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

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

Two points are worth emphasising here.

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

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

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

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

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

In November 2015, the Supreme Court took the opportunity to review and recast the English law on penalties, in Cavendish Square Holding BV v Talal El Makdessi [2015] UKSC 67.  The decision has been of particular interest to the oil and gas community, where the enforceability of JOA forfeiture provisions has long been the subject of debate.

The Cavendish ruling was welcomed by English lawyers, coming as it did some 100 years after the previous leading authority, Dunlop Pneumatic Tyre Co Ltd v New Garage and Motor Co Ltd [1915] AC 79.  In the intervening period, English case law had sought to refine the penalties test, with results that were sometimes helpful and at other times confusing.  The result was, according to the Supreme Court, “an ancient, haphazardly constructed edifice which has not weathered well“.

Before Cavendish, any analysis of whether a clause was a penalty would likely have started with Lord Dunedin’s four “tests” from the Dunlop case and his focus on whether the sums payable amounted to a genuine pre-estimate of loss or a deterrent.  Post-Cavendish, the test is now clearer.  The key question is whether the relevant clause is a secondary obligation and, if it is, whether it is out of all proportion to any legitimate interest of the innocent party in its enforcement.

So, the first task is to establish if the obligation is a primary obligation or a secondary obligation.  A primary obligation would, for example, be an obligation to pay for services (even if a part of that payment is contingent on future behaviour, as it was in Cavendish) provided under a contract; a secondary obligation would be an obligation to pay liquidated damages on breach.  Only if the clause is a secondary obligation can it be a penalty, as the English courts will not interfere in the parties’ original commercial bargain.

The second task is then to investigate the legitimate interest of the innocent party in the enforcement of the clause.  In Cavendish, for example, this focused on the interest of the buyer in ensuring that the seller adhered to certain restrictive covenants to ensure that the goodwill in the value of the company’s shares was preserved.

JOA forfeiture provisions take many forms.  However, most operate on the basis of certain key principles.  First, they apply to circumstances where a contractor has failed to pay its share of costs when due.  Second, they require the other contractors to pay the defaulting contractor’s share of costs, pro rata to their participating interests.  Third, where the default remains unremedied, the defaulting contractor is required to assign (or “forfeit”) some or all of its participating interest to the non-defaulting contractors.

Whether such provisions amount to primary obligations under the JOA will be determined by the wording used.  Generally, those we have seen more naturally fall within the category of secondary obligations.  However, the legitimate interest of the non-defaulting contractors will be similar across most JOAs; the continuity of the operations and compliance with their obligations to the Government that has granted them rights in the given contract area.  The non-defaulting parties will argue with some force that these legitimate interests justify the partial or complete exclusion of a party that is unwilling to bear its share of costs, particularly where the innocent contractors have had to bear those costs themselves.

Whether the forfeiture provisions are proportionate to these legitimate interests will depend on their precise terms and, importantly, the commercial context.  Some commentators have suggested that it may be easier to argue that forfeiture is proportionate where costs incurred are relatively low and the prospects for the contract area uncertain, for instance during the exploration phase of operations.  This is one reason for the range of remedies often to be found in JOAs, where mandatory assignment and withdrawal provisions may be accompanied by buy-out and withering interest options.

It remains to be seen to what extent Cavendish has affected the enforceability of JOA forfeiture provisions.  Whilst the Supreme Court’s focus on legitimate interests over genuine pre-estimate of loss or deterrence is undoubtedly helpful for parties seeking to enforce such provisions, it may be argued that English case law had already been moving in that direction.  More recent case law had, for example, tended to focus on the commercial justification for the sums payable; the legitimate interests test is arguably an extension of this.  Non-defaulting contractors would likely have deployed the same (persuasive) arguments in support of a commercial justification test as they now would in support of their legitimate interests.

Further, two English law principles that are key to analysing JOA forfeiture provisions were established long before Cavendish.  The first is that, where a contract has been negotiated by properly advised parties of comparable bargaining power, there is a strong presumption that they are the best judges of what is legitimate and that the court should therefore not interfere (Philips Hong Kong Ltd v Attorney General of Hong Kong (1993) 61 BLR).  In the sophisticated world of oil and gas exploration and production, the vast majority of contracts will meet this description.

