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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

On 30 November 2016, the European Commission officially unveiled the latest instalment of its ongoing Energy Union initiative, which will reform some of the central pieces of EU energy legislation.  Referred to in advance as the “Winter Package” (not to be confused with the rather more limited package released in February 2016), it has been published as the “Clean Energy for all Europeans” proposals and is the most significant series of proposals yet to emerge under the Commission’s “Energy Union” brand.  It will have far-reaching implications within and potentially beyond the existing EU single energy market.

There is a lot to consider in these proposals, and we will return to some of the issues they raise in more depth and from other perspectives in future posts. What follows is an overview and some initial thoughts from a predominantly UK-based viewpoint.

Important though it is, many of the Winter Package’s proposed reforms are evolutionary rather than revolutionary.  Some could even be criticised for lacking ambition.  The Commission’s proposals certainly provide opportunities for newer technologies such as storage and demand side response and for those seeking to make use of newer commercial models such as aggregation or community energy schemes, but all these groups are still likely to need to work hard in many cases to exploit the leverage that the new rules would give them.  It is interesting that what has been picked up most in early news reports of the Winter Package is the Commission’s move to end subsidies for coal-fired plant.  This is a significant step, but it is only one part of a complex and multi-layered set of draft legislative measures, and is one of the few instances in those measures of a provision that overtly tilts the playing field in favour of or against a particular technology in a new way.

The story so far

Let’s begin by reminding ourselves what Energy Union is about. The project is said to have five “dimensions”.  These are:

  • Security, solidarity & trust: the buzz-words are “diversification of supply” and “co-operation between Member States” – all informed by anxieties about over-dependence on Russian gas.
  • A fully-integrated internal energy market: going beyond the 2009 “Third Package” of gas and electricity market liberalisation measures (and their ongoing implementation through the promulgation of network codes) to achieve genuine EU-wide single gas and power markets.
  • Energy efficiency: using less energy can be hard, but it is the best way to meet environmental objectives and it can also be a significant source of new jobs and economic growth.
  • Climate action – decarbonising the economy: signing and ratifying the Paris CoP21 Agreement was the easy bit.  How is the EU going to achieve deep decarbonisation of not only its power but also its heat and transport sectors so as to meet its UNFCCC obligations?
  • Research, innovation & competitiveness: can European businesses still take the lead in developing technologies that will save the planet, and also make money out of commercialising them?

In other words, Energy Union is about everything that matters in EU energy policy.  To date, at least in relation to electricity markets, the initiative has involved a lot of consultation but not many concrete legislation proposals.  The new Winter Package goes a long way towards redressing this balance, but it shows there is still a lot of work to do.

What is in the Winter Package?

The documents published by the Commission (all available from this link) include legislative proposals and a range of explanatory and background policy documents.  The legislative proposals are for:

We comment below on what seem to us at this stage to be the most interesting points in these, and also on the Communication on Accelerating Clean Energy Innovation (the Innovation Communication).

The Revised IMED

Overall impressions

The legislative elements of the Winter Package are all inter-related, but the Revised IMED is as good a place to start as any.  Its early articles include two programmatic statements:

  • National legislation must “not unduly hamper cross-border flows of electricity, consumer participation including through demand-side response, investments into flexible energy generation, energy storage, the deployment of electro-mobility or new interconnectors”.
  • Electricity suppliers must be free to determine their own prices.  Non-cost reflective power prices should only apply for a transitional period to vulnerable customers, and should be phased out in favour of other means of support except in unforeseeable emergencies.

In some ways, this sets the tone for the more specific provisions that follow.  It often seems that the Commission never loses an opportunity to put forward legislation in the form of a directly applicable Regulation rather than in the form of a Directive that by definition requires Member States to take implementing measures in order fully to embed its effect within national regulation.  However, the revised IMED, like its predecessor, stands out as a classic old-school Directive, in which EU legislators tell Member States lots of results to be achieved, but do not prescribe many of the means by which this is to happen.  Moreover, even the expression of those objectives is (inevitably) qualified: in other words, get rid of the barriers to the Commission’s vision of Energy Union, except the ones you can justify.  Of course, that is slightly unfair: as noted below, there are at least one or two eye-catching points in the revised IMED, and there are significant changes proposed in other parts of the Winter Package that should further the objectives of the revised IMED, but it arguably demonstrates less willingness to get to grips with some of the most difficult of the longer-term and more fundamental changes in the market than the call for evidence on moving towards a smart, flexible energy system that was published on 10 November by the UK government and GB energy regulator Ofgem (although admittedly the UK authorities are only asking questions, not proposing solutions at this stage).

A market for consumers (and prosumers)

The revised IMED would enhance the rights of consumers generally in a variety of ways.  For example:

  • Price increases are to be notified and explained in advance, giving them the opportunity to switch before an increase takes effect.  Switching must take no longer than three weeks.
  • Termination fees may only be charged where a fixed term contract is terminated prematurely, and must not exceed the direct economic loss to the supplier.
  • All consumers are to be entitled, on request, to a “dynamic electricity price contract” which reflects spot market price fluctuations at least as frequently as market settlement occurs.  They will of course need smart meters to make this work (see further below).
  • All consumers are to be entitled to contract with aggregators, without the consent of their supplier, and to end such contracts within three weeks.

In addition, special consideration is given to two newly defined categories of persons.

  • “Active consumers” are defined as individuals or groups “who consume, store or sell electricity generated on their premises, including through aggregators, or participate in demand response or energy efficiency schemes”, but who do not do so commercially / professionally.
  • “Local energy communities” are defined as organisations “effectively controlled by local shareholders or members, generally non-profit driven or generally value rather than profit-driven…engaged in local energy generation, distribution, aggregation storage, supply or energy efficiency services, including across borders”.

Active consumers are to be:

  • entitled to undertake their chosen activities “in all organised markets” without facing disproportionately burdensome procedures or charges; and
  • encouraged to participate alongside generators in all organised markets.  Obviously in most cases they will do this through aggregators, who are to be treated “in a non-discriminatory manner, on the basis of their technical capabilities”.  For example, they are not to be required to pay compensation to suppliers or generators (contrary to some of the suggestions in the UK call for evidence referred to above).

Local energy communities:

  • are similarly not to be discriminated against;
  • may “establish community networks and autonomously manage them” and “purchase and sell electricity in all organised markets”;
  • must not make participation in a local energy community compulsory, or limit it to those who are shareholders in or members of the community; and
  • will be subject to the unbundling rules for distribution system operators if they are DSOs.

As in the original Directive 2009/72/EC, there are provisions requiring improvements to customer billing and encouraging the rollout of smart meters.

  • Customers should receive bills once a month where remote reading of the meter is possible.
  • Where a Member State has decided not to mandate smart meters for cost-benefit reasons, they are to revisit their assessment “periodically” and report the results to the Commission.
  • The draft Directive sets out functionalities that smart meters must include where a Member State mandates their rollout.  In such cases, the costs of smart metering deployment are to be shared between all consumers.  In other cases, every customer is entitled, on request, to receive a smart meter that complies with a slightly reduced set of functionalities.
  • The implementation of smart metering must encourage active participation of consumers in the electricity supply market (although this may be qualified by a cost-benefit analysis).
  • There are a number of provisions reflecting both concerns about cybersecurity and the importance of making useful data securely available to legitimate market participants.

DSOs (and EVs)

There has been no shortage of recent commentary on how the shift towards decentralised generation of electricity, combined with the potential for storage and more active consumer behavior, may require changes in the role of the 2,400 market participants that the IMED has always called distribution system operators, but which in many jurisdictions have historically not had, even within their own networks, the kind of “system operator” responsibilities of a transmission system operator.  The recent UK call for evidence on flexibility appears at least prepared to contemplate some significant realignment of the respective functions of DSOs and TSOs.  There is nothing so fundamental in the revised IMED, but there are a number of new provisions about DSOs.

  • DSOs are to be allowed, and incentivised, to procure services such as distributed generation, demand response and storage in order to make their networks operate more efficiently.  DSOs will be paid for this, and must specify standardised market products for these services.
  • Every two years, DSOs must update five to ten year network development plans for new investments, “with particular emphasis on the main distribution infrastructure which is required…to connect new generation capacity and new loads including re-charging points for electric vehicles”, as well as demand response, storage, energy efficiency etc.
  • DSOs serving isolated systems or fewer than 100,000 consumers can be excused from this requirement, but note that in general, those operating “closed distribution systems” are to be subject to the same rules as other DSOs under the revised IMED.

However, although DSOs are to facilitate the adoption of new technologies, such as storage and EVs, they are not encouraged to diversify into actually providing them to end users themselves.

  • Member States are to facilitate EV charging infrastructure from a regulatory point of view, but DSOs may only “own, develop, manage or operate” EV charging points if the regulator allows them to after an open tender process in which nobody else expresses an interest in doing so.  And even then, the service taken on by the DSO must be re-tendered every five years.
  • Similar rules would apply to the development, operation and management of storage facilities by either DSOs or TSOs.  For TSOs, there would be an additional requirement that the storage services or facilities concerned are “necessary” to ensure efficient and secure operation of the transmission system, and are not used to sell electricity to the market.

What makes these provisions significant is that until now, with the IMED in its original form silent on the subject of storage, the operation of storage facilities had been seen as potentially falling within the categories of generation or supply.  This appeared to make the involvement of DSOs or TSOs in storage projects (at least as investors) subject to the general unbundling restrictions, and so has tended to inhibit the progress of energy storage initiatives in a number of cases.  The proposed new rules are restrictive in some respects, but bring a degree of clarity and at least recognise storage as a distinct category.

