the Bill does not provide for early closure of the RO to new onshore wind projects.

 

  • In order to carry out its policy, the Government will have to muster more support at Third Reading in the Lords, or reintroduce the early closure provision in the Commons, where its MPs are likely to be easier to whip.  In the latter case, the provision would then have to return to the Lords for consideration, and could go through more than one round of “ping pong” between the two Houses – with the wind industry (or at least many projects) in suspense in the meantime.

 

  • Unless the Prime Minister really intends to create enough new Peers to guarantee passage through the Lords of the RO closure provisions in the form the Government wants (as appeared to be suggested in connection with the parallel Lords rebellion on cutting tax credits for working families), it looks as if Government needs to secure agreement on a package of grace period amendments that Opposition Peers are content to accept.

 

  • The Parliament Act 1911 enables the Government effectively to bypass the House of Lords in certain circumstances.  But it is unlikely to be of any use to the Government on this occasion, since its timescales would not allow the Bill to be enacted until well after 31 March 2016 – and possibly not (or only a few weeks) before the general RO closure date of 31 March 2017.

Finally, it is worth noting that the vote on clause 66 was one of two Government defeats during the Report stage debate on the Bill.  Peers also voted in an Opposition amendment that would change the basis on which the UK’s carbon budgets are set under the Climate Change Act 2008 – probably with the effect of making them harder to meet.  This more technical and, on the face of it, less politically exciting change is in part a reaction to the Government’s confirmation that it will not be setting a decarbonisation target for the power sector (whose emissions are said not to be counted in carbon budget setting because they fall within the EU Emissions Trading Scheme).  In the longer term, it may – if it survives – have even more far-reaching effects than those of the removal of clause 66.

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UK onshore wind subsidies: not dead yet

Grace periods for early closure of Renewables Obligation support for onshore wind

On 8 October 2015, the UK Government’s Department of Energy and Climate Change (DECC) set out its detailed proposals for mitigating the impact of the proposed early closure of the Renewables Obligation (RO) to new onshore wind projects from 1 April 2016. The provisions now set out in a series of proposed amendments to the relevant part of the Energy Bill, which are to be debated by the House of Lords on 14 October 2015, go a little beyond what DECC first put forward at the start of its period of “engagement” with the industry at the start of July 2015.

The original grace period proposal was relatively simple, and based on the “significant investment grace period” for >5MW solar PV projects. An onshore project would be able to achieve RO accreditation if it commissioned and applied for accreditation after 31 March 2016 but before 1 April in 2017, provided that, as at 18 June 2015 (the date of DECC’s announcement about the proposed early closure) it had planning permission, an accepted offer of connection to the transmission or distribution network, and sufficient rights over the land where it was to be situated – e.g. in the form of a lease, option, agreement for lease or exclusivity agreement.

The proposals set out in the 8 October amendments are more generous, but also more complex. They consist primarily of the insertion of a new run of sections in the RO provisions of the Electricity Act 1989 and their effect is summarised in the table below.

Section of Act (as it would be amended) Date wind farm / relevant additional capacity  is accredited Applicable grace period conditions to be satisfied in order to obtain accreditation
32LD On or before 31 March 2016 No need for grace period
32LE Between 1 April 2016 and 31 March 2017 Grid and radar delay condition – i.e. that:

In respect of either grid connection or radar mitigation works relating to the wind farm / additional capacity on or before the date when Ofgem decided to accredit it, Ofgem has received from the operator:

(a) evidence of an agreement to carry out the works in respect of the wind farm / additional capacity;

(b) document from the network operator / radar agreement counterparty estimating completion on or before the primary date (see below);

(c) letter from the network operator / radar agreement counterparty confirming that the works were completed later than planned, and that this was not due to any breach by the wind farm developer; and

(d) declaration by the operator that to the best of its knowledge and belief, the wind farm / additional capacity would have been commissioned / formed part of the wind farm before the primary date if the works had been completed by that date.

For the purposes of section 32LE, the primary date is 31 March 2016.

32LF On or before 31 March 2017 Approved development condition – i.e. that the accreditation application is accompanied by the following as regards planning, grid connection and land rights.

Planning

One of the following:

(a) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was granted on or before 18 June 2015;

(b) evidence that planning permission (or s. 36 consent / development consent under the Planning Act 2008) was refused on or before 18 June 2015 but granted after that date following an appeal or judicial review;

(c) evidence that an application for planning permission was made to the local planning authority on or before 18 June 2015; the authority failed to determine or decline to determine application, or refer it to Ministers, within the statutory period; the application was not referred to Ministers; and the application was granted after 18 June 2015 following an appeal; or

(d) a declaration that to the best of the operator’s knowledge and belief, planning permission is not required for the wind farm / additional capacity,

and that any conditions as to the time for commencement of development in the relevant planning permission have been complied with.

Grid connection

One of the following:

(a) a copy of an offer from a licensed network operator made on or before 18 June 2015 to carry out grid works in relation to the wind farm / additional capacity and evidence that the offer was accepted on or before that date; or

(b) a declaration by the operator that to the best of its knowledge and belief no grid works are required to commission the wind farm / additional capacity.

