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Aviation emissions – new global deal looks likely

Government officials are negotiating a market-based mechanism to reduce emissions in the international aviation industry. Ministers from over 190 countries have gathered at the International Civil Aviation Organization’s General Assembly in Montreal to discuss and vote on a draft resolution. If passed, it will be the first industry-specific global market-based measure for CO2 emissions.
The prospects of achieving resolution are good. So far, 55 countries, including the US, China and EU member states have indicated their support for the proposal and agreed to sign-up for the initial voluntary stage. However, some states with large aviation emissions have yet to confirm their agreement and the EU has questioned how effective the measure will be in combatting climate change. A deal is expected by the end of the Assembly on 7 October.
The proposal aims to prevent the growth of aviation emissions beyond 2020 levels by requiring airlines to offset emissions with carbon credits. The mechanism would take effect on a voluntary basis from 2021, and become mandatory in 2027 with exceptions for some states which are less developed or have low aviation emissions. The offsetting obligations will be based on the sector average emission growth, and later move to incorporate the actual emission growth of individual airlines.

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Aviation emissions – new global deal looks likely

Significant Developments in Canadian Energy – For the Month of July 2016

Conventional

  • July 26, 2016 – TORC Oil & Gas Ltd. entered into an agreement with Zargon Oil & Gas Ltd. to acquire light oil assets in southeast Saskatchewan. The acquisition includes 1,120 boe per day (roughly 95 per cent light oil and liquids) of producing assets for total cash consideration of $89.5 million, subject to customary closing adjustments.
  • July 13, 2016 – In response to industry requests, the Alberta government announced that oil and gas producers can apply to opt in to Alberta’ new Modernized Royalty Framework for wells that otherwise would not have been drilled. This represents a change to the previously announced schedule, which had the Modernized Royalty Framework slated to take effect January 1, 2017. The stated intent of this change is to allow producers to make new investments, or decide to keep investments in Alberta. Further discussion of the Modernized Royalty Framework can be found in previous Dentons articles, available here and here.
  • July 6, 2016 – Seven Generations Energy Ltd. (7G) reached an agreement to acquire approximately 30,000 bbls of oil equivalent of daily production, 155 net sections in the Montney play having 199 million boe in proved reserves from Paramount Resources Ltd. for approximately CAD$1.9 billion in total consideration consisting of cash, 7G shares and the assumption of a portion of Paramount’s debt. This acquisition will significantly expand 7G’s ownership in the Montney Nest liquids-rich natural gas play.

Midstream

  • July 18, 2016 – Husky Energy Inc. closed a transaction to create a new entity, Husky Midstream Limited Partnership, which will assume ownership of certain midstream assets in the Lloydminster region of Alberta and Saskatchewan. Husky received $1.7 billion in cash proceeds from the transaction, which will be applied to strengthening the company’s balance sheet.
  • July 15, 2016 – TransCanada Corporation announced the signing of a memorandum of understanding with four major unions and the Pipe Line Contractors Association of Canada for work on the Energy East pipeline project. The MOU provides that thousands of the skilled pipeline trade jobs required to build the project will be awarded to members of the PLCAC and the four union partners, including the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada, Labourers International Union of North America, International Union of Operating Engineers and Teamsters Canada.
  • July 15, 2016 – Reuters, citing sources familiar with the situation, reported that Williams Cos. Inc. attracted at least seven bidders for the sale of its Canadian business unit, which could pay up to $2 billion for the acquisition.
  • July 14, 2016 – Devon Energy Corporation announced that it had entered into a definitive agreement to sell its 50 per cent interest in Access Pipeline to Wolf Midstream Inc., a portfolio company of Canada Pension Plan Investment Board, for consideration of CAD$1.4 billion

Alternative / Green

  • July 18, 2016 – Canada’s Energy minister, Catherine McKenna, announced that the Canada will implement a national price on carbon emissions by the end of this year. The federal government will publish an emissions reduction plan this fall that could include expanded, standardized emissions disclosure requirements for companies. Currently, the provinces are working on an agreement that could see the provinces implementing a mandatory carbon price. Not all provinces support this initiative, and the effect of the proposed federal provincial carbon price on existing provincial measures has yet to be determined.
Significant Developments in Canadian Energy – For the Month of July 2016

Energy Brexit: initial thoughts

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

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

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

Overall, our conclusions are not surprising.