The Revised Market Regulation

General organisation of the electricity market

Like the revised IMED, the Revised Market Regulation begins with firm statements of purpose: enabling market access for all resource providers and electricity customers, enabling demand response, aggregation and so on.  It goes on to list 14 “principles” with which “the operation of electricity markets shall comply” – starting with “prices are formed based on demand and supply” and finishing with “long-term hedging opportunities allow to hedge parties against price volatility risks”.

Entirely in keeping with these principles, the first specific provision is that all market participants are to be responsible for (or to delegate to a responsible third party) the consequences of any imbalance they create in the electricity system as a result of importing or exporting to or from the grid at a given time more or less than they had said would be the case at that time in previous notifications to the system operator.  This much-trailed provision may be a significant change for renewable generators in some jurisdictions (though not in GB, where imbalance charging reforms are already being implemented).  In an earlier draft, the Revised Market Regulation only permitted sub-500kW renewables or high-efficiency CHP to be exempted from this requirement.  In the published version, this exemption has been broadened to include RES projects that have received state aid that has been cleared by the commission and that have been commissioned before the Revised Market Regulation enters into force.  It also requires that “all market participants” are to have access to the balancing market on non-discriminatory terms, either directly or through aggregators.

There are a number of quite detailed provisions on the overall organisation of electricity markets. We pick out a few of the more notable ones below.

  • There is a shift from a national to a regional approach.  As the explanatory memorandum to the draft Directive puts it: “In certain areas, e.g. for the EU-wide ‘market coupling’ mechanism, TSO cooperation has already become mandatory, and the system of majority voting on some issues has proven to be successful…Following this successful example, mandatory cooperation should be expanded to other areas in the regulatory framework.  To this end, TSOs could decide within ‘Regional Operational Centres’…on those issues where fragmented and uncoordinated national actions could negatively affect the market and consumers (e.g. in the fields of system operation, capacity calculation for interconnectors, security of supply and risk preparedness).”.  Functions to be carried out at a regional level include “the dimensioning of reserve capacity” and “the procurement of balancing capacity”.
  • As far as possible, the organisation of markets is to avoid any rules that could restrict cross-border trading or the participation of smaller players.  So, for example, trades are to be anonymous and in a form that does not distinguish between bidders within and outside a bidding zone.  The minimum bid size is not to exceed 1 MW.
  • Market participants are to be able to trade energy as close to real time as possible, with imbalance settlement periods being set to 15 minutes by 1 January 2025.
  • Long-term (firm, and transferable) transmission rights or equivalent measures are to be put in place to enable e.g. renewable generators to hedge price risks across bidding zone borders.  Such rights are to be allocated in a market-based manner through a single allocation platform.
  • As a general rule, there must be no direct or indirect caps or floors on wholesale power prices, other than a cap at the value of lost load and a floor of minus €2000, or during a 2-year transitional period when a transitional maximum and minimum clearing price may be allowed.  Defined as “an estimation in €/MWh of the maximum electricity price that consumers are willing to pay to avoid an outage”, the value of lost load is to be defined nationally and updated at least every five years.  This concept will evidently need refinement, as there is a difference between what individual consumers may be prepared to pay and the kind of price spikes that it is reasonable for wholesale markets to bear for short periods of time.
  • Dispatching of generation and demand response is to be market-based.  Priority dispatch for renewables is to be brought to an end subject to certain exceptions (these are summarised in the section on the revised RED below).  On the other hand, where redispatch (changing generator output levels) or curtailment is imposed by the system operator other than on market-based criteria, the draft Regulation imposes restrictions on when RES, high-efficiency CHP and self-generated power can be redispatched or curtailed.
  • There is to be a review of the bidding zones within the single electricity market, so as to maximise economic efficiency and cross-border trading opportunities while maintaining security of supply.  In other words, the market coupling process should allow customers to benefit from the availability of lower-priced wholesale power in adjacent markets, but the bidding zone boundaries need to take account of “long-term structural congestion” in the network infrastructure for this to be workable and without adverse side-effects.  TSOs are to participate in the review, but the final decisions are to be taken by the Commission.
  • A significant piece of work is to be undertaken by ACER on “the progressive convergence of transmission and distribution tariff methodologies”.  This is to include, but not be limited to, some issues that have recently proved contentious in the GB context, including the respective shares of tariffs to be paid by those who generate and those who consume power; locational signals (how much more should generators pay if they are located a long way from where the power they generate used); and which network users should be subject to tariffs (would this, for example, open up the question of whether generators connected to the distribution network should pay a share of transmission network charges?).
  • Separately, the draft Regulation sets out some general principles about network charges and restricts both the circumstances in which revenue can be generated from congestion management and the uses to which such revenue can be put.

Resource adequacy (a.k.a. Capacity Markets)

The growth in the share of installed generating capacity in many Member States represented by intermittent renewable generators and the unattractive economics of new large-scale combined cycle gas-fired plant has left many governments in the EU concerned about security of power supply and turning to various forms of capacity market subsidy in order to ensure that the lights stay on.  The Commission has been concerned that capacity markets dampen the price signals that should drive new investment and potentially introduce new barriers to cross-border power flows.  A number of national capacity market regimes have been investigated by the Commission’s DG Competition; both the UK and French approaches to the problem have received state aid clearance.

The starting point of the draft Regulation in this area is an annual assessment of “the overall adequacy of the electricity system to supply current and projected demands for electricity ten years ahead”.  This European-level assessment will form the yardstick against which national proposals to introduce a capacity mechanism are to be judged.  If it has “not identified a resource adequacy concern, Member States shall not introduce capacity mechanisms” and no new contracts shall be concluded under existing capacity mechanisms.  Where capacity mechanisms are introduced, they must not distort the market unnecessarily; interconnected Member States should be consulted; and other approaches, such as interconnection and storage, should be considered first.

The draft Regulation prescribes common elements which capacity mechanisms must contain, including that they must be open to providers in interconnected Member States (unless they take the form of strategic reserves) and that the authorities of one country must not prevent capacity located in their territory from participating in other countries’ capacity mechanisms.  Those participating simultaneously in more than one capacity mechanism “shall be subject to two or more penalties if there is concurrent scarcity in two or more bidding zones that the capacity provider is contracted in”.  Maybe that will help to dampen industry’s appetite for capacity markets.

Finally, the draft Regulation sets an emission limit of 550 gCO2/kWh for plant on which a final investment decision is made after the Regulation enters into force.  Such plant must have emissions below this limit if it is to be eligible for capacity mechanism support.  The draft Regulation goes on to state that generation capacity emitting at this level or higher is “not to be committed in capacity mechanisms 5 years after the entry into force of this Regulation”.  These provisions may be motivated by laudable decarbonisation objectives, but they must at the very least risk precipitating a rush to take final investment decisions in new coal-fired generating capacity over the next two years.  It is possible, but unlikely, that they might stimulate further investment in carbon capture and storage (to bring the emissions of coal-fired plants below the threshold).  Previous experience with emissions limit rules also suggests that much will depend on how emissions are measured – the usual trick of polluting plant being to argue that they should be counted not per hour of generation, but averaged out over time so as to allow for plant to run above the limit for short periods.  This is bound to be an area for lively negotiations between Member States and in the European Parliament.

The Commission’s proposals in relation to capacity markets need to be read alongside DG Competition’s final report on its investigation and the accompanying Staff Working Paper.  We will look in more detail at this aspect of the proposals and how it might affect existing Member State initiatives in a future post.  For now, it is sufficient to note that although this part of the Winter Package is entirely consistent with the logic of the evolving single electricity market, for some, it may simply appear to be an unacceptable blow to the principle of Member States’ self-determination of their own generating mix.

Institutions

In addition to its existing roles, the TSO umbrella body, ENTSO-E, will acquire new responsibilities for the European resource adequacy assessment and in relation to the Regional Operational Centres, including adopting a proposal for defining the regions which each will cover, and generally monitoring and reporting on their performance.  A parallel umbrella body for DSOs, with consultative functions, is also to be set up.

The draft Regulation devotes a number of articles to the Regional Operational Centres. They will be limited liability companies established by TSOs (with adequate cover for potential liabilities incurred by the impact of their decisions).  Their role is to complement TSO functions by ensuring the smooth operation of the interconnected transmission system, but apparently from the perspective of planning and analysis rather than real-time  operational control.  Specific areas of their work (listed under 17 headings) include outage planning coordination, calculating the minimum entry capacity available for participation of foreign capacity in capacity mechanisms, and much else besides.

This area of the draft Regulation will need careful development and implementation if the proliferation of new bodies and functions is not to result in confusion and a lack of accountability.  However, the question of whether to grant Regional Operational Centres binding decision-making powers in relation to some of their potential functions is left to be decided by the national regulatory authorities of a system operating region.

The Revised RED

Target for 2030

The existing Renewable Energy Directive (2009/28/EC) sets out the binding national targets for each Member State to achieve a specified proportion of its energy consumption to be obtained from renewable energy sources (RES) by 2020, contributing to an EU-wide goal of 20% of final energy from RES.  The revised RED starts from a slightly different point, since EU leaders decided in 2014 to move away from legally binding national RES targets imposed at EU level but to set a goal of achieving at least 27% of energy from RES across the EU by 2030.  The starting point of the revised RED, therefore, is that “Member States shall collectively ensure” that the 27% target is achieved by 2030, whilst, individually, ensuring that they continue to obtain at least as high a proportion of final energy from RES as they were obliged to achieve by 2020.

