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Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

On November 3, 2016, the Alberta government released the details of its long-awaited plan to accelerate the development of renewable power generation in the province through an auction-based procurement process—a key plank of the Climate Leadership Plan it announced in 2015.

The Renewable Electricity Program (REP) will be launched in early 2017 with an initial, three-stage procurement process for up to 400 MW in new or expanded renewable generation.  Winning bidders will be awarded payments under a “Renewable Electricity Support Agreement” (RESA) that would grant fixed, market-insulated prices for a 20-year term, similar to Ontario and other jurisdictions.

The REP represents a clear, if incremental, change of course for Alberta’s “energy-only” electricity market model—one that will offer significant opportunity to prospective renewable developers if the 2017 auction succeeds.

Background:  The Climate Plan and the AESO’s role

In late 2015, the Alberta government, acting on the recommendations of a Climate Change Advisory Panel (Climate Panel), released its Climate Leadership Plan, a four-pronged “policy architecture” to address climate change in the province.

Beyond its plans for an economy-wide carbon tax, a 100 Mt oil sands emissions cap and a methane reduction plan, the Climate Plan includes a commitment to “30 by ’30”:  to increase the generation share of renewables in Alberta to 30 percent by 2030. To that end, the Climate Panel recommended setting up an open, competitive request for proposals process and incentive payments bounded by a “price collar” (or limit to government support) of CA$35/MWh.  The Panel otherwise saw no need for a change in Alberta’s “energy-only” electricity market.

The “30 by ’30” goal coincides with the Climate Plan’s announcement of a planned phase-out of all of Alberta’s coal-fired generation by 2030. This will be a significant undertaking: based on Alberta Energy 2015 statistics, coal supplies fully half of Alberta’s power requirements.

In January 2016, the Alberta government assigned the Alberta Electric System Operator (AESO) the task of developing specific recommendations on the REP, noting that the government “has not chosen to fundamentally alter the current wholesale electricity market structure.” In the first half of 2016, the AESO launched a stakeholder engagement process and retained economic and financial consultants to study options.

The AESO’s report and the Renewable Electricity Program

On November 3, 2016, the Alberta government publicly released the AESO’s May 2016 Renewable Electricity Program Recommendations report (AESO Report) and adopted its recommendations as the REP.

Speaking at the Canadian Wind Energy Association’s annual conference, Minister Shannon Phillips claimed that the REP would inject some CA$10.5 billion into the Alberta economy by 2030 and create 7,200 jobs. The policy is to be implemented through enacting a Renewable Electricity Act in late 2016.

(a)  The REP payment mechanism: Loosening the “collar”

The REP aims to incent the addition of 5,000 MW in installed renewable generation by 2030 through a series of AESO-administered auctions. As described by the AESO, the “[w]inning bidder bids a price that is, in essence, its lowest acceptable cost for the renewable project the bidder plans to advance.” Successful bidders are awarded the right to guaranteed per-MWh prices for 20-year terms via “top-up” support payments enshrined in a RESA.

The RESA payment mechanism, financed by carbon revenues from large industrial emitters, operates as a so-called “Contract for Differences.” To compensate for low Alberta power market prices relative to renewable costs, RESA payments add to the generator’s market revenues and recede as the market price rises toward the generator’s bid price. If the market price exceeds the generator’s bid price, the generator pays its above-bid revenues to the government.

Interestingly, this “indexed” approach was criticized in the November 2015 Climate Panel report on the basis that it would remove market price–based incentives for higher-value (rather than simply higher-capacity) power projects and “likely trigger a land rush for the best wind resources in the province.”

The AESO Report, on the other hand, indicates the opposite concern with the Climate Panel’s CA$35/MWh support “collar”—noting that consulted lenders were of the view that it left power projects unfinanceable. The AESO expects the RESA’s “uncollared,” indexed approach to attract more extensive bidder interest by offering greater revenue certainty to developers (and by placing price risk with Alberta). The likely result, in the AESO’s estimation, is a more competitive auction featuring lower bid prices.

(b)  The 2017 REP bid process

Alberta has indicated its intention to stage and complete its first REP procurement in 2017. For the AESO’s first round, qualifying projects must:

  • be based in Alberta;
  • be new or expanded (existing projects are not eligible);
  • be 5 MW or greater in size;
  • meet Natural Resources Canada’s definition of a “renewable” source;
  • connect to existing transmission or distribution infrastructure; and
  • be operational by the end of 2019.