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

Putting things in perspective

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

Common ground and policy continuity?

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

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

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

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

Sources of irritation

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

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

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

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

Back to the future?

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

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

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

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

Next, consider how the EEA works legally.

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

The EEA Agreement in action

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

It can take a long time to adopt some measures.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Nuclear options?

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

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

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

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

The Energy Community

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

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

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

Freedom and sovereignty

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

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

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

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

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

A special deal with the EU?

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

Non-EU / EEA law constraints imposed by international law

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

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

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

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

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

Closer to home

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

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

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

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

(Provisional) conclusions

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

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

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

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

 

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Energy Brexit: initial thoughts

Alberta’s Bill 20: Climate Leadership Implementation Act

The Alberta Government introduced Bill 20, the Climate Leadership Implementation Act, on May 24, 2016. The Bill proposes a carbon levy on fuel consumption and marks the Government’s first step towards executing Alberta’s Climate Leadership Plan. Additional legislation aimed at eliminating emissions from coal-fired electricity generation, capping oil sands emissions and reducing methane emissions is still pending. Currently, the Specified Gas Emitters Regulation remains in full force and effect.

Bill 20 proposes two new statutes, the Climate Leadership Act and the Energy Efficiency Alberta Act, while also making minor, corollary amendments to three existing pieces of provincial legislation. The proposed legislation passed its first reading in Parliament and will become law upon receiving Royal Assent.

Under the Climate Leadership Act, all fuel consumption—including gasoline and natural gas consumption—will be subject to a carbon levy to be effected through a series of payment and remittance obligations throughout the fuel supply chain. Commencing on January 1, 2017, consumers of fuel will pay levies at rates based on CA$20 per ton of carbon (e.g. 4.49 cents/litre for gasoline), with the carbon price increasing to CA$30 per ton on January 1, 2018 (6.73 cents/litre). There are certain exemptions from the carbon levy, including fuel used in the operation of a specified gas emitter and fuel used in farming operations. The Climate Leadership Act creates mechanisms for the assessment of the levy and the enforcement of payment, while providing that directors can be held jointly or severally liable for payment if their corporation fails to remit the required carbon levy.

The revenue generated from the carbon levy will be applied to provincial climate change initiatives, while also producing rebates for qualified individuals and businesses. Initial estimates state that more than 60 percent of Albertans will be eligible for full or partial rebates.

The Energy Efficiency Alberta Act establishes a new Crown corporation, Energy Efficiency Alberta. The provincial agency will have a mandate to raise awareness among energy consumers, design and deliver programs related to energy conservation and small scale renewable energy systems, and to promote the development of an energy efficiency services industry. Energy Efficiency Alberta will consult with stakeholders and citizens to encourage a reduction in energy use and to raise awareness of consequences of energy consumption.

Amendments to the Corporate Tax Act will reduce the small business tax rate from three to two percent in order to allow businesses to adapt to the carbon levy, while amendments to the Alberta Personal Income Tax Act will provide for the eligibility and calculation methods pertaining to the Alberta Climate Leadership Adjustment Rebate. Finally, amendments to the Climate Change and Emissions Management Act broaden the accepted use and purpose of the Climate Change and Emissions Management Fund to encompass education initiatives and outreach programs.

The Dentons Climate Change group will continue to track and report on further legislation, including the pending regulations referred to above. If you wish to receive our Climate Change Newsletter please contact us.

This article was co-authored by Alex MacWilliam and Cameron Hughes, Partners in Dentons’ Calgary office.

Alberta’s Bill 20: Climate Leadership Implementation Act

Insolvency and energy insights: The Redwater decision

The Alberta Court of Queen’s Bench decision in Redwater Energy Corporation Re, 2016 ABQB 278, written by Chief Justice Neil Wittmann, clarifies that the provisions of the Bankruptcy and Insolvency Act (BIA) addressing the environmental liability of trustees render certain provisions of provincial regulatory legislation addressing wells and pipelines inoperative to the extent they conflict with the BIA.

This is a significant decision that will directly impact the conduct of oil and gas receiverships and bankruptcies in Alberta, and affect the position of secured creditors in those proceedings.