Second, Lord Dunedin made clear in Dunlop that the analysis of whether or not a clause is a penalty must be carried out at the time the contract was entered into, not at the time of breach.  In addition, he emphasised that the fact that it may be difficult to estimate what the true loss would be is no obstacle to enforceability (and may, indeed, be a reason to uphold the parties’ original bargain).  In JOAs, the loss suffered by the non-defaulting contractors as against the value of the interests to be forfeited by the defaulting party may well be difficult (if not impossible) to estimate at the time the JOA is entered into, which may help persuade a court to uphold the terms agreed.

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.

 

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

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

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

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

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

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

 

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

Iran is said to be targeting an increase in oil production from 3.85 to 4 million barrels per day by the end of 2016. Iran is also hoping to start export of a new heavy oil, called West Karun, and which is expected to compete with Iraq’s Basra Heavy crude, which has gained a significant market with US and Asian refiners since its launch in 2015.

Iran’s new upstream contract, the Iran Petroleum Contract (IPC), was delayed by parliamentary amendments but is now scheduled for launch in January 2017. The State-owned National Iranian Oil Company (NIOC) has already signed up an IPC with local firm, Persia Oil and Gas Development Company, which is one of eight Iranian contractors authorised to team up with international joint venture partners. Whilst Iran’s production costs may be rock bottom, foreign investment (and currently foreign exchange) is needed to deliver scale and speed of development.

NIOC (on behalf of Iran’s Ministry of Petroleum) has published its “Pre-qualification Questionnaire for Exploration and Production Oil and Gas Companies,” to be completed by 19.11.16 in order for NIOC to publish a “Long List” of qualified applicants on 7.12.16. This list is intended to be valid for two years as a pre-requisite for participating in upstream tenders. NIOC intends to then invite a short-list of qualified applicants from the long list, depending on project type (Short List).

Long List applicants will be scored according to typical technical and financial criteria but with some additional emphasis seemingly echoing NIOC’s objectives, including “scale” and “internationality”. The greatest score (25%) is allocated under the heading “Reliability” to credit ratings. Whilst it seems unusual to delegate financial capability diligence simply to reliance on a third party credit rating agencies, it does reduce the internal resources needed to sift financial data. That said, a number of those with credit ratings (and by definition, public equity or debt) may not yet have the appetite for Iranian investments, whilst those privately funded entrepreneurs and companies with strong balance sheets, may not seemingly participate, assuming that NIOC doesn’t choose to deal with non-compliant applicants.

“Scale” is assessed in terms of production rates and wells drilled over the last three years, with technical capability assessed over the same period and broken down into experience type including conventional and fractured operations, and improved and enhanced oil recovery. Choosing the last three years of oil pricing where some operations may be moth-balled etc. may be significant, but given that it is unclear as to how applicants may be assessed competitively, this is perhaps academic, provided a minimum threshold is demonstrated.

“Internationality” is judged against an “applicant’s headquarters’ business and/or registration place” which is seemingly designed to allow some flexibility to avoid being disadvantaged by a tax headquarters and otherwise to make the best of an organisation’s international operations, and possibly from more than one headquarters, if one takes a literal interpretation of the punctuation.

For the purposes of the Short List, applicants are “requested” to specify their “priorities and interested fields” and whether they wish to act as operator or non-operator. This clearly allows room for judgement versus competitors as to whether applicants would wish to share their commercial position at the outset.

It seems likely that most of the credit-rated applicants who would qualify, are already known to NIOC / have registered their interest more or less formally. The collation of extra data should enable NIOC to take into account preferences, but to grade applicants and to allocate tender opportunities in a manner perceived as transparent and which tends to avoid the dominance of any particular constituencies. Whilst the application of such process could be regarded as a short-term disincentive to some with an incumbent position, it could also be used to justify the favouring of incumbents, safe in the knowledge that the market was tested first. Otherwise, such process is likely to be regarded more generally as a welcome codification of what is expected to be a hotly-contested new market for lower cost developments.

Efficiency dilemma

In common with other post Soviet countries, Ukraine suffers from very low energy efficiency and a high level of energy consumption in its economy. Key primary sources of energy are coal and natural gas (about 36 percent of the energy mix each), with nuclear power accounting for roughly 18 percent.[1]

The Ukrainian government has been aware of the efficiency issue for decades but has failed to make substantial progress. State officials felt no great incentive to take any meaningful active measures, as Russia always sold natural gas to Ukraine at low prices.

The mood changed dramatically in 2014 when the need for a long-term energy efficiency drive was made painfully obvious by the flare up of tensions between Ukraine and the Russian Federation. In particular, Ukraine’s northern neighbor tried to pressurize the new administration and the state-owned company PJSC “Naftogaz of Ukraine” into buying natural gas at much higher prices than previously. This kick-started the Ukrainian government into taking a number of sporadic energy efficiency initiatives, such as partial reimbursement of loans to households to replace gas boilers, special ESCO legislation in the public sector, and special tariffs for producers of heat from alternative fuel.