The requirements of an existing grid connection and a 2019 in-service date may constrict the 2017 bidder pool. In particular, the AESO Report itself acknowledges the challenges developers may face in obtaining the requisite regulatory approvals in time to energize in 2019.

The auction process is to follow three stages, each monitored by an appointed “Fairness Advisor”:

  • Request for Expressions of Interest (REOI): in which the AESO has the opportunity to attract and gauge interest in the auction and receive feedback (4-6 weeks);
  • Request for Qualifications (RFQ): in which eligibility requirements are released and bidders submit their qualifications (including in respect of project eligibility, financial strength and capacity, and construction and operations capability), and a non-refundable “Pay-to-Play” fee is paid by participants (4-6 months); and
  • Request for Proposals (RFP): in which qualified bidders provide security for their bids, make final, binding offers and a winning bidder is selected (2-3 months).

The auction process will be “fuel-neutral”; the AESO is not setting quotas for, or otherwise favouring particular sources. Notably, for the first auction, there is also no provision for crediting Aboriginal or community aspects of a project, as in Ontario’s FIT programs, and as was contemplated by the Climate Panel. The AESO Report instead insists that qualified bidders strictly “be selected on based on lowest price (subject to any affordability ceiling).”

The government has indicated that stakeholder engagement on the 2017 auction’s draft commercial terms will begin on November 10, 2016.

Does the energy-only market have a future?

Since Ontario’s foray into procuring contracted, renewable forms of generation began in 2004, the share of the province’s generation under contract—without exposure to the market price—has risen to 65 percent, according to data from a 2015 Independent Electricity System Operator (IESO) report. Many commentators have described Ontario’s market as a “hybrid” system, characterized by high levels of policy intervention, steeper costs and the effective abandonment of market price as a generation investment signal.

The introduction of market price–insulated generation envisioned by the REP promises, at least at this juncture, to be more incremental than Ontario’s sweeping example. The Climate Plan and AESO Report both contemplate the maintenance of Alberta’s wholesale market system and prioritize, in express terms, cost containment. The increasing price-competitiveness of renewable sources, too, may cushion the cost increases seen in early-adopting jurisdictions. Finally, as noted by the Climate Panel, Alberta continues to reap the benefit of an abundant, low-priced gas supply in transitioning away from coal.

Notwithstanding this, the eligibility of generators for RESA payments—especially given the low market prices and rising costs of the current environment—may itself “result in other generators demanding the same treatment (i.e. some kind of guaranteed revenue stream),” as the AESO acknowledges in its report. Elsewhere, the AESO Report presents a grim diagnosis for non-renewable investment, noting that “there has been a significant erosion of the support for investing in the energy-only markets in Alberta (and elsewhere) given [that] market and policy is undermining confidence.” It remains to be seen whether the REP’s policies, as in other places, signal a broader trend away from energy-only markets; are themselves overtaken by political opposition in a contested election; or find their place in a market framework that has, to date, proven adaptable to Alberta’s ever-changing climate.

This post was co-authored by Joseph Palin and Bernard Roth, Partners in Dentons’ Calgary office.

Alberta unveils Renewable Electricity Program: The beginning of the end for the energy-only market?

Polish Green Certificates Held by the Commission to Be Compatible State Aid: a Curious Story Comes to an End

On 2 August 2016, the Commission issued its long-awaited and precedent-setting decision in a case involving Polish green certificates issued to producers of energy from renewable energy sources (RES), following complaints filed as from 2013 in respect of co-firing and hydropower technologies. The Commission concluded its proceedings, extended since then into all RES technologies, at the preliminary examination stage, deciding that the green certificates did involve State aid. However, the Commission held that that aid was compatible with the internal market and decided not to raise objections.

The programme reviewed by the Commission was essentially based on certificates, shaped by the national legislation to be tradable in the market. They were issued to energy producers in respect of the RES energy they generated. Polish laws also required certain businesses to acquire these certificates up to certain levels (quotas), or instead pay a penalty fee, generally used by the authorities to fund other environmental investments. Only one other benefit was offered to the RES producers – selected utilities had the public duty to offtake RES-generated electricity at an average wholesale market price calculated and published annually by the National Regulatory Authority, while RES producers were free to sell their electricity to purchasers of their choice. In particular, no feed-in tariff or guarantee of the green certificates price was provided.