You can find Dentons’ commentary on this decision in our recent Insights publication found here.

Insolvency and energy insights: The Redwater decision

Daniels v. Canada: Métis and non-status Indians fall under Parliament’s legislative authority

On April 14, 2016, the Supreme Court of Canada (SCC) rendered its decision in Daniels v. Canada (Indian Affairs and Northern Development), 2016 SCC 12.

Members of the Dentons Canada LLP Aboriginal Law practice addressed the significance of the decision in their latest Insights post. You can find that post here.

Daniels v. Canada: Métis and non-status Indians fall under Parliament’s legislative authority

Significant developments in Canadian energy – for the month of March 2016

Conventional

  • March 9, 2016 – Encana Corporation is exploring the sale of more non-core assets in the United States and Canada that could net proceeds of approximately $1 billion. Encana is open to offers on all of its non-core assets including the Deep Panuke offshore gas field in Nova Scotia; its Horn River and Wheatland assets in Western Canada; natural gas assets in the Piceance Basin in northwest Colorado; its San Juan assets in New Mexico; and its Tuscaloosa Marine Shale assets in Mississippi and Louisiana.
  • March 21, 2016 – Bankers Petroleum Ltd., one of Albania’s largest foreign investors, said on Sunday it has agreed to be acquired by affiliates of China’s Geo-Jade Petroleum Corp. for C$575 million. Bankers Petroleum said it will be bought by firms owned by the Chinese oil and gas exploration and production company for C$2.20 per share. The Canadian company said its corporate and technical headquarters will remain in Calgary. The deal is subject to shareholder approval at a meeting before the end of May. Bankers Petroleum said the company will be delisted after the sale.
  • March 23, 2016 – SECURE Energy Services Inc. has closed its $150-million bought deal common share financing with a syndicate of underwriters. Net proceeds of the offering will be used to temporarily repay bank indebtedness, increase working capital and fund ongoing capital expenditure programs and acquisition opportunities. The focus of near-term potential acquisitions will be in the processing, recovery and disposal and midstream asset classes.

Unconventional

  • March 11, 2016 – Imperial Oil Limited has filed regulatory applications with the Alberta Energy Regulator to seek approval of a new in situ oilsands project on its Cold Lake lease area. The proposed Cold Lake expansion project will use solvent-assisted, steam-assisted gravity drainage technology to access a bitumen resource in the Grand Rapids formation with recoverable potential of approximately 550 million bbls of contingent resources, development pending, which is Imperial’s share before royalties.
  • March 24, 2016 – Renaissance Oil Corp. will likely be in the running when Mexico puts some of its shale oil and gas fields up for auction this fall, while others will be closely watching the process, as the country moves ahead with the next stage in its efforts to end the monopoly of state-owned Petroleos Mexicanos (Pemex). Renaissance Oil Corp. is the only Canadian-based oil and gas producer so far to have secured blocks as a result of the auction process that has been underway in the country.
  • March 22, 2016 – Suncor Energy Inc.’s acquisition of Canadian Oil Sands Limited (COS) has been completed following shareholder approval of an amalgamation agreement at a special meeting of COS shareholders Monday morning. Suncor, through a wholly owned subsidiary, acquired 76.75 million COS shares (representing approximately 15.8 per cent of the outstanding COS shares) and now owns 484.61 million COS shares (representing 100 per cent) of the issued and outstanding COS shares.