At this point, you may ask what the enforcement mechanism is for meeting the new EU-wide target.  An answer (of sorts) is to be found in the Governance Regulation – see below.

Power (plus)

With reference to subsidies for RES, the revised RED builds on the principles set out in the Commission’s 2014 guidelines on state aid in the energy and environmental sectors: competitive auctions in which all technologies can compete on a level playing field are to be the norm, with traditional feed-in tariffs limited to small projects.

The revised RED also makes provision on two points that have led to disputes in connection with RES subsidies.  First, picking up on a point that has in the past given rise to litigation under general EU Treaty principles, it would set quotas for the proportion of capacity tendered in RES subsidy auctions that each Member State must throw open to projects from other Member States.  Second, with an eye to the numerous cases brought against Member States either under domestic constitutional / administrative law or under the Energy Charter Treaty, the revised RED attempts to outlaw retrospective reductions in support for RES once that support has been awarded, unless these are required because a state aid investigation by the Commission has found the subsidy received by a project is unduly generous.  Note that while the first of these rules appears to relate only to RES electricity subsidies, the second is expressed in a way that suggests that it relates to all RES projects.   An additional measure of reassurance for investors is a requirement to consult on and publish “a long-term schedule in relation to expected allocation for [RES] support” looking at least three years ahead.

Other points of interest in the draft Directive in connection with RES power include:

  • In a magnificently brief reference to one of the most important market trends in the renewable power sector, the revised RED would require Member States to “remove administrative barriers to corporate long-term power purchase agreements to finance renewables and facilitate their uptake”.
  • The process of applying for permits to build and operate new RES projects is to be streamlined, with a single point of contact co-ordinating the permitting process (including for associated network infrastructure) and ensuring that it does not last longer than three years.  This provision would confers on all RES projects (again, the current language of the draft Directive does not limit this to power sector projects) a benefit currently only conferred at EU level under the Infrastructure Regulation on those projects singled out as Projects of Common Interest – although in its current form it is questionable if it would give a developer thwarted by slow decision-making in a given case a useful remedy.
  • The permitting procedures for repowering of existing projects are to be “simplified and swift” (i.e. not to last more than 1 year), although this may not apply if there are “major environmental or social” impacts.  If you were hoping to be able to demand fast-track treatment for applications to repower existing wind farms with fewer, taller turbines generating more power, don’t hold your breath.
  • The existing RED rules on priority dispatch for RES generators are to be abolished.  This point is reiterated in the Revised Market Regulation.  However, that draft Regulation provides for “grandfathering” of priority dispatch rights for existing RES (and high efficiency CHP) generators until such time as they undergo “significant modifications”.  Exceptions are also permitted for innovative technologies and sub-500kW installations (from 2026, sub-250kW), if no more than 15% of total installed generating capacity in a given Member State benefits from priority dispatch (beyond that level, the threshold is 250kW or 125kW from 2026).
  • The revised RED likes prosumers, or as it calls them, “renewable self-consumers”.  They are to be entitled to sell their surplus power “without being subject to disproportionate procedures and charges that are not cost reflective”, to receive a market price for what they feed into the grid, and not to be regulated as electricity suppliers if they do not feed in more than 10MWh (as a household) or 500MWh (as a business) annually (Member States may set higher limits).
  • The revised RED also likes “renewable energy communities”.  The draft definition of these is a little complicated, but essentially they are locally based entities that are either SMEs or not for profit organisations, which are to be allowed to generate, consume, store and sell renewable electricity, including through PPAs.

Heat, cooling and transport

The revised RED seeks to “mainstream” RES in heating and cooling installations, and in the transport sector.  The means by which it seeks to achieve this are not, at first sight particularly dramatic, given the acknowledged scale and difficulty of the challenge of decarbonising these sectors.

In relation to heat and cooling, Member States are to identify “obligated parties amongst wholesale or retail energy and energy fuel suppliers” and require them to increase the share of RES in their heating and cooling sales by at least 1 percentage point a year.  The obligation should be capable of being discharged either directly or indirectly (including by installing or funding the installation of highly efficient RES heating and cooling systems in buildings).  This does not seem hugely ambitious.  Mention is made of “tradable certificates” – it feels a bit like a combination of the Renewables Obligation, but applied to heat and cooling, and the Clean Development Mechanism under the Kyoto Protocol.  It is also relevant in this context that the revised RED envisages that renewable guarantees of origin (REGOs or GoOs) will in future be available for the production and injection into the grid of renewable gases such as biomethane.

The rules aimed at the transport sector are also based on mandatory requirements on fuel suppliers – in this case to incorporate both a minimum (annually increasing) percentage of certain kinds of RES fuel, waste-based fossil fuel and RES electricity into the transport fuel they supply and to ensure that the parts of that supply that take the form of advanced biofuels and biogas from specified sources (which must constitute a certain part of the overall RES percentage) contribute to an increasing reduction in greenhouse gas emissions.  The provisions for calculating the various percentages are quite complex, involving as they do an element of lifecycle emissions calculation (e.g. considering the emissions from the generation of electricity used to produce advanced biofuels).

On district heating and cooling, the revised RED takes a three-pronged approach.

  • Member States are to ensure that authorities at local, national and regional level “include provisions for the integration and deployment of renewable energy and the utilisation of unavoidable waste heat or cold when planning, designing, building and renovating urban infrastructure, industrial or residential areas and energy infrastructure, including electricity, district heating, and cooling, natural gas and alternative fuel networks”.
  • The efficiency of district heating systems is to be certified.  Providers of such systems must grant access to new customers where they have the capacity to do so (unless they are new and meet exemption criteria based on efficiency and use of renewables).  Customers of systems that are not efficient may disconnect from them in favour of their own RES heat and cooling, but Member States may restrict this right to those who can demonstrate that the customer’s own heating or cooling solution is more efficient.
  • There is to be regular consultation between operators of district heating and gas / electricity networks about the potential to exploit synergies between investments in their respective networks.  Electricity network operators must also assess the potential for using district heating and cooling networks for balancing and energy storage purposes.

This is all unobjectionable.  It is not clear that in itself it will be enough to cause a major expansion of district heating and cooling where it does not already exist, or to significantly increase the take-up of RES heat and cooling options, but perhaps this is the kind of area where an effective policy push can only be delivered at national, or indeed municipal level.

Biomass

Following a trend that has been evident for some time in UK subsidies for RES electricity, the revised RED would appear to prohibit “public support for installations converting biomass into electricity” unless they apply high efficiency CHP, if they have a fuel capacity of 20 MW or more.  However, the precise words setting this out have been moved from the operative provisions of the draft Directive into a recital, which also clarifies that this would not require the termination of support that has already been granted to specific projects, but that new biomass projects will only be able to be counted towards renewables targets if they apply high efficiency CHP.

What is clear is that the revised RED would tighten the sustainability criteria applicable to biofuels and bioliquids at various points in the energy supply chain, with greenhouse gas emissions – for example those arising from land use to grow the raw materials that become biofuels – being designated as a distinct impact to be measured.  If you dig up soil with a high carbon content to grow something that will become biofuel, you may end up increasing rather than reducing overall GHG emissions, so this is obviously to be avoided.

The Governance Regulation

The Governance Regulation is meant to hold everything together.  In particular, it aims to give credible underpinning to the commitments on climate change that the EU as a whole has made under the Paris Agreement (but which must ultimately be delivered by Member State action) and to bridge the gap left by having an EU level 2030 renewables target but no correspondingly increased Member State level targets.  It also gives legislative expression to the EU’s Union-level energy and climate targets to be achieved by 2030, which are:

  • a binding target of at least 40% domestic reduction in economy-wide greenhouse gas emissions as compared with 1990;
  • a binding target of at least 27% for the share of renewable energy consumed in the EU;
  • a target of at least 27% for improving energy efficiency in 2030, to be revised by 2020, having in mind an EU level of 30%;
  • a 15% electricity interconnection target for 2030.

In outline, the Regulation works as follows.

  • Every 10 years, starting in 2019, each Member State is to produce an integrated national energy and climate plan covering a period of ten years, two years ahead (so e.g. the 2019 plan covers 2021 to 2030, and so on).  The plan is to set out, in relation to each of the five dimensions of the Energy Union, the current state of play in the relevant Member State; the national objectives and targets, policies and measures they have adopted; and their projections (including in relation to emissions) going forward to 2040.  The draft Regulation sets out in considerable detail the information which is required to be included.
  • In relation to RES and energy efficiency, Member States are expressly required to take into account the need to contribute towards achieving the relevant EU level targets, and to ensure, collectively, that they are met.  In relation to RES policies, they are also to take into account “equitable distribution of deployment” across the EU, economic potential, geographic constraints and interconnection levels.
  • The draft Regulation states that Member States must consult widely on the plans and suggests that there may also be a need for the preparation of and consultation on a strategic environmental assessment of the draft plans in some cases.
  • Every two years (starting in the first year to which the plans apply), Member States are to report to the Commission on the status of implementation of their plans; on GHG policies, measures and projections; on climate change adaptation and support to developing countries; on progress in relation to renewable energy, energy efficiency and energy security; on internal market benchmarks such as levels of interconnectivity; and on public spending on relevant research and innovation projects.  In addition, the draft Regulation specifies how Member States are to report annually on GHG inventories for UNFCCC purposes.
  • The plans and drafts are to be updated if necessary after five years (with the first draft update in 2023 and the first update in 2024), using the same procedures.  Updates cannot result in Member States setting themselves lower targets.
  • The plans are first to be submitted to the Commission for comment one year in advance, in draft (i.e. first draft by 1 January 2018).  Either at this point or in its annual State of the Energy Union reports, the Commission may make recommendations to individual Member States, for example about “the level of ambition of objectives and targets” in its draft plan, and Member States “shall take utmost account” of these when finalising the plan.  Member States are obliged to issue annual progress reports on their plans and these must include an explanation of how they have taken utmost account of any Commission recommendations and how it has implemented or intends to implement them.  Any failure to implement the Commission’s recommendations must be justified.
  • Member States whose share of RES falls below their 2020 baseline must cover the gap by contributing to an EU-level fund for renewable projects.  If it becomes clear by 2023 that the 2030 RES target is not going to be met, Member States must cover the gap in the same way, or by increasing the percentage of RES fuel to be provided by heat and transport fuel suppliers under the revised RED, or by other means.  Action may also be taken by the Commission at EU level.