As long as the penalty fee, fixed by the authorities, was in excess of the green certificates price, the committed entities tended to acquire the certificates providing the RES energy producers with cash flow to supplement the proceeds from RES sales and to assure the bankability of RES projects. The support scheme did not discriminate between RES producers; intensity of support measured in certificates issued per MWh of generated RES electricity was exactly the same for any eligible technology. However, due to the open nature of the certificate system, over time the supply of certificates exceeded statutory quotas and the market for green certificates proved to be volatile. In the absence of any specific intervention from the government, prices declined over time, leading to levels currently considered by RES producers to be unsatisfactory, if not unsustainable.

Under these circumstances the Commission’s decision is of obvious importance for the Polish energy market, which had been awaiting the Commission’s conclusions on the case with some concern. Admittedly, it had been common to believe (for various reasons ranging from technical arguments to policy considerations) that the Commission’s decision would eventually be positive. However, the lack of a formal act terminating the Commission’s proceedings did appear as an impediment and, in particular, had tangible detrimental effects on various transactions involving Polish energy assets. It also added to a variety of other measures, regulatory or financial, recently implemented by the Polish authorities and perceived by part of the RES industry as having a telling harmful impact on their projects.

However, the Commission’s decision is interesting for a number of other reasons, which will only be outlined below.

The protection of legitimate expectations is obviously one of the fundamental principles of the EU legal order and, as such, it has also been held as immensely relevant to State aid matters. In particular, the EU courts made it clear that an unexpected turn in the Commission’s approach towards a particular State aid issue, going against a sufficiently clear and unambiguous line of earlier decisions, cannot result in the recovery of aid from the beneficiaries. As the Commission’s track record indicates (see for instance the Commission’s decision of 2 August 2004 in State Aid implemented by France for France Télécom) in manifest cases the Commission itself has been as reasonable as to rule, where it experienced such a radical change of mood, that its new approach would not apply to the detriment of beneficiaries in receipt of aid previously granted.

Poland introduced its green certificates system without a prior notification in 2005, whereas in the preceding years the Commission explicitly held various similar aid programmes not to qualify as State aid at all. The Commission made it clear inter alia in the decision on the green certificates granted in the UK (N 504/2000 – United Kingdom – Renewables Obligation and Capital Grants for Renewable Technologies), Belgium (N 14/2002 – Belgique – Régime fédéral belge de soutien aux énergies renouvelables) or Sweden (N 789/2002 – Sweden – Green certificates). In addition, outside the formal procedures the Commission officials also provided certain parties from other Member States, upon their request, with comfort letters reiterating that no aid would be found in case of the green certificates available in their respective jurisdictions. The Commission’s approach was largely inspired by the PreussenElektra judgement, although the latter concerned feed-in tariffs and not green certificates. However, that ruling indeed suggested that the award to RES producers, through national legislation, of the option to sell their output to mandatory purchasers does not engage any public funds and, consequently, does not constitute State aid either.

One could observe that over time, and in light of new matters submitted to the Commission’s appraisal (such as the emission allowances), the Commission became uncertain whether its earlier approach towards the green certificates was truly valid. Case law evolved likewise, including through cases such as Essent Netwerk Noord and Others (C-206/06), decided upon on 17 July 2008 by the Court of Justice of the European Union. The judges made a distinction from the PreussenElektra case in ruling that the mere fact of a publicly owned company being charged under national law with collection of funds and subsequently with the disbursement of payments from these funds to certain energy producers allowed for the imputation of these funds as originating from the State.

The Commission’s deliberation process meandered into the decision of 13 July 2011 in the Romanian green certificates case (State aid SA. 33134 2011/N – RO – Green certificates for promoting electricity from renewable sources). The decision is quite curious in that that the Commission discussed in more detail the arguments for both the existence and non-existence of aid in the green certificates systems, but eventually refrained from taking “a definitive position as to the existence of aid”. For the avoidance of doubt, the Commission made these comments despite there being no prior amendment in the Commission’s environmental guidelines, not to mention EU laws that would alter the assessment of the State aid implications in green certificates. In any event, the Commission eventually approved the Romanian green certificates system based on the compatibility of the (potential) aid with the internal market. However, taking into account the rather vague and discursive wording of this decision, as well as the apparent absence of any subsequent decisions dealing specifically with green certificates outside Romania, one might wonder whether the Commission’s decision in the Romanian case could indeed be taken as constitutive of a definite change in the Commission’s practice. The Commission was yet to strike the final chord in the green certificates crescendo.