Midstream/Downstream

  • March 9, 2016 – The Canadian government announced that it will proceed with a pipeline safety law passed by its predecessor, one that makes Canadian companies liable for the clean-up costs of competitor pipeline firms in certain cases. The government will allow the Pipeline Safety Act, which incorporated a “polluter pays” principle on spill costs, to take effect in June as scheduled.
  • March 9, 2016 – Imperial Oil Limited has reached agreements with five fuel distributors in Canada to sell its remaining 497 company-owned Esso retail stations. Distributors purchasing the sites include Alimentation Couche-Tard Inc. for retail stations in Ontario and Quebec, 7-Eleven Canada Inc. for sites in Alberta and British Columbia, Harnois Groupe pétrolier for sites in Quebec, Parkland Fuel Corp. for sites in Saskatchewan and Manitoba, and Wilson Fuel Co. Limited for sites in Nova Scotia and Newfoundland. The sales are anticipated to close by year-end 2016, subject to regulatory approvals. Proceeds from the transactions are valued at about $2.8 billion.
  • March 10, 2016 – Veresen Inc. reported that the Cutbank Ridge Partnership approved the $930 million Saturn Phase 2 processing facility near Dawson Creek, B.C. It is the third major facility now under construction as part of the Veresen Midstream infrastructure development. Saturn Phase 2 is a fully contracted expansion to the recently constructed Saturn compressor station, and will add 200 mmcf per day of compression and 400 mmcf per day of processing, and significant inlet liquids and NGL handling facilities.
  • March 18, 2016 – TransCanada Corporation announced an agreement to acquire Columbia Pipeline Group, Inc., a Houston, Texas-based company that operates an approximate 24,000-kilometre network of interstate natural gas pipelines extending from New York to the Gulf of Mexico, with a significant presence in the Appalachia production basin. The aggregate transaction value is US$13 billion including the assumption of roughly $2.8 billion of debt.
  • March 18, 2016 – Paramount Resources Ltd. has entered into an agreement with a wholly-owned subsidiary of Pembina Pipeline Corporation for the sale of its Musreau Complex and related midstream assets for cash and other considerations of over $600 million. The midstream transaction includes the 50 mmcf per day refrigeration plant, the 200 mmcf per day deep cut plant, the 22,500 bbl per day condensate stabilizer, the amine facility and the gas sales pipeline connecting the Musreau Complex to the TransCanada Pipelines Ltd. meter station, as well as the majority of Paramount’s larger-diameter gathering system in the Musreau area. Also included in the midstream transaction are the site and engineering and design work for the future 06-18 gas processing plant.
  • March 21, 2016 – Canadian regulators extended by three months Petroliam Nasional Bhd.’s (Petronas) application to build a liquefied natural gas terminal on the B.C. coast so the Malaysian company can provide more information about the project’s environmental impacts. The extension came 750 days after the project’s original submission and four days before the deadline for a ministerial decision on the environmental impacts.
  • March 21, 2016 – Canada’s Environment Minister on Friday approved a liquefied natural gas export project proposed by Woodfibre LNG in British Columbia, after an environmental review found the project was “not likely to cause significant adverse environmental effects.” Environment Minister Catherine McKenna imposed numerous conditions on the project, including restrictions related to construction in or near fish habitat and additional consultation with Aboriginal groups, among other things. Woodfibre LNG, backed by Indonesian billionaire Sukanto Tanoto’s RGE Group, hopes to build its LNG export terminal outside the city of Squamish, north of Vancouver. The company has not yet made a final investment decision on the project.
  • March 24, 2016 – TransCanada Corporation is working with JPMorgan Chase & Co. to find buyers for more than $7 billion in assets to help finance its acquisition of Columbia Pipeline Group Inc., people with knowledge of the matter said. Assets for sale include a portfolio of U.S. Northeast merchant power plants and a minority stake in TransCanada’s Mexican natural gas pipeline business. The value of the combined assets is estimated to be $7.1 billion, according to Moody’s Investors Service.

Off-Shore

  • March 11, 2016 – Williams Partners L.P. has reached an agreement with Shell Offshore Inc. and Nexen Petroleum Offshore U.S.A. Inc. to provide deepwater gas gathering services to the Appomattox development, located 80 miles offshore from the nearest shoreline in Louisiana, in approximately 7,200 feet of water. Shell is 79 per cent owner in the Appomattox development and is the operator; Nexen is 21 per cent owner.