The answer to the question of how the 2030 targets are enforced is therefore – and perhaps inevitably – somewhat incomplete.  Whilst one may doubt the usefulness, under the current RED, of the prospect of the Commission taking infraction proceedings against a Member State that fails to reach the required percentage of RES energy by 2020, there is arguably nothing in the Governance Regulation that has even this degree of legal bite when it comes to pushing recalcitrant Member States into action from the centre.  However, ultimately the whole edifice of the Paris Agreement, of which this is effectively a supporting structure, will only work on the basis of a combination of the economic attractions of better energy efficiency, cheaper renewables and other technological advances, and stakeholder pressure, including through democratic and judicial processes.  The Governance Regulation, like the UK’s Climate Change Act 2008 with its system of carbon budgets, certainly provides some scope for interested parties to challenge national authorities who are, for example, failing unjustifiably to implement Commission recommendations.

The Risk Regulation

The Risk Regulation exists to provide “a common framework of rules on how to prevent, prepare for and manage electricity crisis situations, bringing more transparency to the preparation phase and…ensuring that electricity is delivered where it is needed most”.  A common approach to identifying and quantifying risks is seen as essential to building the necessary “trust” and “spirit of solidarity” between Member States.  The draft Regulation would replace the rather less ambitious existing Directive 2005/89/EC.

ENTSO-E is tasked with developing a common risk assessment methodology, on the basis of which it is to draw up and update regional crisis scenarios such as extreme weather conditions, natural disasters, fuel shortages or malicious attacks.  Provision is made for emergency planning at both national and regional levels, with the Regional Operational Centres playing a significant role at various points.  As throughout the Winter Package, emphasis is laid on using market measures wherever possible, so that forced disconnections, for example, should be response of last resort, and Member States facing a crisis should not automatically seek to curtail outbound cross-border power flows.

The ACER Regulation

It comes as no surprise that the Winter Package proposes conferring more powers on ACER.  So, for example, the methodologies and calculations underlying the European resource adequacy assessment will require the approval of, and may be amended by, ACER – since, as one of the recitals to the draft Regulation notes, “fragmented national state interventions in energy markets constitute an increasing risk to the proper functioning of cross-border electricity markets”.  But the draft Regulation is far from representing a major transformation of ACER into an EU energy super-regulator.

The Innovation Communication

The Innovation Communication picks up on a number of the themes emphasised in the various legislative proposals.  It builds on existing initiatives, for example within the framework of the EU’s Horizon 2020 funding programme, for which it includes some new money.  The need to leverage more private sector investment in innovative energy-related technologies is noted, with some examples of where this has already been achieved.  The Communication also states that the Commission, with Member States, will take a leading role in two of the workstreams identified by the international Mission Innovation Initiative.

Four particular priorities are singled out as technology focus areas for EU innovation funding:

  • Energy storage solutions, including the (perhaps not unambitious) objective of “re-launching the production of battery cells in Europe”.
  • Electro-mobility and a more integrated urban transport system, which amongst other things will include tackling “fragmentation in the developing market of low-emission transport”.
  • Decarbonising the EU building stock by 2050: going beyond “today’s nearly zero-energy designs” to include e.g. the application of circular economy principles.
  • Integration of renewables: reducing the costs of existing established technologies; promoting new technologies like building-integrated photovoltaics; and intensifying efforts to integrate renewables through storage and the transport sector.

Energy Efficiency

Last but not least, energy efficiency. The two draft Directives on this make less wide-ranging changes to the existing legislation.

Under the revised Energy Efficiency Directive, Member States will be obliged to deliver the equivalent of 1.5% of annual energy sales (by volume) to final consumers over the period 2021-2030 – but with scope to determine how those savings are phased.

As regards the Energy Performance of Buildings Directives, there is an emphasis on encouraging the use of smart technologies.  There is also a requirement, when building or carrying out major renovations of buildings with more than 10 car parking spaces, to install one alternative fuel re-charging point for every 10 spaces in a non-residential context and to put in pre-cabling for re-charging points for EVs in all spaces in a residential context.  In the non-residential context at least, the re-charging point must be “capable of starting and spotting charging in relation to price signals”.  There are also some new requirements to monitor the energy efficiency of non-residential buildings, presumably in the hope that if their owners become aware of how much inefficiencies of design or operation are costing them, they will invest in improvements.

At the same time, the Commission has issued an ecodesign working plan for 2016-2019, reminding us as it does so that EU ecodesign and energy labelling deliver “energy savings equivalent to the annual consumption of Italy” and “save almost €500 per year” on household energy bills, as well as delivering approximately €55 billion extra revenue for industry.

Brexit

One of the many energy-sector questions raised by the UK’s decision to leave the EU is on what terms participants in the electricity markets in GB and Northern Ireland (and indeed the Republic of Ireland, until such time as it has a direct interconnection with Continental Europe) may be able to continue to participate in the EU’s single electricity market in a post-Brexit world.  Possible models for this include membership of the European Economic Area (as an EFTA, rather than an EU state) or joining the Energy Community (many of whose members are candidates for EU membership, but disputes within which are resolved by a political Association Council without reference to the Court of Justice of the EU).

The Winter Package in its published form casts no direct light on this subject.  However, in a version of the main legislative proposals that was leaked only a couple of weeks before they were published, a number of the draft measures (such as the draft revised IMED) included a couple of articles that appeared to offer some grounds for hope – if continued UK membership of the single EU electricity market is the sort of prospect that makes you hopeful.

  • Like the EU itself, the Energy Community is currently operating on (or is working towards) the version of the single electricity and gas markets set out in the Third Package of EU liberalisation measures adopted in 2009.  The leaked draft revised IMED set out a process for the Energy Community and the Commission to incorporate the revised Directive into the Energy Community’s legislative framework.  So if the UK was happy with the final form of the Winter Package legislation, the option of continuing to be subject to and getting the benefit of it as a member of the Energy Community would be a possible option.
  • On the other hand, once the UK ceases to be an EU Member State, and assuming it does not opt for EEA membership, it will simply become a “third country” (with or without the benefit of a bespoke EU / UK free trade agreement).  The leaked draft revised IMED suggested that third countries may participate in the single electricity market provided that they agree to adopt, and apply, “the main provisions” of the Winter Package legislation; EU state aid rules; the REMIT rules on wholesale energy market integrity; “environmental rules with relevant for the power sector”; and rules on enforcement and judicial oversight that require it to submit either to the authority of the Commission and the CJEU or “to a specific non-domestic enforcement body and a neutral non-domestic Court or arbitration body which is independent from the respective third country”.

Reading these provisions in the UK, it was hard not to see them as drafted with Brexit in mind.  Of course, the EU is, or aspires to be, physically connected to power systems in other non-EU countries as well (such as the potential solar energy exporters of North Africa), so it would be wrong to see them entirely in that light.

How the absence of such provisions, or the prospect of their potential reinsertion, will affect the dynamics of the UK’s participation in negotiations on the Winter Package (which is likely to take place while the UK is still a Member State) is another question.  In our view, the UK and its electricity industry stakeholders should in any event try to play a leading and constructive role in the whole of the negotiations on the Winter Package, as they have in negotiation on past internal energy market measures.

Maybe, in one sense, it is better that the draft provisions on third country participation have not been included at this stage.  Similar provisions could be negotiated on a standalone basis later, and include the gas as well as electricity single markets, for example.  By leaving them out of the Winter Package (for whatever reason), the Commission may have prevented the UK team from being unduly distracted from the main subject of the legislative proposals, or expending its negotiating capital on their Brexit dimension.

Provisional conclusions

The Winter Package covers a lot of ground, but then it needs to do so, since the next ten years are acknowledged to be crucial to the success of global efforts to avoid dangerous climate change.  It may not be as radical as some would like, but then whilst some of its requirements are already more or less met by a number of Member States, for others they may represent a considerable challenge.  In one sense it is a timely reminder of both the scope and the limitations of the European project.

There are a lot of links between the individual pieces of draft legislation.  There are also a number of areas where the drafting suggests that some key concepts have not yet been absolutely fully thought out.  Steering negotiations so as to result in a clear and coherent legal framework will be difficult.  The risks of (calculated or inadvertent) lack of clarity in the final texts may be higher than is usual with EU legislation, leading to wrangles with regulators and before the courts down the line – or simply having a chilling effect on what could be useful activity.  However, since the need for action is urgent, waiting for perfect legislation is not a luxury the EU can afford.  So it is vital that those with an interest in making Energy Union work scrutinise the parts of the Winter Package that matter to them carefully, and tell their national governments or MEPs where they find it wanting.