Under these circumstances the Polish authorities were rather discontented to learn of complaints claiming the Polish green certificates to qualify as State aid (incompatible with the internal market due to the alleged overcompensation inherent in the scheme at hand) and even more of the Commission’s view confirming that the scheme may indeed involve State aid. In that regard the Commission did not seem receptive to any arguments based on its earlier practice and proved determined to rule on the compatibility of the programme despite any such concerns. Also the breakthrough judgment of the Court of Justice in Vent De Colère and Others (C-262/12) dealing with feed-in tariffs, believed by many to undermine the PreussenElektra jurisprudence to a great extent, came to the aid of the Commission in that regard as it imposed a rather extensive notion of public resources in the context of public support schemes applied in the energy sector.

It was under these circumstances that the Polish authorities, albeit contesting the Commission’s new view on the existence of aid in green certificates systems, reasonably focused on demonstrating the compatibility of the scheme and, in any event, the Commission’s decision turned out to be positive. Still, in the event of the Commission taking a negative decision in the Polish RES case, one could expect the rather plausible allegations of the Polish authorities (or of private claimants) of a breach of the legitimate expectations inferred from the Commission’s earlier decisional practice.

The Commission’s positive decision is currently rather unlikely to be challenged as far as the existence of aid is concerned and may thus be expected to stand out as a milestone in the Commission’s State aid practice in the field of energy. Therefore, most likely, we would not have the opportunity to see whether the legitimate expectations defence would be raised in litigation before EU courts and how it would be tackled by the Commission and received by the Court. The fact remains, however, that retroactive adjustment in the Commission’s practice concerning green certificates could just raise the judges’ eyebrows and warrant the annulment of the Commission’s decision. In addition, even though the decision is likely to remain uncontested in respect of the existence of aid, the legitimate protection argument could nonetheless resurface in  private enforcement cases.

On a practical note, the Commission’s decision in the Polish case seems to put an end to the debate on State aid classifications of green certificates, and it should also be taken into account in that capacity in any outstanding procedures pertaining to similar instruments (such as the Polish CHP certificates case still pending at the date of this entry). It may also impact on the identification of State aid in various instruments based on free-of-charge awards of specific benefits or entitlements – in the energy sector or well beyond it.

The article was originally published on the StateAidHub 14 September 2016 http://www.stateaidhub.eu/blogs/stateaid/post/7171

Polish Green Certificates Held by the Commission to Be Compatible State Aid: a Curious Story Comes to an End

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

IPP procurement programme framework in South Africa

In 1998 the Government of South Africa indicated that it is an objective of the State to encourage the entry of multiple players into the generation market. This would ensure both diversification and security of electricity supply.

In 2003, a White Paper on Renewable Energy was approved in South Africa in terms of which it was stated that a target of 10,000GWh of energy is to be produced from renewable energy sources such as biomass, wind, solar and small-scale projects by 2013. Since 2011, independent power producer (“IPP”) procurement programmes have been conducted with great success in South Africa, and it is likely that the Department of Energy will continue relying on these programmes to procure electricity from IPPs. This has attracted many international and local private project developers and investors to South Africa.

In this blog post we provide an overview of the IPP procurement programme framework in South Africa.

Background

Eskom, a state-owned utility company, currently generates about 95% of electricity used in South Africa.

In line with the objectives of creating efficient, effective, sustainable and orderly development and operation of electricity supply infrastructure in South Africa, the Electricity Regulation Act 4 of 2006 (“Electricity Regulation Act”) was enacted. The Electricity Regulation Act provides that the Minister of Energy may publish determinations for new generation capacity.  In these determinations, the Minister can specify the amount of new generation capacity required to ensure the continued uninterrupted supply of electricity, the types of energy sources from which this electricity must be generated and the procurement procedure for such new generation capacity.

The Electricity Regulations on New Generation Capacity GNR.399 of 4 May 2011 (GG: 34262), published under the Electricity Regulation Act (“Regulations”), further provide that the  abovementioned determinations must set out whether the new generation capacity will be established by an IPP and who will be responsible for the procurement of the new generation capacity. These Regulations do not apply to the purchase of new electricity generation capacity and electricity by persons other than organs of state.

These Regulations also specify that the Minister of Energy must develop an Integrated Resource Plan (“IRP”) together with the National Energy Regulator of South Africa to determine long and medium-term plans for the provision of clean, reliable and cost-effective electricity. The Integrated Resource Plan was launched in 2010 and updated in 2013 (see http://www.doe-irp.co.za/content/IRP2010_updatea.pdf). This provides for a twenty year projection of electricity supply in South Africa and stipulates that 40% of South Africa’s electricity must be generated from renewable sources. The Minister of Energy issues determinations based on the new power generation requirements in the IRP.