Alternative / Green

  • March 4, 2016 – Working together with the Canadian Prime Minister Justin Trudeau, Canada’s 10 provinces accepted the concept of putting a price on carbon but agreed the specific details could be finalized at a later date. The mechanisms for pricing carbon would take into account each province’s specific circumstances.
  • March 10, 2016 – The United States and Canada have agreed on joint steps to fight climate change, including cutting methane emissions from existing oil and gas industry sources and signing the Paris climate deal as soon as possible. Under the agreement, the U.S. Environmental Protection Agency will begin developing regulations for methane emissions from existing oil and gas sources immediately and “will move as expeditiously as possible to complete this process.” Environment Canada “intends to publish an initial phase of proposed regulations by early 2017,” and put in place national regulations in collaboration with provinces, territories, and indigenous groups.
  • March 11, 2016 – Alberta Energy Minister Margaret McCuaig-Boyd and the British High Commissioner to Canada Howard Drake have signed a UK-Alberta Low Carbon Innovation and Growth Framework. Building on already strong links, the framework will facilitate partnerships between Alberta and UK stakeholders that will: drive economic development, diversification, innovation and job creation; enhance collaboration on low carbon technology and innovation; and further develop UK-Alberta dialogues on energy and environmental policy and regulation.
Significant developments in Canadian energy – for the month of March 2016

Suspension of coal leasing

The United States Department of the Interior has announced a temporary suspension of coal leasing on public lands pending a comprehensive review of the federal coal program by the Bureau of Land Management (BLM).  Public lands currently account for approximately 40% of all coal production in the United States.

During the temporary suspension, BLM will not process or approve new coal lease applications.  The suspension does not halt ongoing production activities under existing leases or prohibit the approval of new coal leases on Native American tribal land.

The temporary suspension will impact a number of pending lease applications, and it is already receiving considerable attention in the media and in the Congress.  But the BLM’s comprehensive review of the federal coal program is likely to be even more important in the long run.

The comprehensive review will take the form of a Programmatic Environmental Impact Statement (EIS) prepared under the National Environmental Policy Act (NEPA), a document that will be available for review and comment by interested parties.  Among other things, the Programmatic EIS is likely to address the following questions:

  • How, where, and when should public lands be leased for resource extraction activities?
  • To what extent should coal produced on public land be used to support American energy needs?
  • Should rents and royalty rates charged by the United States account for the “social cost” of carbon?
  • To what extent should government leasing decisions account for the potential environmental impacts of resource exports?
  • How should climate change impacts be addressed in the federal leasing and environmental impact assessment process?

The importance of these questions (and the answers that will emerge in the EIS) extends far beyond federal coal leasing.  All stakeholders with an interest in federal land management and energy policy should take careful note of — and consider directly participating in — the BLM’s Programmatic EIS process.

Dentons’ award-winning Energy, Environment and Natural Resources practices specialize in helping project proponents, industry associations, financial institutions, and other stakeholders successfully navigate the Environmental Impact Assessment process and evaluate the strategic implications of federal agency decision-making.

Suspension of coal leasing

Reform of energy efficiency taxes – have your say

CRC, EU ETS, ESOS, Climate Change Levy – the alphabet spaghetti of overlapping environmental taxes, levies and reporting obligations on businesses grow every year.

Many think that the current system is too complicated,  and a distraction from improving energy efficiency. So it is good news that the Treasury is considering a much simpler system.

HM Treasury has released a consultation on reform of the energy efficiency tax landscape. The consultation is available here (https://www.gov.uk/government/consultations/consultation-reforming-the-business-energy-efficiency-tax-landscape) and closes on 7 November 2015.

The headline proposals are below.

Energy Consumption Tax

The Treasury proposes replacing the CRC Energy Efficiency Scheme and the Climate Change Levy (CCL) with a new single energy consumption tax (based on the CCL). Stakeholders are asked to comment on several issues, including:

  • How to best design a single tax to improve its effectiveness;
  • Should rates vary across businesses;
  • Whether different approaches are needed for different businesses.

Energy Reporting

The government is considering using the Energy Savings Opportunity Scheme (ESOS) as the primary tool for energy reporting. The consultation asks a number of questions on reporting, including:

  • Should reporting be mandatory;
  • Should reporting require board level approval;
  • Should reported data be publically available;
  • What data should be collected through the reporting scheme (e.g. GHG emissions, renewable energy proportion and actions taken to meet any audit recommendations)
  • Does a streamlined report enable market actors have access to transparent, reliable and comparable information in order to support financing and investment in efficient and low carbon measures.

Incentives

The Treasury is also consulting on incentives for energy efficiency and carbon reduction,  and the simplest way to enable businesses to access decarbonising incentives.