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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

First flesh on the bones of the new UK government’s energy policy?

The UK Department of Business, Energy & Industrial Strategy (BEIS) chose 9 November 2016 to release a series of long-awaited energy policy documents.  The substance of some of the announcements, which primarily cover subsidies for renewable electricity generation and the closure of the remaining coal-fired generating plants in England and Wales, was first outlined almost a year ago when Amber Rudd, the last Secretary of State for Energy and Climate Change, “re-set” energy policy in outline in a speech of 18 November 2016.  Broadly speaking, the documents indicate that little has changed in the UK government’s thinking on energy policy following the EU referendum and the formation of what is in many respects a new government under Theresa May.

Contracts for Difference

BEIS has confirmed that the next allocation process for contracts for difference (CfDs) for renewable generators will begin in April 2017, aiming to provide support for projects that will be delivered between 2021 and 2023. There will be no allocation of CfD budget for onshore wind or solar, consistent with the Government’s view that these are mature and/or politically undesirable technologies which should no longer receive subsidies.  The only technologies supported will be offshore wind, certain forms of biomass or waste-fuelled plant (advanced conversion technologies, anaerobic digestion, biomass with CHP) wave, tidal stream and geothermal.

The budget allocation is a total of £290 million for projects delivered in each of the delivery years covered: 2021/22 and 2022/23. Details are set out in a draft budget notice and accompanying note.  CfDs are awarded in a competitive auction process, the details of which are set out in an “Allocation Framework” (the one used for the last auction, in 2014/2015, can be found here).  It is likely that most, if not all, of the budget will be taken up by a small number of offshore wind projects, as the size of the projects which could be eligible to bid in the auction is large in comparison with the available budget.

Competition for CfDs will be fierce and Government should be able to show progress towards achieving its target of reducing support to £85/MWh for new offshore wind projects by 2026. For the 2017 auction, “administrative strike prices” have been set at levels designed to ensure that “the cheapest 19% of projects within each technology” can potentially compete successfully.  Behind this terse statement and the methodology it summarises lies an extensive BEIS analysis of Electricity Generation Costs, underpinned or verified by studies or peer reviews by Arup, Imperial College, NERA, Prof Anna Zalewska, Prof Derek Bunn, Leigh Fisher and Jacobs and EPRI.

The heat is on

Alongside the draft budget notice, BEIS has published two documents about CfD support for particular technologies.

One of these is a consultation that returns to the long-unanswered question of what to do about onshore wind on Scottish islands: should it be regarded as just another species of onshore wind (and therefore not to receive subsidy, in line with post-2015 Government policy), or does it face higher costs to a degree that merits a special place in the CfD scheme, as was suggested by the 2010-2015 Government?  It comes as no surprise that the Government favours the former view: another item to add to the list of points on which the UK and Scottish Governments do not see eye to eye.

The second document is a call for evidence on the currently CfD-eligible thermal renewable technologies of biomass or waste-fuelled technologies (including biomass conversions), and geothermal.  These raise a number of issues, on which the call for evidence takes no clear stance.

  • Is continued support for the fuelled technologies in particular consistent with getting “value for money” by focusing subsidies on the cheapest ways of decarbonising the power supply (except onshore wind and solar), given that (with the exception of biomass conversions), they have a relatively high levelised cost of electricity generation?
  • Can they be justified on the grounds that they are “despatchable” (and so do not impose the same burdens on the system as “variable” renewable generation like wind and solar)?  Or on the grounds that (where they incorporate combined heat and power), they contribute to the decarbonisation of heat, as well as of power generation – an area in which more progress needs to be made soon in order to meet our overall target for reducing greenhouse gas emissions under the Climate Change Act 2008 (and the Paris CoP 21 Agreement)?
  • Is the current relationship between the CfD and Renewable Heat Incentive support schemes the right one in this context?  Is a CfD for a CHP plant unbankable because of the risk of losing the heat offtaker?
  • Are all these technologies about to be overtaken as potential ways of decarbonising the heat sector on a large scale by other contenders such as hydrogen or heat pumps (and if so, is that a reason to abandon them as targets for CfD or other subsidy)?
  • Should more existing coal-fired power stations be subsidised to convert to burning huge quantities of wood pellets (is that really “sustainable” – and would such subsidies comply with current EU state aid rules, for as long as they or something like them apply in the UK)?

Against this background, the draft budget notice proposes to limit advanced conversion technologies, anaerobic digestion and biomass with CHP to 150MW of support in the next CfD auction.

Kicking the coal habit

Finally, BEIS is consulting on the best way to “regulate the closure of unabated coal to provide greater market certainty for investors in the generation capacity that is to replace coal stations as they close, such as new gas stations”.  The consultation needs to be read alongside BEIS’s latest Fossil Fuel Price Projections (with supporting analysis by Wood Mackenzie).  These set out low, central and high case estimates of coal, oil and gas prices going forward to 2040.  BEIS has significantly reduced its estimates for all three fuels under all three cases as compared with those in its 2015 Projections.

We are talking here about eight generating stations, which between them can produce 13.9GW. Their share of GB electricity supply tends to fluctuate with the relative prices of coal and gas.  Most are over 40 years old.  All can only survive by taking steps to comply with the limits on SOx, NOx and dust prescribed by the EU Industrial Emissions Directive – at least for as long as the UK is within the EU.

The Government’s difficulty is how to ensure that these plants close (for decarbonisation purposes), but on a timescale and in circumstances that ensure that the contribution that they make to security of electricity supply is replaced without a gap by e.g. new gas-fired plant, of which so little has recently been built. BEIS evidently hopes that by the time this consultation finishes on 1 February 2017, the results of next month’s four-year ahead Capacity Market auction will have seen a significant amount of new large-scale gas fired power projects being awarded capacity agreements at prices that make them viable (when taken together with expectations of lower-for-longer gas prices).

Although BEIS professes confidence in the changes that it has made to the rules and market parameters for the next Capacity Market auctions, one cannot help but wonder how convinced Ministers are that the 2016 auctions will succeed in this respect where those of 2014 and 2015 failed.  Because from one point of view, if the Capacity Market does result in new large gas-fired projects with capacity agreements, and gas prices remain low, the market should simply replace the existing coal-fired plants – which, as the consultation points out, aren’t even as flexible as modern gas-fired plant.  Maybe if a newly inaugurated President Trump pushes ahead with his plans to revive the use of coal in the US, higher coal prices will help accelerate the closure of some of our remaining coal-fired plants: BEIS calculates that with relatively low coal prices and no Government intervention, they could run until 2030 or beyond.

So how will Government make the plants close? Two options are proposed.  One would be to require them to retrofit carbon capture and storage (CCS), the other would be to require them to comply with the emissions performance standard (EPS) that was set in the Energy Act 2013 for new fossil-fuelled plant with a view to ensuring that no new coal plant was commissioned.  Neither path is entirely straightforward.  As it seems unlikely that operators would invest the kinds of sums associated with CCS on such old plant, there must be a risk that in trying to make CCS a genuine alternative to complete closure, regulations could end up allowing operators to run a significant amount of capacity without CCS whilst taking only limited action to develop CCS capacity.  With the EPS approach, there would be some tricky questions to resolve around biomass co-firing, as well as biomass conversion, if that were to remain an eligible CfD technology and budget were to be allocated to it.

When it comes to consider how to ensure that coal closure does not involve a “cliff-edge” effect, the consultation seems to run out of steam a bit: having mentioned the possibility of limiting running hours or emissions, either on a per plant basis or across the whole sector, BEIS says simply that it would “welcome any views on whether a constraint [on coal generation prior to closure] would be beneficial and, if so, any ideas on the possible profile and design”.

What next?

Nothing stands still.  The period of these consultations / calls for evidence, and the next Capacity Market auctions, overlaps with other processes.  Over the next few months, the Government is scheduled to produce over-arching plans or strategies in a number of areas that overlap with some of the questions posed in these documents.  It will also continue to develop its strategy for Brexit negotiations with the EU; and the European Commission will publish more of its proposals on Energy Union (including new rules on renewables, market operation and national climate and energy plans).

The documents state more than once that while the UK is an EU Member State, it will “continue to negotiate, implement and apply” EU legislation. But – at least in relation to coal closure – the Government is trying to make policy here for the 2020s.  By that time, it presumably hopes, it will no longer be constrained by EU law.  It remains to be seen how Brexit will affect the participation of our remaining coal-fired plants in the EU Emissions Trading System, which is at present a significant feature of the economics of such plant.  In the short term, the coal consultation points to an announcement in the Chancellor’s 2016 Autumn Statement (23 November) of the “future trajectory beyond 2021” of the UK’s own “carbon tax”, the carbon price support rate of the climate change levy.

After a period in which we have been relatively starved of substantive energy policy announcements, things are starting to move quite fast, and decisions taken by Government over the next few months could have significant medium-to-long-term consequences for UK energy and climate change policy.

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First flesh on the bones of the new UK government’s energy policy?

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

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

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

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

Background:  The Climate Plan and the AESO’s role

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

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

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

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

The AESO’s report and the Renewable Electricity Program

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

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

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

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

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

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

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

(b)  The 2017 REP bid process

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

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

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

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

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

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

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

Does the energy-only market have a future?