In 2012, the Minister made determinations for the procurement of electricity from:

On 18 August 2015, the Minister of Energy published a determination for the Department of Energy to procure electricity from renewable resources.  This specified that the electricity will be procured from IPPs through one or more IPP procurement programmes, tendering processes, direct negotiations with one or more project developers or other procurement procedures.  In December 2015, a determination in respect of nuclear energy was made (see http://www.gov.za/sites/www.gov.za/files/39541_gon1268.pdf)

The REIPPP Programme is generally regarded as being one of the most successful public-private partnership initiatives in Africa and the Department of Energy refers to it as its flagship programme.

According to the “Overview of the IPP Procurement Programme” published by the IPP Office on 31 March 2015, the REIPPP Programme has resulted in the investment of approximately $14 billion in South Africa’s renewable energy sector, of which approximately 28% constitutes foreign direct investment.

Overview of IPP Procurement Programmes

Under IPP procurement programmes a competitive tender process is followed. This is structured in rolling bid-windows which allows for continued participation.

The exact bid rules for each IPP procurement programme depends on the request for proposals issued in respect of that programme.  However, generally the bid rules relate to (i) commercial, legal, financial and technical requirements, and (ii) socio-economic development criteria.

The socio-economic development criteria aim to broaden the positive impact that the IPP procurement programme will have, particularly in the area where projects will be undertaken by successful bidders.

The socio-economic development criteria include the following.

  • Local Ownership – Generally, a certain percentage of the project must be owned by South Africans. Under the REIPPP Programme of 2012, 40% of each project was required to be owned by South Africans and 2.5% of each project was required to be owned by the local communities. Local communities would normally hold their ownership through community trusts or Communal Property Associations. Under the Coal Baseload IPP Procurement Programme of 2012, 51% of each project was required to be owned by South Africans.
  • Socio-Economic Development – Bidders may be required to propose socio-economic development projects that it will contribute to if the bid is successful. Under the REIPPP Programme of 2012, the proposed socio-economic development projects varied from education, social and welfare, health care, enterprise development and infrastructure projects. Successful bidders are required to contribute a minimum of 1% of their revenue to the Socio-Economic Development projects and to submit quarterly reports to the Department of Energy on the initiatives they have engaged in.
  • Local Content – Successful bidders are required to spend a certain percentage of the project value in South Africa.

The 2015 Determinations

As indicated above, the Minister of Energy published a number of determinations on 18 August 2015.  The table below provides a summary of the amount of electricity to be procured and from which sources such electricity can be generated under each of these IPP procurement programmes.

  Gas IPP Procurement Programme 2015 Cogeneration IPP Procurement Programme 2015 Renewable Energy IPP Procurement Programme 2015
Generation capacity needed 3,126 MW 1,800 MW 6,300 MW
Source types
  • Natural gas
  • LNG
  • Coal bed methane
  • Synthesis gas
  • Shale gas
  • Any other gas type or source
  • Waste heat or furnace off gas
  • Simultaneous generation of electricity and useful thermal energy from a common fuel source
  • An energy source which is a co-product, by-product, waste product or residual product of an industrial process and/or sustainable agricultural or forestry activity
  • Concentrated solar power
  • Wind
  • Solar photovoltaic
  • Biogas
  • Biomass
  • Landfill gas
  • Small hydro (<40MW)
  • Small projects (<5MW)

The IPP office postponed the bid submission date for bids pursuant to the 2015 Cogeneration IPP Procurement Programme pertaining to its 1,800MW generation capacity from 1 October 2015 to 11 November 2015. The successful bidders of this programme have not yet been announced.

Conclusion

South Africa has an energy shortage and is required to substantially increase its generation capacity in an environmentally sustainable manner. The REIPPP Programme has been able to provide for additional energy to be fed into the grid within a reasonably short period of time. Following the success of the REIPPP Programme, the Minister of Energy has published determinations for electricity from other sources to be procured by IPP procurement programmes and has published a determination for further electricity to be procured from renewable sources.

In addition to ensuring additional generation capacity, the IPP procurement programmes will also increase the entry of multiple players in the generation market.

IPP procurement programme framework in South Africa

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

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

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

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

Some background

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

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

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

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

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

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

Headline proposals

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

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

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

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

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

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

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

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

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

Degression

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

The Consultation proposes:

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

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

Indexation

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

Overall cap

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

This is because DECC further proposes:

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

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

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

Other points

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

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

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

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

The good news?

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

What next?