While these measures had some effect, they were soon deemed insufficient, and both public officials and civil society realized that a more systematic approach was required, in particular in terms of providing financing for energy efficiency measures in the district heating sector.

This culminated in late 2015 / early 2016 with the government proposing that an Energy Efficiency Fund be set up to create sustainable financing for energy efficiency activities in district heating and related areas. Discussions ensued, resulting in the Cabinet of Ministers of Ukraine adopting a formal ‘Concept for the Implementation of Mechanisms for Sustainable Financing of Energy Efficient Measures’ by Resolution No. 489-p of 13 July 2016. The Resolution paves the way for the regulatory framework needed to establish the Energy Efficiency Fund, as discussed below.

Savings opportunity

The Concept estimates that the country loses out to the tune of US$3 billion annually through the inefficient use of fuel and energy in district heating costs, meaning that some 60 percent of energy resources are wasted. Household energy consumption is running at 20,384 Mtoe, which is almost 33 percent of total consumption in Ukraine ‒ 58 percent of which is natural gas.

Ukraine burns on average 18.6 bcm of gas per annum to meet its district heating requirements. If Ukraine enjoyed EU levels of gas consumption efficiency, it would save up to 11.4 bcm annually (equivalent to 60 percent of Ukrainian imports). This could be achieved through the following measures: (i) thermal upgrade of buildings (up to 7.3 bcm); (ii) replacement of residential boilers (up to 1.7 bcm); (iii) boiler upgrades (up to 1.1 bcm); and (iv) pipeline upgrades (up to 1.3 bcm).

The intensity of individual energy consumption in Ukraine is two to three times higher than in western EU member states. To achieve a comparable level of energy efficiency, an estimated UAH 830 billion (approx. US$32 billion) would need to be invested in thermal upgrades of buildings. Disappointingly, only UAH 893 million (approx. US$34 million) was allocated for these purposes in the state budget for 2016–2017. Given scant resources in state and local budgets, sustainable financing of energy efficiency projects in residential buildings is possible only with additional funding from international financial and donor organizations.

Creating the Energy Efficiency Fund

The Ukrainian government believes the Energy Efficiency Fund will successfully attract external financial resources. It will be based on the principles of transparent and efficient use of available resources and on the model European approach towards cooperation between state and international financial organizations.

The Fund should start operations in 2017 (most likely full scope operation will start in April 2017, according to recent statements by government officials) and optimal results are expected to be achieved in a 15 year horizon. Key goals include: (i) a reduction in the consumption of natural gas forecast at 1.5 bcm annually, saving UAH 9.1 billion (US$350 million) annually and improving stability of the local currency and energy efficiency; (ii) reduction in direct subsidies (UAH 5 billion annually) and other breaks for consumers with respect to utilities payments; (iii) creation of a new market for energy efficiency measures; (iv) creation of up to 75,000 new jobs; (v) increased tax payments of up to UAH 10 billion; and (vi) a reduction in household bills, and increased investment by households in their own energy efficiency.

The government plans that, initially, the Fund will use existing mechanisms of support available under state and local budgets. According to official statements, UAH 800 million (US$31 million) has been allocated for the Fund, and up to US$110 million is expected from international partners for 2016-2017.

The Cabinet of Ministers of Ukraine expects to create the Fund directly as a state establishment, as proposed under the Bill: Law on Energy Efficiency of Buildings No. 4941 of 11 July 2016, planned to be voted on in November 2016. The Fund will act on the basis of a charter approved by the government.

It is expected that the Fund will, in particular: (i) reimburse part of the interest payable on loans (or part of loans) obtained by individuals, associations of co-owners of condominiums and ESCO companies for energy efficient measures related to residential households, public establishments and organizations; (ii) provide technical support (energy audit, technical and economic feasibility, etc.) for projects aimed at enhancing energy efficient measures of residential households, public establishments and organizations and heating supply buildings; (iii) provide proposals for state policy in the sphere of energy efficiency and related instruments; and (iv) perform other functions in accordance with its charter.

The Ministry of Regional Development and Municipal Economies of Ukraine is currently working on the structure of the Fund, and the government is expected to approve its internal structure (financing, staff, etc.) after consultations with all interested parties in October–November 2016.

[1] https://www.eia.gov/beta/international/analysis.cfm?iso=UKR

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.