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

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

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

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

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

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

Conventional

  • September 27, 2016 – In connection with a state visit to China by Canadian Prime Minister Justin Trudeau, Sinoenergy Corporation Ltd. announced its intention to support the operations of Long Run Exploration Ltd. by the injection of an additional CDN$500 million in investment over the next two years
  • September 23, 2016 – Goldman, Sachs & Co. acquired 14.79 million common shares of Prairie Provident Resources Inc. in connection with the business combination of Lone Pine Resources Canada Ltd. and Arsenal Energy Inc. to form Prairie Provident. GS&Co now beneficially owns, controls and directs more than 10 per cent of the outstanding common shares of the amalgamated company.
  • September 20, 2016 – Encana Corporation announced a public offering of 107 million common shares at a price of US$9.35 per share, for gross proceeds of US$1 billion. Encana intends to use roughly half of the net to fund a portion of its 2017 capital program. The majority of this capital program is expected to be allocated to growing Encana’s Permian production.
  • September 20, 2016 – InPlay Oil Corp. and Anderson Energy Inc. announced an agreement to combine to create a new, Cardium-focused producer. InPlay also announced an agreement to acquire Cardium light oil assets in the Pembina region of Alberta from Bellatrix Exploration Ltd. for total consideration of $47 million, made up of $42 million cash, and 16.67 million shares of InPlay having a deemed value of $5 million (30 cents per share).
  • September 12, 2016 – Imperial Oil Limited announced that it will be seeking a buyer for its interest in the Norman Wells Oil Field in the Northwest Territories, though a definitive decision to sell the assets has not been made.
  • September 9, 2016 – Suncor Energy Inc. announced that it will issue an aggregate of $1 billion of senior unsecured Series 5 medium term notes. The offering will be conducted in two tranches consisting of $700 million of senior unsecured Series 5 medium term notes maturing on Sept. 14, 2026, and $300 million of senior unsecured Series 5 medium term notes maturing on Sept. 13, 2046.
  • September 9, 2016 – Crescent Point Energy Corp. entered into an agreement, on a bought deal basis, to sell 33.7 million common shares at $19.30 per share to raise gross proceeds of approximately CDN$650 million. Crescent Point increased its fourth quarter capital budget by $150 million, resulting in budgeted annual capital expenditures of $1.1 billion for 2016.

Unconventional

  • September 27, 2016 – the Government of Canada announced its approval, subject to conditions, of Progress Energy’s Pacific North West LNG project. The announcement was made at an evening press conference held in Richmond, British Columbia by federal Ministers Catherine McKenna (Environment), Jim Carr (Natural Resources), and Dominic LeBlanc (Fisheries, Oceans and the Canadian Coast Guard). PETRONAS, the parent company of Progress Energy, subsequently announced that it will be reviewing the project internally in light of the conditions to approval imposed by the federal government and prevailing market conditions.
  • September 19, 2016 – Seven Generations Energy Ltd. announced that it had entered into a development agreement with Steelhead LNG to explore infrastructure development and open new overseas markets for Canadian natural gas. 7G also acquired a minority ownership interest in Steelhead LNG.
  • September 16, 2016 – The Alberta government approved three new oilsands proposals: (a) the Blackpearl Resources Inc. Blackrod SAGD development; (b) the Surmont Energy Ltd. Wildwood oilsands SAGD development; and (c) the Husky Energy Inc. Saleski oilsands development. Collectively these projects represent about $4 billion of potential investment into Alberta’s economy and about 95,000 bbls per day of production.

Midstream

  • September 29, 2016 –Enbridge Inc. announced an agreement for the sale of liquids pipelines assets in the South Prairie Region to Tundra Energy Marketing Limited for $1.075 billion in cash. Closing of the transaction is expected to close in the fourth quarter of 2016.
  • September 26, 2016 – TransCanada Corporation announced that its wholly-owned subsidiary, Columbia Pipeline Group, Inc. has offered to acquire, for cash, all of the 53.84 million outstanding common units of the master limited partnership, Columbia Pipeline Partners, LP at a price of US$15.75 per common unit (aggregate US$848 million). This represents an 11.3 per cent premium to the 30-day average closing price on September 23, 2016.
  • September 7, 2016 – Veresen Inc. announced that Veresen Midstream secured CDN$650 million of new credit facilities, which will be primarily used to fund Veresen Midstream’s contracted capital projects under construction, including the Sunrise, Tower and Saturn processing facilities.
  • September 6, 2016 – Enbridge Inc. and Spectra Energy Corp. entered into a definitive merger agreement under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy common stock at approximately CDN$37 billion (US$28 billion), based on the closing price of Enbridge’s common shares on September 2, 2016. The combination will create the largest midstream energy company in North America and one of the largest globally based on a pro-forma enterprise value of approximately CDN$165 billion (US$127 billion). The transaction was unanimously approved by the boards of directors of both companies and is expected to close in the first quarter of 2017, subject to shareholder and certain regulatory approvals, and other customary conditions.
  • September 2, 2016 – Enbridge Inc. announced that its affiliate, Enbridge Energy Partners, L.P. (EEP), will defer its US$2.6 billion Sandpiper project in the Bakken and withdraw associated regulatory applications currently before the Minnesota Public Utilities Commission. EEP decided that the project should be delayed until crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity.

Alternative / Green

  • September 20, 2016 – In connection with Alberta’s Climate Leadership Plan, the provincial government announced the appointment of a task force to provide recommendations on government investment into “climate technology.” The appointees are: Gordon Lambert, chair; W.L. (Vic) Adamowicz; Shelly Vermillion; Suzanne West and Sara Hastings-Simon.
  • September 19, 2016 – Canadian Environment Minister Catherine McKenna announced that Canada will impose a carbon price on provinces that do not adequately regulate emissions by themselves. Details of this new carbon price and how it will be implemented have not yet been announced.
Significant Developments in Canadian Energy – For the Month of September 2016

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Due Diligence For Bankable Solar PV Projects

With Gillian Goldsworthy, Melanie Blanchard and Simon Mitchell

Sharp reductions in the price of solar PV technology, dramatic technological advancement and (until recently) generous subsidies for solar PV generation have enabled developers to project reliable and attractive revenues over the lifetime of a solar PV project (up to 35 -40 years). As such, in recent years, solar PV has become an increasingly appealing proposition to funders and has gained acceptance as a “bankable” technology.

Nevertheless, irrespective of the financing structure or size of the project, there are risks associated with the development of solar PV projects on which a funder will require comfort during its due diligence process. Therefore, it is essential that the developer works closely with the funder and provides access to a comprehensive suite of documentation and information.

This article provides an overview on the legal due diligence that, from a UK perspective, is a pre-requisite to the successful development of a financeable ground-mounted solar PV project and focuses on the real estate, planning, grid connection and corporate aspects of the due diligence process.

Property

Once a technically suitable site has been located property due diligence is required to establish whether development of the site is feasible from a legal perspective. In general, property due diligence investigations for a solar PV project will not be substantively different from those carried out for any major acquisition or pre-funding title investigation.

Searches

The first steps of a property due diligence exercise is to carry out searches at the Land Registry to ensure that all titles affecting the site are reported on. A funder will also expect local authority enquiries, an environmental search and standard utility enquiries to be raised. Highway Authority enquiries should also be conducted to ensure that the project has vehicular access to a public highway and (if there is an extended cable route) to identify where the cable crosses a highway, or is laid within it, so that it can be established whether the necessary consent has been obtained from the Highway Authority.

Some of the more interesting results of past property searches have included, unexploded ordinance, obsolete pipelines, incapacitated landowners, rights held by minors and sites subject to environmental risks such as flood risk and even nuclear contamination.

Third party rights

Ideally, the site on which the project is located should be free of encumbrances (such as the rights of utility operators to lay and operate their equipment). If encumbrances do exist, it will be necessary to ensure that the project is designed around them and that consents to the works have been obtained (if required).

If the site is affected by restrictive covenants which preclude solar PV (limitation to solely agricultural use can sometimes affect rural properties) then either a release needs be negotiated with the beneficiary of the covenant (if the beneficiary can be located), or defective title insurance must be put in place at a level which would fully compensate the project company for wasted capital costs and loss of future income arising from the project being decommissioned earlier than anticipated. The funder will also want to see that insurance is in place where a site is affected by rights to run service media in unidentified locations, or where mineral rights are excepted from the title.

Access

The site will also need to connect (directly or indirectly) to a public highway in order to ensure the right of vehicular access. Whilst direct access is preferable, a right of way over private land would also be acceptable to a funder, provided that there are no “gaps” in title between the highway and the site. If “gaps” do exist, then a funder will require insurance to be in place.

Right to connect to grid

In most cases, solar PV projects require the right to connect to the grid. Therefore a key part of the property due diligence is to check that both the site and project company have the rights to lay a cable to the point of connection to the grid. The point of connection may be on the site, in which case no separate investigations are needed. However, it is not unusual for the point of connection to be several kilometres away from the site. An essential first step is to find out if the cable/cable works have been adopted by the distribution network operator (DNO) (adoption usually occurs after the project has been commissioned). If the cable has been adopted by the DNO then a funder would not expect further cable route due diligence (other than reviewing the adoption arrangements). However, if the cable has not been adopted then full due diligence on it would be required, with the same title investigations, searches and planning due diligence as carried out for the site itself.