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

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

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

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

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

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

Levellling the playing field? UK Government reduces effective of price of renewable power by £5/MWh

On 8 July 2015, George Osborne’s Summer 2015 Budget had little new to say about UK energy policy: extension of some North Sea tax reliefs, a review of energy efficiency taxation, repetition of existing commitments to seeking a UN climate change deal at Paris later this year.  However, one measure stood out as an unwelcome surprise for generators of renewable electricity.  From 31 July 2015, suppliers who sell “green” power to business users will have to pay the same “climate change levy” (CCL) of £5.54/MWh as they do when supplying “brown” power from coal, gas or nuclear plant.

The CCL is a tax on business and public sector energy use.  The general rule is that supplies of electricity to non-domestic customers are subject to a levy of £5.54/MWh.  (There are separate or additional rates for supplies of other “taxable commodities” such as coal and gas.)  But electricity generated from renewable sources is exempt.  Generators of such electricity receive “levy exemption certificates” (LECs) from Ofgem which entitle suppliers to claim relief on the tax when they supply the associated power.  As a result, when renewable generators sell their power to suppliers under power purchase agreements (PPAs), part of the payment which they receive from the supplier for each MWh of power that they sell is made up of a proportion of the value of the associated LEC to the supplier.

Brief details of the change announced in the Budget are set out in a policy paper from HMRC.  The removal of the exemption is justified on the grounds that it will contribute to “fiscal consolidation” and “maintain the price signal necessary to incentivise energy efficiency”, and that a third of the value of the exemption (£3.9 billion over the life of the current Parliament) goes to supporting “renewable electricity generated overseas” (possible sub-text: “and those pesky EU single market rules might make it hard for us to stop overseas projects receiving LECs without also removing the entitlement from domestic ones”?).  HMRC also suggest that the value of LECs will be “negligible by the early 2020s, when the supply of renewable electricity will exceed CCL eligible business demand for it”, but even if that is so, it is not clear why it justifies scrapping LECs now, while they are still worth having.

The Budget indicates that there will be some transitional provision: “There will be a transitional period for suppliers, from 1 August 2015, to claim the CCL exemption on any renewable electricity that was generated before that date. The government will discuss the details of this transitional period with stakeholders over the summer and autumn, to determine an appropriate length for it.“.  The relevant legislation will be included in the Summer Finance Bill 2015 and the Finance Bill 2016.

However, the key point is that within a few months, all existing and future renewables projects will be deprived of a small but significant element of their anticipated revenue, and the suppliers who buy their power will have one less reason to purchase renewable power.  Some projects may find that the reduction in the rate of corporation tax, also announced in the Budget, offsets, or helps to offset, the reduction in revenue.  But for projects in the early stage of their operating lives that are on relatively low rates of Renewables Obligation or Feed-in Tariff support, there is likely to be an appreciable impact.  Moreover, the removal of LECs is one of a number of recent changes that may make renewable PPAs less attractive.  These include the shift from the Renewables Obligation to CfDs – admittedly partly counterbalanced by the backstop PPA or “offtaker of last resort” regime – and Ofgem’s decision to increase significantly the imbalance prices that suppliers can be exposed to as a result of contracting with intermittent generators.

The good news is that removing renewable generators’ entitlement to LECs will help to reduce the deficit.  The Government’s estimates of the impact of the measure show a positive impact on annual tax revenues of £450 million in 2015/2016 rising steadily to £910 million in 2020/2021.

Behind these fairly large increases in Exchequer revenues lie some significant negative effects on individual projects.  Shares in Drax fell substantially on the announcement and the company indicated that the change could reduce its 2016 earnings by £60m.  It is also possible that projects whose bids set, or were close to, the clearing prices in the first auction of Contracts for Difference (CfDs) may feel the loss of LECs if they included LEC revenues in the financial modelling assumptions for their bids.

The LEC change comes on top of the Government’s announcement of early termination of the Renewables Obligation for onshore wind and suggestions by the Competition and Markets Authority in the summary of its provisional findings on competition in GB energy supply markets that even the competitive allocation process that was used by DECC to allocate CfDs earlier this year may be too generous (in reserving particular “pots” of funding to specified technologies).  While they wait to see what allocation of funding will be made available for new projects in the next CfD round, and when it will take place, renewable generators are likely to want to spend some time reviewing the Change in Law provisions in their existing PPAs (or even CfDs) to see how the loss of LECs affects them.

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Levellling the playing field? UK Government reduces effective of price of renewable power by £5/MWh