The results and corresponding reforms are likely to be announced in the 2016 Budget.

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Reform of energy efficiency taxes – have your say

The Offshore Safety Directive (6) – offshore operatorship

On 19 July 2015, a raft of legislative amendments and new regulations came into force implementing the Offshore Safety Directive (2013/30/EU) (OSD). The key regulations are the Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015 and the Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015. The application of the new regulations is phased in over a transitional period between 19 July 2015 and 19 July 2018.

The new regulations create new obligations, duties and liabilities for offshore licensees and the companies they appoint to carry out offshore operations. The changes do not represent a radical overhaul of the existing regime. However, the changes are important – especially in terms of the contractual relationships between oil companies, licence operators and appointed installation duty holders.

Exploration, production and services companiesOil rig and sheep would do well to scrutinise their existing arrangements in the light of the changes. They would also do well to ensure they carry out thorough contractual due diligence on proposed appointments in the light of the new regulations.

Here are some key points:

  • Consolidation of environmental and safety duties

One of the “structural” changes introduced by the new regulatory regime is to get rid of the old separation of environmental and safety duties.

Historically, environmental compliance on offshore platforms has been the responsibility of licensed operators, regulated by DECC; whereas safety has been the responsibility of “duty holders” appointed by the licensees under safety legislation, regulated by HSE. Accordingly, the appointed safety duty holders on offshore platforms were sometimes different companies from the licensed operators.

This is now changing. Under the new regime, a single appointed installation operator must be responsible for both environmental compliance and safety management at any one time.

  • New competent authority

There is a new consolidated competent authority regulating OSD matters, the Offshore Safety Directive Regulator (OSDR), made up of both HSE and DECC.

The Government decided against taking the opportunity to simplify the regulatory structure and create a single offshore regulator in charge of all aspects of both environmental and safety regulation for the industry. Rather, they have created OSDR as a joint HSE/DECC regulator to cover OSD issues; HSE and DECC will continue to exist as individual safety and environmental regulators, and will still have separate functions under individual permitting regimes.

  • New duties for offshore installation operators

In addition to the consolidation of safety and environmental duties, appointed installation operators will have a number of brand new duties which did not exist under the previous regime – at least as mandatory legal requirements. These new duties include the preparation and submission of a Corporate Major Accident Prevention Policy (CMAPP), and an obligation to produce a Safety and Environmental Management System (SEMS).

  • Financial provision and environmental liability

Licensees and operators have always been required to demonstrate adequate financial provision to deal with oil spills. However, the historic approach to financial provision for oil spills was arguably rather weak. (This is in contrast to the historic approach to decommissioning security – which has always been robust, and underpinned by a statutory liability regime under the Petroleum Act.)

For example, DECC had a power rather than a duty to check the financial resources of licensees and operators to cope with pollution incidents. Also, licensees and operators alike were required to demonstrate financial provision for pollution liability indirectly and at the regulator’s discretion, for example as a pre-requisite for obtaining operator approval or as a pre-requisite for approval for particular well operations. In other words, demonstrating financial resources to cope with major pollution incidents was not required by way of a direct legal obligation or pursuant to a standard licence condition – it was required by the regulator at its discretion.

By contrast, the system for ensuring that licensees have the resources to deal with any major pollution incidents has now been strengthened and formalised. The licensing authority (in practice the OGA, currently an executive agency of DECC which issues licences and supervises the activities of licensees) will have a specific duty as part of the licensing process to obtain details of and take into account a licensees’ financial capability; and there are new more robust requirements on licensees to demonstrate and maintain adequate financial provision to cover the costs associated with environmental incidents. There are also new (potentially problematic) rules requiring licensees, as distinct from their appointed operators, to be “financially liable” for remediating environmental damage.

Fire

The new regulations are significant. They are also unlikely to spell the end of what is a wider process of legislative reform in this area – driven by the Macondo incident. Tucked away near the end of the OSD (article 39) is a requirement on the EU Commission to report on the adequacy of existing legal liability regimes in Europe to cover compensation and liability for major offshore accidents. This is likely, in our view, to result in proposals for significant changes to the civil and criminal liability regimes applicable to offshore incidents. But that’s a subject for another blog post!

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The Offshore Safety Directive (6) – offshore operatorship