Lease

The operational life of a solar PV project can range between 25 and 40 years, depending on the technology used, the underlying rights held by the project and the project’s economics. It is normal for a 25 year lease to be granted, often with an option to renew for a further period of time if the project remains operational. In addition to standard commercial lease provisions, solar leases should require the landlord to grant any necessary easements or leases to the DNO and should permit the project company to share occupation of, or grant a substation lease to a DNO. The landlord should also covenant not to do anything which would obstruct sunlight from reaching the PV panels. Full rights to lay cables and access rights should be included and repair and restoration obligations should be relatively light. A funder will also require a direct agreement from the landlord to facilitate step-in where there is a project company in default. The lease should therefore also contain an express obligation upon the landlord to enter into a direct agreement where a funder requires one.

Planning

Planning can often be a sticking point at various stages of the development of a solar PV project, as the timing of planning decisions can be as unpredictable as the decision itself. From our experience, advanced preparation, transparency and openness with the local planning authority will often ensure a smoother process to a successful and financeable project.

In respect to planning, funders will require:

  • planning permission in respect of the PV plant which is clear from the risk of judicial review;
  • planning permission in respect of the cable route works which is clear from the risk of judicial review; and
  • all relevant conditions imposed on the permissions (in particular those required to be discharged prior to commencing works on site) to have been discharged.

Any proposed amendments to the scheme as approved by the planning permission should, if possible, be kept to a minimum and, in any case, the developer should apply for and obtain the consent of the local planning authority before any amendments on-site are undertaken. If the proposed amendment is non-material, as an alternative to the amendment process established under Section 73 of the Town and Country Planning Act 1990 which is used for material changes, the developer should seek to obtain a non-material amendment (NMA) of the planning permission, as the NMA process is usually simpler and quicker than under the Section 73.

Funders will want to see evidence that no enforcement action has been taken in relation to the project, and that the project has been constructed in accordance with the approved plans and conditions imposed on the permission.

Community benefit funding is often offered to community bodies to allow a share of benefits from the projects within the community. All offers should be charitable, open and transparent and in compliance with the applicable anti-bribery legislation (Bribery Act 2010). This is often evidenced by the local/parish council reporting all offers and payments made to their public meetings. One-off payments are, of course, easier for a developer to manage, but more often annual payments are agreed, whereby yearly payments for the life of the project are paid to the community body.  A funder will want to review these arrangements carefully to ensure that all arrangements are compliant with the Bribery Act 2010.

Grid connection

The basic aim of a solar PV project is to generate electricity in order to generate revenues from the sale of such electricity (in addition to any subsidies available for generation). Therefore, the ability to export electricity from the project to the power purchaser is crucial to the viability of the project.

The majority of solar PV projects are connected to the grid via an electricity distribution network operated by a DNO. The two key contracts between the project company and the DNO, which together govern the establishment and on-going connection to the DNO’s electricity distribution network, are the connection offer and, following connection of the project to the grid, the connection agreement.

Connection Offer

The main document relating to the establishment of the connection of the solar plant to the grid is the connection offer. Pursuant to Sections 16 and 17 of the Electricity Act 1989 (Act), DNOs are obliged to make an offer of connection to a “premises” (which includes a PV plant) when requested to do so by the “owner, occupier or a party acting on their behalf” (which includes a developer of a solar PV project).

Each connection offer will include information in relation to the connection including:

  • The export/import capacity offered.
  • The location of the point of connection.
  • A list of connection works which the DNO is obliged to carry out itself (known as non-contestable works).
  • A list of connection works that the DNO would be willing (but is not obliged) to carry out (known as contestable works). (The developer is free to arrange for an Independent Connection Provider to carry out these contestable works).
  • The cost of connection works.
  • The estimated connection date of the project.
  • Any assumptions that the connection offer is based on, including meeting certain construction milestones and obtaining all necessary third party consents within specified timeframes.

When reviewing the connection offer, the funder will require comfort on issues such as:

  • Whether the connection offer has been validly accepted within the required timeframe.
  • Whether the export/import capacity is sufficient for the project’s planned generation output.
  • Whether all of the connection costs due under the connection offer have been paid.
  • Whether the estimated date of connection is compatible with the project’s eligibility for accreditation under a particular subsidy regime and the revenue impact of missing the estimated date. This is a key issue, particularly in light of the recent significant curtailing of government support available under both the Renewable Obligation and Feed-in Tariff regimes. In such an environment, developers require expert regulatory support in order to navigate an ever-changing legal framework and to assess their eligibility for certain “grace periods”, which may allow the project to benefit from subsidy support after the subsidy has been formally closed.
  • What are the circumstances in which the DNO may unilaterally terminate the connection offer.
  • Are there any other bespoke or onerous features of the connection offer, including the offer being interactive with other connection offers, constraints in the distribution network, the requirement for the DNO to apply for Statement of Works with National Grid, or the obligation for the project company to provide security to the DNO?

Connection Agreement

Once a solar PV project has been commissioned (and thus connected to the grid), the connection offer largely falls away and is superseded by the connection agreement which governs the rights and obligations of the on-going grid connection. The connection agreement will usually incorporate the National Terms of Connection which are the standard terms and conditions setting out the basis on which the DNO will maintain the grid connection. Given the standard form nature of this document, the connection agreement will not generally be the subject of negotiation. However, the funder will be concerned to ensure that the connection agreement is in place for the duration of the financing and, in certain circumstances, will require the DNO to enter into a direct agreement in respect of the connection agreement or to take security over the connection agreement (which will require the consent of the DNO). Any departures from the National Terms of Connection will need to be explained and justified to the funder.

Corporate

The project company will be party to the lease, connection offer, connection agreement and other project documents (such as a power purchase agreement (PPA) and an Engineering, Procurement, and Construction contract (EPC)). It is also the entity to which the funder will lend (either directly or indirectly via a parent company). Therefore, the ownership, constitution and liabilities of the project company are of key concern to the funder. The principal areas of interest to the funder are:

  • Ownership of the project company’s share capital within the borrower group.
  • Encumbrances over the project company’s share capital (which may need to be removed as pre-condition to financing).
  • Encumbrances over the project company’s business and assets (which may need to be removed as a pre-condition to financing or financing).
  • Inter-company debt owed by the project company’s to the borrower group (which may need to be subordinated to the financing or financing debt).
  • The articles of association of the project company (which may need to be amended to remove any restriction on registration of transfer of shares on an enforcement of security, if the lender is take security over the project company’s share capital).
  • To ascertain if the project company’s has any liabilities (or assets) other than in connection with its solar project.
  • In addition, if there is to be a reorganisation of the project company’s share capital or an intra-group transfer of the project company in connection with the financing, corporate due diligence will cover a review of the relevant documentation and advise on the reorganisation.

Conclusion

This article has provided an overview of the real estate, planning, grid connection and corporate due diligence that funders will require. Legal advisors with experience in finding solutions to the issues unearthed by due diligence and who are able to anticipate funders’ requirements as well as to address their concerns are an integral part of the efficient development of a “bankable” solar PV project. It is important to note that the due diligence described in the article forms only part of the overall legal input, which will include the negotiation of “bankable” project contracts such as the PPA and EPC and advice in relation to the funder’s loan documentation.

Due Diligence For Bankable Solar PV Projects

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

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

Conventional

  • June 22, 2016 – In response to the Redwater decision (discussed below) and pending the outcome of an appeal, the Alberta Energy Regulator (AER) implemented interim changes to its regulatory measures “to minimize risks to Albertans.” Among these changes, the AER will require all transferees of existing well licenses to demonstrate that they have a liability management ratio (LMR) of 2.0 or higher immediately following the transfer. In response to industry concerns, the AER subsequently indicated that it will assess whether to implement the interim changes on a case-by-case basis. Additional Dentons commentary on the AER changes can be found here.
  • June 21, 2016 – Encana Corporation entered into an agreement to sell its Gordondale assets in northwestern Alberta to Birchcliff Energy Ltd. for a total cash consideration of C$625 million. The sale includes approximately 54,200 net acres of land and associated infrastructure.
  • June 17, 2016 – Longshore Resources Ltd. announced the closing of an acquisition of certain producing assets in the Peace River Arch area of Alberta and the closing of a $150 million equity financing by ARC Financial Corp.
  • June 13, 2016 – Penn West Petroleum Ltd. announced that it had entered into a definitive agreement for the sale of all of its Saskatchewan assets, including its Dodsland Viking area, for cash consideration of $975 million, subject to normal closing adjustments. The purchaser is Teine Energy Ltd., a Viking producer backed by the Canada Pension Plan Investment Board.
  • June 8, 2016 – Suncor Energy Inc. entered into an agreement to sell 71.5 million common shares from treasury, on a bought deal basis, at a price of $35 per share. Net proceeds will be used for the previously announced acquisition of an additional five per cent interest in the Syncrude Canada Ltd. oilsands joint venture and to reduce outstanding indebtedness.
  • June 3, 2016 – The Alberta Court of Queen’s Bench decision in the Redwater Energy Corp. sparked widespread debate regarding who pays for the remediation of Alberta’s orphan wells. At issue in the Redwater case was whether trustees managing insolvent oil companies may “cherry-pick” among a bankrupt producer’s oil and gas assets, selectively disclaiming properties, along with any attached environmental liability. Alberta Chief Justice Neil Wittmann ruled that insolvency trustees could ‘renounce’ assets. Dentons analysis of the Redwater case can be found here.
  • June 1, 2016 – Raging River Exploration Inc. and Rock Energy Inc. entered into an agreement for the acquisition by Raging River of all the issued and outstanding Rock common shares, pursuant to a plan of arrangement. Rock’s assets include 2,550 boe per day (95 per cent oil) of production and approximately 25 net sections of land prospective of Viking light oil in the Kerrobert area of southwest Saskatchewan. Through this transaction, Raging River is also acquiring interests in heavy oil assets at Mantario (Laporte) and Onward, both in southwest Saskatchewan.