Land rights

A declaration that to the best of the operator’s knowledge and belief a developer of the wind farm or additional capacity or a person connected with it in within the meaning of s. 1122 Corporation Tax Act 2010:

(a) was an owner or lessee of the land where the wind farm / additional capacity is to be situated;

(b) had entered into an agreement to lease that land;

(c) had an option to purchase or lease that land; or

(d) was a party to an agreement by the owner or lessee of the land not to permit any person other than those identified in the agreement to construct a wind farm there.

32LG Between 1 April 2017 and 31 March 2018

 

Approved development condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LG, the primary date is 31 March 2017.

32LH Between 1 April 2017 and 31 December 2017

 

Approved development condition

and

Investment freezing condition – i.e. that the accreditation application is accompanied by the following documents:

(a) a declaration from the operator that, to the best of its knowledge and belief, as at 1 May 2016:

(i) it required funding from a recognised lender (a provider of debt finance with an investment grade credit rating) before the wind farm / additional capacity could be commissioned / added;

(ii) the recognised lender was not prepared to provide such funding until enactment of the Energy Act 2016 because of uncertainty about whether it would be enacted / how it would be worded if enacted; and

(iii) the wind farm / additional capacity would have been commissioned / added on or before 31 March 2017 if the funding had been provided before enactment of that Act; and

(b) a letter or other document dated on or before 1 May 2016 from a recognised lender confirming that it was not prepared to provide funding for the wind farm / additional capacity until enactment of the Energy Act 2016.

32LI Between 1 January 2018 and 31 December 2018 Approved development condition

and

Investment freezing condition

and

Grid and radar delay condition – noting that:

Documentary requirements are as described in relation to section 32LE, but

For the purposes of section 32LI, the primary date is 31 December 2017.

It seems likely that the Government’s proposed amendments will be adopted. It remains to be seen whether subsequent debates as the Energy Bill passes through the remaining stages of its passage through the House of Lords, or through the House of Commons, will result in the addition of any further grace period criteria or the tweaking of those already covered. For now, the following points may be noted:

  • The grace period criteria based around a combination of planning, grid and land rights proposed in July have been broadened as regards planning permission.  In particular, what is now called the “approved development condition” allows grace period status to be claimed not just by projects that had obtained planning permission by 18 June 2015, but also by those who had their planning applications refused on or before that date, but have managed to obtain planning permission through an appeal or judicial review process subsequently.  The value of a further extension, relating to cases which local authorities have failed to handle according to statutory timetables, may be more limited, because as currently drafted it appears only to benefit cases that have not been referred to Ministers for determination.
  • The introduction of provisions acknowledging that some projects may be delayed because lenders are unwilling to commit to finance them before the legislation has received Royal Assent is clearly a welcome addition to the package of mitigation for early closure.  However, note that the “investment freezing condition” in which this is set out does not function as an independent justification for not commissioning by 31 March 2016.  Rather, it allows those projects that can already justify an extension of the period within which they can achieve accreditation under the approved development condition to extend for an additional 9 months.
  • In July 2015 DECC had already indicated that projects which benefited from planning, grid and land rights on 18 June 2015 could bring themselves within the scope of the existing grace period provisions on grid and radar delay – thereby potentially enabling them to apply for accreditation as late as 31 March 2018 where such delay had occurred.  The proposed amendments to the Energy Bill disapply the grace period provisions of the Renewables Obligation Closure Order 2014 from onshore wind projects, but reproduce the effect of its provisions on grid and radar delay as part of their own suite of grace period criteria.
  • The revised impact assessment produced alongside the proposed amendments does not appear to suggest that any more capacity will be accredited as a result of the expansion of the grace period criteria (the numbers in all the key tables are the same as in the version of the impact assessment published in September, apparently on the basis of the original proposals).  However, the accompanying DECC press release states that “around 2.9 GW” of onshore wind capacity could be eligible for the grace periods.

The package of mitigation proposed by the amendments is appreciably more generous than what was suggested by DECC in July, but there are limits to that generosity.  For example, the amendments have not simply followed the model established by the >5MW solar PV RO grace period and allowed the planning criterion within the approved development criterion to be satisfied by any project that had applied for planning permission by 18 July 2015.  However, it is noticeable that the DECC policy paper of 8 October 2015 invites “onshore wind developers to tell us about any of their projects affected by our proposals. In particular, we are interested in hearing from developers with projects that are currently in the planning system, but which have not yet secured planning consent, and to receive information and evidence relating to:

  • the stage that such projects have reached in the planning process, anticipated final planning decision dates, and expenditure incurred on projects as at the date of the Secretary of State’s announcement
  • project timetables and anticipated dates for securing a grid connection offer and acceptance; and
  • the prospects of such projects being in a position to accredit under the RO by 31 March 2017 and expected final investment decision dates.”

It is therefore possible that Government is leaving the door open (or, at least, slightly ajar) to a revised ‘approved development condition’ that more closely resembles the model established by the >5MW solar PV RO grace period (and is more favourable to the industry than that currently tabled in the Energy Bill).

Conversely, it will be interesting to see whether some of the new concepts introduced by the proposed ‘grace period’ conditions for onshore wind, such as the investment freezing condition, will find any place in DECC’s eagerly awaited response to its consultation on the proposed early closure of the RO to ≤5MW solar PV projects.

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Grace periods for early closure of Renewables Obligation support for onshore wind