Unconventional

  • June 20, 2016 – Athabasca Oil Corporation granted a contingent bitumen royalty to Burgess Energy Holdings LLC on its thermal assets for total consideration of $129 million. Concurrently, the company repaid its US$221 million first lien term loan.
  • June 16, 2016 – Bear Head LNG Corporation, Inc. has received Governor in Council approval for a licence to import natural gas from the United States and a licence to export LNG from its project site on the Strait of Canso in Richmond County, Nova Scotia. The National Energy Board’s approval was previously issued in August 2015, but was subject to the approval of the Governor in Council.

Midstream

  • June 14, 2016 – TransCanada Corporation announced that its joint venture with IEnova, Infraestructura Marina del Golfo (IMG) has been chosen to build, own and operate the US$2.1-billion Sur de Texas-Tuxpan natural gas pipeline in Mexico. The project will be supported by a 25-year natural gas transportation service contract for 2.6 bcf a day with Mexico’s state-owned power company, the Comisión Federal de Electricidad.
  • June 2, 2016 – The National Energy Board recommended that the federal government approve NOVA Gas Transmission Ltd.’s (NGTL) proposed expansion to its existing system in northern Alberta. The board’s final report, released Wednesday, lists 48 conditions that NGTL would have to meet should the project go ahead. On March 31, 2015, NGTL applied to the board to construct and operate approximately 230 kilometres of pipeline in five pipeline section loops and two compressor station unit additions in northern Alberta, mostly adjacent to existing sites. The total estimated cost of the project is $1.29 billion and the planned in-service date is April 1, 2017.

Off-Shore

  • June 10, 2016 – Statoil completed the drilling of nine wells using the Seadrill West Hercules in the Flemish Pass Basin. The drilling program included four exploration wells in the vicinity of the 2013 Bay du Nord discovery, as well as three appraisal wells on the discovery. In addition, two exploration wells were drilled in areas outside the Bay du Nord discovery.
  • June 8, 2016 – Royal Dutch Shell plc has voluntarily contributed more than 860,000 hectares of offshore exploratory permits in the waters of Baffin Bay, near Lancaster Sound, to the Nature Conservancy of Canada. This contribution will support the establishment of a national marine conservation area off the coast of Nunavut. The Nature Conservancy of Canada subsequently released the permits to the Government of Canada. A government moratorium on oil and gas activity has been in place for nearly 40 years in the Lancaster Sound and Baffin Bay regions and Shell had not conducted any exploration activities on these lands during that period.

Alternative / Green

  • The federal government’s 2016 budget provided $50 million over two years to support the development of clean technologies for Canada’s oil and gas sector. Natural Resources Minister Jim Carr announced this week that the government is seeking proposals to access the Oil and Gas Clean Tech Program. Projects selected under the fund will demonstrate industry-led clean technologies that, once commercialized, could be more widely adopted across the oil and gas industry to improve environmental performance and help reduce greenhouse gas emissions both domestically and globally.
Significant developments in Canadian energy – for the month of June 2016

Significant Developments in Canadian Energy – For the month of April 2016

Conventional

  • April 21, 2016 – The Alberta government announced the technical formulas that will be used to calculate royalties and payout cost allowances on oil, natural gas, propane and butane starting in 2017. Discussion of these formulas can be found in our article of April 27, 2016.
  • April 18, 2016 – Penn West Petroleum Ltd. closed the previously announced sale of its properties in the Slave Point area of northern Alberta for cash consideration of CDN$148 million. In addition, Penn West closed approximately CDN$50 million of its previously announced non-core asset sales of CDN$80 million. It has also entered into a definitive agreement to sell the balance of such non-core assets for cash consideration of CDN$30 million, subject to closing adjustments. The sale is expected to close in the second quarter.
  • April 12, 2016 – Enerplus Corporation entered into a definitive agreement to sell certain non-core assets located in northwest Alberta, including its Pouce Coupe asset. The total cash consideration is CDN$95.5 million, subject to closing adjustments, and the transaction is expected to close in the second quarter of 2016. Enerplus has used its 2016 divestment proceeds, which will total CDN$288.5 million, to reduce its outstanding debt, including repurchasing a portion of its senior unsecured notes.

Unconventional

  • April 27, 2016 – Suncor Energy Inc. announced that it will acquire a further 5% interest in Syncrude Canada Ltd. from Murphy Oil Corporation’s Canadian subsidiary for a purchase price of CDN$937 million, subject to closing adjustments. Through this transaction, Suncor’s share in Syncrude will increase from 48.74% to 53.74% (36.74% of which is held through Suncor’s interest in Canadian Oil Sands Limited). The transaction remains subject to closing conditions, including regulatory approval under the Canadian Competition Act and is expected to close in the second quarter of 2016. The remaining ownership interests of Syncrude will continue to be held by Imperial Oil (25%), Sinopec Limited (9%), Nexen Inc. (7.23%), and Mocal Energy (5%). Suncor indicated that it does not intend to become the operator of Syncrude.

Midstream

  • April 25, 2016 – Husky announced that it has reached an agreement to sell 65% of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan to Cheung Kong Infrastructure Holdings Limited and Power Assets Holdings Limited. Husky will receive CDN$1.7 billion of gross cash proceeds, will retain a 35% ownership interest, and will remain operator. The sale price represents about 13 times the expected 2016 EBITDA of approximately CDN$180 million.
  • April 20, 2016 – TransCanada Corporation completed its public offering of cumulative redeemable minimum rate reset first preferred shares, Series 13. TransCanada issued 20 million Series 13 preferred shares for aggregate gross proceeds of CDN$500 million through a syndicate of underwriters co-led by TD Securities Inc., BMO Capital Markets and Scotiabank. Net proceeds of the offering will be used for general corporate purposes and to reduce short-term indebtedness of TransCanada and its affiliates.
  • April 11, 2016 – Pembina Pipeline Corporation and Petrochemical Industries Company K.S.C., a subsidiary of the Kuwait Petroleum Corporation, announced their participation in a joint study for the evaluation of a world-scale combined propane dehydrogenation (PDH) and polypropylene upgrading facility in Alberta. The project could consume approximately 35,000 bbls per day of propane and produce up to 800,000 metric tonnes per year of polypropylene. This announcement follows the adoption by the Alberta government of the Petrochemicals Diversification Program, the intent of which is to encourage the construction of such facilities in Alberta, and which is discussed in our blog post of March 2, 2016.
  • April 11, 2016 – TransCanada Corporation announced that it was awarded a contract to build, own and operate the USD$550 million Tula – Villa de Reyes natural gas pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 mmcf a day with the Comisión Federal de Electricidad, Mexico’s state-owned power company.
  • April 1, 2016 – TransCanada Corporation completed its previously announced bought deal offering of subscription receipts. The total gross proceeds of $4.4 billion will be used to finance a portion of the purchase price of the previously announced acquisition of Columbia Pipeline Group, Inc.

Off-Shore

  • April 7, 2016 – the Canada-Newfoundland & Labrador Offshore Petroleum Board announced two Calls for Bids for 2016 comprising thirteen parcels (totaling 2,949,252 hectares) in the Eastern Newfoundland Region and three parcels (totaling 354,552 hectares) in the Jeanne d’Arc Region. The deadline for the 2016 Bid Round is November 9, 2016 and as in previous rounds, the sole bid selection criteria will be the size of the work commitment that is bid. This follows the successful conclusion of last year’s Call for Bids, which resulted in companies bidding over CDN$1 billion in work commitments in respect of 11 parcels totaling 2,581,655 hectares.

Oilfield Services

  • Hallmark Tubulars Ltd. announced the acquisition of two tubular running services businesses in Western Canada: Canarctic Inc., based out of Vermillion and Davy Crockett’s Oilfield Services Ltd., based out of Valleyview. These acquisitions are anticipated to augment Hallmark’s existing tubular running operations in Nisku and Bonnyville through the addition of all the employees of both companies, an enlarged equipment fleet and expanded geographic coverage.
  • April 5, 2016 – Sanjel Corporation announced that it had signed two agreements for the sale of assets to two separate North American pressure pumping providers. Sanjel announced a definitive agreement for the sale of its Canadian fracturing, coiled tubing and cementing assets to STEP Energy Services Ltd., an ARC Financial Corp. sponsored company. Concurrently, Sanjel signed a definitive agreement for the sale of its United States fracturing, coiled tubing and cementing assets to Liberty Oilfield Services.

Alternative / Green

  • April 1, 2016 – Enbridge Inc. announced its updated climate policy, which includes: commitments to develop multi-year plans for emissions reduction and energy efficiency in its business segments; building on the $5 billion Enbridge has already invested in renewable energy to double renewable energy generation capacity in five years; and investing in programs that will enable its residential and commercial natural gas customers to reduce energy use, emissions and costs. Enbridge has committed to providing an annual review of its progress in achieving its policy commitments.
Significant Developments in Canadian Energy – For the month of April 2016